EA045677B1 - OPTIMIZED PLACEMENT OF VIBRATION DAMPING MEANS DUE TO ADJUSTMENT OF VIBRATION SHAPE - Google Patents

Description

Cross-reference to related application

This application claims the benefit of U.S. Provisional Application Serial No. 62/899,354 filed September 12, 2019, U.S. Provisional Application Serial No. 62/899,291 filed September 12, 2019, U.S. Provisional Application Serial No. 62/899,331 filed in September. 12, 2019, and U.S. Provisional Application Serial No. 62/899,332, filed September 12, 2019, the entire disclosure of which is incorporated herein by reference.

Prerequisites for creating the invention

1. Scope of the invention.

The present invention generally relates to downhole operations and systems for damping vibrations of downhole systems during operation.

2. Description of the prior art.

Wells are drilled deep into the earth's crust to achieve many purposes, such as carbon dioxide sequestration, geothermal exploration and development, and hydrocarbon exploration and production. In all cases, well bores are drilled to access or pass through a location of material (such as gas or liquid) contained in a formation (such as a reservoir) located below the earth's surface. Wellbores can house different types of tools and devices to perform different tasks and measurements.

During operation, downhole components may be subject to vibration, which can affect their performance. For example, severe vibrations in drill strings and bottom hole assemblies (BHAs) can be caused by cutting forces at the bit or mass imbalances in downhole tools such as mud motors. The effects of such vibrations may include, but are not limited to, reduced penetration rates, reduced measurement quality, and excessive fatigue and wear on downhole components, tools and/or devices.

Summary of the invention

Disclosed herein are systems and methods for damping vibrations, such as torsional vibrations, in downhole systems. The systems include a downhole system rotatable within the wellbore and a damping system provided on the downhole system. The damping system includes one or more dampers that are mounted near or on a drill bit or other downhole system disruption device. The dampers are configured to reduce or eliminate one or more specific modes and thus improved well performance and/or greater efficiency can be achieved.

In accordance with some embodiments, systems are provided for damping torsional vibrations of downhole systems. These systems include a drilling system containing a BHA located at the end of the drill string, at least one vibration shape adjustment element located on the drilling system, and said at least one vibration shape adjustment element is configured to shift the maximum mode of high-frequency torsional vibrations (HFTO), and a damping system made as part of the drilling system, wherein said damping system contains at least one damping element located in an offset maximum position.

In some embodiments, methods are provided for damping torsional vibrations of wellbore systems in a wellbore. These methods include installing on the drilling system at least one mode adjustment element, wherein the said drilling system includes a drill string and a BHA, wherein the at least one mode adjustment element is configured to shift the position of the maximum of the high-frequency torsional vibration mode (HFTO) ) of the drilling system and installing a damping system on the drilling system, wherein said damping system contains at least one damping element located in an offset maximum position.

Brief description of graphic materials

The subject matter of the invention, which is considered as the present invention, is particularly indicated and expressly stated in the claims at the end of this specification. The foregoing and other features and advantages of the present invention will be apparent from the following detailed description taken in conjunction with the accompanying drawings, like elements designated by like reference numerals, wherein:

in fig. 1 illustrates an example of a well system to which embodiments of the present invention may be employed;

in fig. 2 is an illustrative graph of a typical friction or torque curve versus relative speed or relative rotational speed between two interacting objects;

in fig. Figure 3 shows a hysteresis plot of friction force versus displacement for a positive relative average speed with additional small changes in speed;

- 1 045677 in Fig. 4 is a graph of friction force, relative speed, and the product of both versus time for a positive relative average speed with additional small changes in speed;

in fig. Figure 5 shows a hysteresis plot of friction force versus displacement for a relative average speed of zero with additional small changes in speed;

in fig. 6 shows a graph of friction force, relative speed and the product of both for a relative average speed of zero with additional small changes in speed;

in fig. 7 is a schematic illustration of a damping system in accordance with one embodiment of the present invention;

in fig. 8A is a graph of tangential acceleration measured at a drill bit;

in fig. 8B is a graph corresponding to FIG. 8A illustrating rotation speed;

in fig. 9A is a schematic diagram of a well system showing the shape of the well system as a function of distance from the bit;

in fig. 9B illustrates exemplary corresponding torsional vibration modes that may be generated during operation of the wellbore system shown in FIG. 9A;

in fig. 10 is a schematic illustration of a damping system in accordance with one embodiment of the present invention;

in fig. 11 is a schematic diagram of a damping system in accordance with one embodiment of the present invention;

in fig. 12 is a schematic diagram of a damping system in accordance with one embodiment of the present invention;

in fig. 13 is a schematic diagram of a damping system in accordance with one embodiment of the present invention;

in fig. 14 is a schematic diagram of a damping system in accordance with one embodiment of the present invention;

in fig. 15 is a schematic diagram of a damping system in accordance with one embodiment of the present invention;

in fig. 16 is a schematic diagram of a damping system in accordance with one embodiment of the present invention;

in fig. 17 is a schematic diagram of a damping system in accordance with one embodiment of the present invention;

in fig. 18 is a schematic diagram of a damping system in accordance with one embodiment of the present invention;

in fig. 19 is a schematic illustration of a damping system in accordance with one embodiment of the present invention; and in fig. 20 is a schematic graph of the dependence of the vibration damping coefficient on the amplitude of local vibration;

in fig. 21 is a schematic representation of a downhole tool having a damping system;

in fig. 22 is a cross-sectional view of the downhole tool shown in FIG. 21;

in fig. 23 is a set of graphs illustrating the mode shapes of various BHAs and the normalized damping for a damper in accordance with an embodiment of the present invention;

in fig. 24A-C are schematic illustrations of the placement of a single damper element in a wellbore in accordance with embodiments of the present invention;

in fig. 25 is a set of graphs illustrating the mode shapes of various BHAs and the normalized damping for a damper in accordance with an embodiment of the present invention;

in fig. 26A is a schematic view of a well string having waveform control elements and a damper element installed thereon in accordance with an embodiment of the present invention;

in fig. 26B illustrates waveforms modified or tuned by incorporating waveform tuning elements in accordance with an embodiment of the present invention;

in fig. 27 is a schematic diagram of a tangential damper element in accordance with one embodiment of the present invention;

in fig. 28 is a schematic diagram of a tangential damper element in accordance with one embodiment of the present invention;

in fig. 29A is a schematic diagram of examples of waveform tuning elements in accordance with one embodiment of the present invention; and in fig. 29B is a schematic representation of examples of a well string assembly having waveform adjustment elements and a sub with a damper element in accordance with

- 2 045677 embodiment of the present invention.

Detailed description

In fig. Figure 1 shows a schematic diagram of the system for performing well work. As shown, the system is a drilling system 10 that includes a drill string 20 having a drilling assembly 90, also referred to as a bottom hole assembly (BHA), transported in a wellbore 26 penetrating the earth formation 60. The drilling system 10 includes a conventional drilling rig. 11 mounted on a platform 12 which supports a rotor table 14 which is rotated by a main drive such as an electric motor (not shown) at a desired rotation speed. The drill string 20 includes a drill tubular member 22, such as a drill pipe extending downward from the rotor table 14 into the wellbore 26. A disintegration device 50, such as a drill bit (or simply a bit), attached to the end of the BHA 90, when rotated, breaks up the geological formations to drill the wellbore 26. The drill string 20 is connected to surface equipment, such as lifting, rotating and/or pushing systems, including, but not limited to, the drawworks 30 via a kelly 21, a swivel 28, and a line 29 via a lifting block 23. In some embodiments, the surface equipment may include a top drive (not shown). During drilling operations, the drawworks 30 is controlled to control the load on the bit, which affects the drilling rate of penetration. The operation of winch 30 is well known in the art and therefore is not described in detail herein.

During drilling operations, suitable drilling fluid 31 (also called drilling fluid) from a mud source or reservoir 32 is circulated under pressure through the drill string 20 by a mud pump 34. The drilling fluid 31 passes into the drill string 20 through the hydraulic shock absorber 36, the fluid line 38 and the kelly rod 21. The drilling fluid 31 is discharged in the bottom hole assembly 51 through an opening in the disintegration device 50. The drilling fluid 31 circulates up the wellbore through the annulus 27 between the drill string 20 and the wellbore 26 and returns to the drilling fluid reservoir 32 through the return line 35. A sensor S1 in the fluid line 38 provides fluid flow information. A surface torque sensor S2 and a surface torque sensor S3 associated with the drill string 20 respectively provide information about the torque and rotational speed of the drill string. In addition, one or more sensors (not shown) associated with line 29 are used to provide a load on the hook of the drill string 20 and other desired parameters related to drilling the wellbore 26. The system may further include one or more downhole sensors 70 located on the drill string 20 and/or BHA 90.

In some applications, the disintegrator 50 is rotated only by rotating the drill pipe 22. However, in other applications, a drilling motor 55 (e.g., a mud motor) located in the drilling assembly 90 is used to rotate the disintegrator 50 and/or to superimpose or complement the rotation drill string 20. In any case, the rate of penetration (ROP) of the disintegration device 50 into the earth formation 60 for a given formation and a given drilling assembly is largely dependent on the weight on bit and the rotational speed of the drill bit. In one aspect of the embodiment shown in FIG. 1, the drilling motor 55 is coupled to the disintegrator 50 via a drive shaft (not shown) located in the bearing assembly 57. The drilling motor 55 rotates the disintegrator 50 as drilling fluid 31 passes through the drilling motor 55 under pressure. The bearing assembly 57 supports the radial and axial forces of the disintegration device 50, the thrust drop of the drilling motor, and the upward reaction load from the applied weight on the bit. The stabilizers 58, coupled to the bearing assembly 57 and/or other suitable positions, act as centralizers for the drilling assembly 90 or parts thereof.

Surface control unit 40 receives signals from downhole sensors 70 and devices through a transducer 43, such as a pressure transducer located in fluid line 38, as well as from sensors S1, S2, S3, hook load sensors, engine speed sensors, torque sensors, and any other sensors used in the system, and processes such signals in accordance with programmed commands provided to the ground control unit 40. The surface control unit 40 displays required drilling parameters and other information on a display/monitor 42 for use by an operator at the well site to control drilling operations. The ground control unit 40 includes a computer, a data storage device, computer programs, models and algorithms accessible to a processor on the computer, a recording device such as a tape drive, a memory unit, etc. for data logging and other peripheral devices. The ground control unit 40 may also include simulation models for computer processing of data in accordance with programmed commands. The control unit responds to user commands entered through a suitable device such as a keyboard. The ground control unit 40 is configured to activate warning signals 44

- 3 045677 when certain unsafe or undesirable operating conditions occur.

The drilling assembly 90 also includes other sensors and devices or tools to provide various measurements related to the formation surrounding the wellbore and to drill the wellbore 26 along a desired path. Such devices may include a device for measuring formation resistivity near the drill bit, gamma ray logging devices for measuring gamma ray intensity of the formation, and devices for determining the inclination, azimuth and position of and/or in front of the drill string. A formation resistivity logging tool 64 fabricated in accordance with the embodiment described herein may be attached at any suitable position, including above the lower deflection initiation subassembly 62, to estimate or determine formation resistivity adjacent to or in front of the disintegrator 50 or in other suitable positions. An inclinometer 74 and a gamma ray logging device 76 may be positioned respectively to determine the BHA inclination and gamma ray intensity of the formation. Any suitable inclinometer and gamma ray logging device can be used. Additionally, an azimuth device (not shown), such as a magnetometer or gyroscopic device, can be used to determine the azimuth of the drill string. Such devices are known in the art and therefore are not described in detail herein. In the above-described exemplary configuration, the drilling motor 55 transmits electrical power to the disintegrator 50 through a shaft that also allows drilling fluid to flow from the drilling motor 55 to the disintegrator 50. In an alternative embodiment of the drill string 20, the drill motor 55 may be coupled below the resistivity logging device 64 or at any other suitable position.

As shown in FIG. 1, other logging-while-drilling (LWD) devices (generally designated herein by reference numeral 77), such as devices for measuring formation porosity, permeability, density, rock properties, fluid properties, etc., may be placed at suitable positions of the drilling assembly 90 to provide information useful for evaluating the subterranean formation along the wellbore 26. Such devices may include, but are not limited to, temperature measuring instruments, pressure measuring instruments, borehole diameter measuring instruments (e.g., caliper), acoustic instruments, radioactive logging instruments, nuclear magnetic resonance instruments, and formation testing instruments. and sampling.

The above devices transmit data to the downhole telemetry system 72, which in turn transmits the received data up the wellbore to the surface control unit 40. The downhole telemetry system 72 also receives signals and data from the surface control unit 40 and transmits such received signals and data to the corresponding downhole devices. In one aspect, a mud-pulse telemetry system may be used to transmit data between downhole sensors 70 and devices and surface equipment during drilling operations. Transducer 43, located in fluid line 38 (eg, a drilling fluid line), detects pulses in the drilling fluid in response to data transmitted by downhole telemetry system 72. Transducer 43 generates electrical signals in response to changes in downhole fluid pressure and transmits such signals through conductor 45 to ground control unit 40. In other aspects, any other suitable telemetry system, including, but not limited to, an acoustic telemetry system, an electromagnetic telemetry system, an optical telemetry system, an wired telemetry, which may use wireless couplers or repeaters located in the drill string or wellbore. A wireline telemetry system may be formed by connecting sections of drill pipe, with each section of pipe including a data line, such as a wire, running along the pipe. The data connection between pipe sections may be made by any suitable method, including, but not limited to, solid electrical or optical coupling, inductive coupling, capacitive coupling, resonant coupling, such as electromagnetic resonant coupling or directional coupling techniques. In the case where coiled tubing is used as the drill pipe 22, a data line may be run along the side of the coiled tubing.

The drilling system described thus far herein refers to drilling systems that use a drill pipe to transport the drilling assembly 90 into the wellbore 26, with the weight on bit being controlled from the surface, typically by operating a drawworks. However, a large number of modern drilling systems, especially for drilling highly inclined and horizontal wellbores, use coiled tubing strings to transport the drilling assembly into the wellbore. In such an application, a mover is sometimes deployed in the drill string to provide the required force on the drill bit. Additionally, when coiled tubing is used, the tubing is not rotated by the rotor table, but is instead driven into the wellbore by a suitable blower while the downhole motor, such as the drilling motor 55, rotates the disintegrator 50. In offshore drilling, an offshore drilling rig or vessel is used to support drilling equipment, including the drill string.

Also with reference to FIG. 1, a resistivity logging tool 64 may be provided including, for example, a plurality of antennas including, for example, transmitters 66a or 66b and/or receivers 68a or 68b. Resistivity may be one of the formation properties of interest when making a drilling decision. Those skilled in the art will appreciate that other tools may be used in conjunction with or instead of the resistivity logging tool 64 to measure formation properties.

Liner drilling can be a single configuration or operation used to provide a disintegration device, which is becoming more attractive in the oil and gas industry as it has several advantages over conventional drilling. One example of such a configuration is shown and described in United States Cooperative Patent No. 9,004,195, entitled Apparatus and Method for Drilling a Wellbore, Installing Casing, and Cementing the Wellbore in a Single Run, which is incorporated herein by reference in its entirety. It is important to note that despite the relatively low rate of penetration when drilling, the time to deliver the liner to the target position is reduced because the liner is simultaneously lowered into the hole while the wellbore is being drilled. This can be useful when working in swelling formations, where the narrowing of the drilled hole may interfere with the subsequent installation of casing. Additionally, drilling with casing in depleted and unstable reservoirs minimizes the risk of stuck pipe or drill string due to wellbore collapse.

Although fig. 1 is shown and described in relation to drilling operations, those skilled in the art will appreciate that similar configurations, although using different components, can be used to perform a variety of downhole operations. For example, wireline, wireline, liner drilling, reaming, coiled tubing, and/or other configurations may be used in the art. In addition, various production configurations can be used to extract and/or inject materials from/into geological formations. Thus, the present description should not be limited to drilling operations, but can be used for any suitable or desired downhole intervention.

Intense vibrations in drill strings and bottom hole assemblies during drilling operations can be caused by cutting forces on the drill bit or mass imbalances in downhole tools such as drilling motors. Such vibrations can reduce drilling rates of penetration, reduce the quality of measurements taken by bottomhole assembly tools, and can lead to wear, fatigue and/or failure of downhole components. As will be understood by those skilled in the art, there are various vibrations, such as transverse vibrations, axial vibrations and torsional vibrations. For example, stick-slip motion of the entire drilling system and high-frequency torsional vibration (HFTO) are types of torsional vibration. The terms vibration, oscillation, and unevenness refer to repetitive and/or periodic movements or periodic deviations from an average value, such as average position, average speed, average acceleration, average force, and/or average torque. In particular, these terms are not limited to harmonic deviations, but can include all types of deviations, such as, but not limited to, periodic, harmonic and statistical deviations. Torsional vibrations can be generated by self-excitation mechanisms that arise from the interaction of the drill bit or any other cutting structure, such as a reamer bit, and the formation. The main difference between low-frequency torsional vibrations (such as stick-slip) and HFTO is the frequency and type of vibration. For example, VCCs have frequencies typically greater than 50 Hz compared to low-frequency torsional vibrations, which typically have frequencies below 1 Hz. In addition, the excited mode of low-frequency torsional vibration or stick-slip typically represents the first mode of the entire drilling system, while the ISC mode can be higher and is usually limited to smaller parts of the drilling system with relatively high amplitudes at a point excitation, which may be the drill bit or any other cutting structure (eg, a reamer) or any contact between the drilling system and the formation (eg, a stabilizer).

Due to the high vibration frequency, the HFTO corresponds to high acceleration and torque values along the BHA. Those skilled in the art will appreciate that for torsional movements to occur, one component of acceleration, force, and torque is always accompanied by the other two components of acceleration, force, and torque. In this sense, acceleration, force and torque are equivalent in the sense that none of these elements can occur without the other two. Stresses in the form of high-frequency vibrations or oscillations can adversely affect the efficiency, reliability and/or durability of the electronic and mechanical parts of the BHA. The embodiments proposed herein relate to providing damping

- 5 045677 torsional vibration on downhole system to mitigate HFTO. In some embodiments of the present invention, torsional vibration may be activated if the system reaches a threshold of a measured property, such as amplitude or frequency of torsional vibration.

In accordance with a non-limiting embodiment proposed herein, a vibration damper or, in the context of the present invention, simply a damper, also called a damping system, for example, a torsional vibration damping system, may be friction based. For example, in accordance with some embodiments, said damper may comprise one or more damper elements that may be included in a damper element sub. Friction between two parts within the damper element, such as two interacting objects within the damper element, can dissipate energy and reduce the level of torsional vibration, thereby reducing the potential damage caused by high frequency vibrations. Preferably, the damper energy dissipation is at least equal to the input amount of HFTO energy caused by the bit-formation interaction.

The friction dampers described herein can result in significant energy dissipation and thus mitigate torsional vibrations. When two components or interacting objects are in contact with each other and are moving relative to each other, the frictional force acts in the direction opposite to the speed of relative movement between the contacting surfaces of the components or interacting objects. The friction force leads to energy dissipation.

In fig. 2 is an illustrative graph 200 of a typical friction or torque versus relative velocity v (eg, or relative rotational speed) curve between two interacting objects. The two interacting objects have a contact surface and a force component FN perpendicular to the contact surface in engagement with the two interacting objects. Plot 200 shows the frictional force or torque of two interacting objects as a function of speed reduction behavior (eg, frictional contact or cutting characteristic). At higher relative speeds (ν > 0) between two interacting objects, the friction force or torque has a distinctive value, shown by point 202. A decrease in the relative speed will result in an increase in the friction force or torque (also called the speed reduction characteristic). The frictional force or torque reaches its maximum when the relative speed is zero. Maximum frictional force is also known as static friction, sticking friction or adhesion.

Essentially, the friction force F _R depends on the normal force, as described in the equation F _R = μ FN, with a coefficient of friction μ. Essentially, the coefficient of friction μ is a function of speed. Herein, the normal force may also change in accordance with the excited vibration in the normal direction. In case the relative velocity between two interacting objects is zero (ν = 0), the static friction force FS is related to the normal force component FN according to the equation FS = μ ₀ FN with the static friction coefficient μ0. In case the relative speed between two interacting objects is not zero (ν^0), such a coefficient of friction is known as the coefficient of dynamic friction μ. If the relative speed is further reduced to negative values (i.e., if the relative motion of the two interacting objects is reversed), the frictional force or torque is switched in the opposite direction with a high absolute value corresponding to the stage from a positive maximum to a negative minimum value at point 204 in graph 200. Thus, the frictional force versus speed relationship shows a sign change at the point at which the speed changes sign and is discontinuous at point 204 in graph 200. The velocity reduction characteristic is a well-known effect between interacting objects that are frictionally coupled . The velocity reduction characteristics of contact force or torque are hypothesized to be a potential root cause of sticking/slipping. Velocity reduction characteristics can also be achieved by using a dispersion fluid with a higher viscosity at lower relative speeds and a lower viscosity at higher relative speeds. If the dispersive fluid passes through a relatively small channel, then the same effect can be achieved in the sense that the flow resistance is relatively high or low at low or high relative velocities, respectively.

With reference to FIG. 8A, B, in Fig. 8A shows the measured swirl acceleration of the well system as a function of time. During the 5 second measurement, as shown in FIG. 8A shows vibrational twist acceleration with an average acceleration of approximately 0 g superimposed on vibrational twist acceleration at relatively low amplitudes from about 0 s to 3 s and relatively high amplitudes up to 100 g from about 3 s to 5 s. In fig. 8B shows the corresponding rotation speed in the same period of time as in FIG. 8A. According to FIG. 8A, FIG. 8B shows the average speed ν ₀ (shown by the ν ₀ line in FIG. 8B) which is relatively constant at a rotation speed of about 190 rpm. Superimposed on the average speed are rotational speed oscillatory vibrations with relatively low amplitudes from approximately 0 s to 3 s and relatively high amplitudes from approximately 3 s to 5 s, consistent with the relatively low and high acceleration amplitudes shown in FIG. 8A. It is noteworthy that the oscillatory rotation speed does not lead to negative rotation speed values, not even during the time period of approximately 3 s to 5 s, when the amplitudes of the oscillation speeds are relatively high.

Once again with reference to FIG. 2, point 202 illustrates the average speed of two interacting objects, which corresponds to the average speed ν ₀ in FIG. 8B. In the schematic diagram in FIG. 2 data shown in FIG. 8B correspond to a point where the speed oscillates at a relatively high frequency due to HTFO around an average speed ν ₀ which changes relatively slowly with time compared to HFTO. Thus, the point illustrating the data shown in FIG. 8B moves back and forth on the positive leg of the curve shown in FIG. 2, only rarely reaching negative speed values or in their absence. Accordingly, the corresponding frictional force or torque oscillates around a positive average frictional force or average frictional torque and is usually substantially positive or only rarely reaches negative values. As further discussed below, point 202 illustrates where a positive average relative speed corresponds to static torque, and point 204 illustrates the sweet spot for frictional damping. It should be noted that frictional forces or torque between the drilling system and the borehole wall will not generate additional damping of high frequency vibrations in the system. This is because the relative velocity between the contact surfaces of the interacting objects (such as the stabilizer and the borehole wall) does not have an average velocity, which is so close to zero that HFTO causes the relative velocity of the two interacting objects to change sign. Rather, the relative velocity between the two interacting objects has a high average value at a distance from zero that is large such that HFTO does not cause the relative velocity of the two interacting objects to change sign (eg, as illustrated by point 202 in FIG. 2).

Those skilled in the art will appreciate that the reduced contact force or torque versus relative speed characteristic as shown in FIG. 2, leads to the use of energy in the system for oscillatory relative movements of interacting objects with an average speed ν ₀ , i.e. high value compared to the speed of oscillatory movement. In this context, other examples of self-excitation mechanisms, such as coupling between axial and torsional degrees of freedom, may lead to a similar performance.

The corresponding hysteresis graph is shown in Fig. 3, and the time graph for friction force and speed is shown in FIG. 4. In FIG. Figure 3 shows a hysteresis plot of friction force F _r , sometimes also called cutting force in this context, versus displacement relative to a position that moves at a positive average speed with additional small changes in speed resulting in an additional small displacement dx.

Accordingly, in FIG. 4 shows the friction force (F _r ), relative speed

and the product of both (indicated by reference numeral 400 in FIG. 4) for a positive average relative velocity with additional small changes in velocity, resulting in an additional small offset dx. Those skilled in the art will recognize that the area between frictional force and velocity over time is equal to the energy dissipated (ie, the area between line 400 and the zero axis), which is negative in the case shown in FIG. 3 and fig. 4. Thus, in the case shown in FIG. 3 and fig. 4, energy is transferred to vibration from friction through frictional contact.

Again with reference to FIG. 2, point 204 denotes a favorable average speed for friction damping small speed changes or vibrations in addition to the average speed. For small vibrations of relative motion between two interacting objects, stopping at point 204 in FIG. 2 with a change in the sign of the relative speed of interacting objects also leads to a sharp change in the friction force or torque. This change in sign results in hysteresis, which results in a large amount of dissipated energy. For example, one can compare FIG. 5 and fig. 6, which are similar graphs to FIG. 3 and fig. 4 respectively, but illustrate the case of zero average relative speed with additional small speed changes or vibrations.

The area below the 600 line in FIG. 6, which corresponds to the product „ dx Г _г —. ' άτ

- 7 045677 is equal to the dissipated energy during one period and, in this case, is positive. Thus, in the case shown in FIG. 5 and fig. 6, energy is transferred from high frequency vibration through frictional contact into friction. The effect is comparatively high compared to the case shown in FIG. 3 and fig. 4, and has the required sign. From the comparison of Fig. 2, 5 and 6 also show that the dissipated energy depends significantly on the difference between the maximum frictional force and the minimum frictional force for ν = 0 (i.e., position 204 in Fig. 2). The higher the difference between the maximum friction force and the minimum friction force for ν = 0, the higher the dissipated energy. Although in FIG. 3-4, speed reduction characteristics such as those shown in FIG. 2, embodiments of the present invention are not limited to this type of characteristics. The devices and methods described herein will be functional for any type of response as long as the frictional force or torque undergoes a sign-changing phase as the relative velocity between the two interacting objects changes.

Friction dampers in accordance with some embodiments of the present invention will now be described. Friction dampers are mounted on or in a drilling system, such as the drilling system 10 shown in FIG. 1, and/or portions of the drilling system 10, such as a portion of the bottom hole assembly 90. The friction damper elements are part of the friction dampers and may comprise two cooperating entities, such as a first element and a second element having a frictional contact surface with the first element. The friction dampers of the present invention are arranged such that the first element has an average speed that is related to the rotational speed of the drilling system in which it is installed. For example, the first element may have a similar or the same average speed or rotational speed as the drilling system such that small varying fluctuations cause the relative velocity to change sign or cross zero between the first element and the second element in accordance with point 204 in FIG. 2.

It should be noted that frictional forces or torque between the drilling system and the borehole wall will not generate additional damping of high frequency vibrations in the system. This is because the relative velocity between the contact surfaces (eg, stabilizer and wellbore) does not have a zero average value (eg, point 202 in FIG. 2). In accordance with the embodiments described herein, the static friction between the first element and the second element is set high enough to allow the first element to accelerate the second element (while rotating) at an average speed ν ₀ with the same value as the drilling system . Thus, the additional high-frequency oscillations cause sliding between the first element and the second element at positive or negative speeds in accordance with the oscillations around the position shown in FIG. 2, which is equal to or close to point 204 in FIG. 2. Sliding occurs if the inertial force FI exceeds the static friction force, expressed as the coefficient of static friction times the normal force between two interacting objects: FI > μ ₀ FN. According to embodiments of the present invention, the normal force F _N (eg, caused by the contact and ground pressure of the contact surface between two interacting objects) and the static friction coefficient μ ₀ are adjusted to achieve optimal energy dissipation and optimal amplitude. In addition, the moment of inertia (torsional), contact and ground pressure of the contacting surfaces and the placement of the damper or contact surface relative to the distance from the bit can be optimized.

For example, in FIG. 7 schematically illustrates a damping system 700 in accordance with one embodiment of the present invention. Damping system 700 is part of a downhole system 702, such as a bottom hole assembly and/or drilling assembly. The wellbore system 702 includes a string 704 that rotates to allow drilling operations of the wellbore system 702 to form a wellbore 706 within the formation 708. As described above, the wellbore 706 is typically filled with drilling fluid, such as mud. The damping system 700 includes a first element 710 operatively coupled, for example, fixedly coupled or integral with the downhole system 702, to cause the first element 710 to rotate at an average speed that is related, for example, similar or identical to the average downhole speed. system 702. The first element 710 is in frictional contact with the second element 712. The second element 712 is at least partially movably mounted on the downhole system 702 with a contact surface 714 located between the first element 710 and the second element 712.

In the case of frictional forces, the difference between the minimum and maximum frictional force depends positively on the normal force and the coefficient of static friction. The dissipated energy increases with frictional force and harmonic displacement, but the energy is dissipated only in the sliding phase. During the sticking phase, the relative displacement between frictional couplings and dissipated energy is zero. The upper amplitude limit of sticking increases linearly with normal force and coefficient

- 8 045677 friction in the contact interface. The reason is that the reaction force at the contact interface, Jx > MH = F _N μ _H r, which can be caused by the moment of inertia J of one of the contacting objects, if it accelerates with x, must be higher than the torque MH = F _N μ _H r, which determines the limit between sticking and sliding. As used herein, FN is the normal force, _μΗ is the effective coefficient of friction, and r is the effective or average radius of the friction contact region. In the case of complex parts of frictional contacts of interacting objects, sticking or sliding can occur simultaneously. Herein, contact pressure can be optimized to achieve optimal damping and amplitude.

Similar mechanisms apply if the contact force is caused by displacement and a spring element. The acceleration x of the contact region may be due to the excitation mode of vibration and depends on the corresponding mode of vibration, as further discussed below in relation to FIG. 9B. In the case of an attached inertial mass (or simply inertia or mass in the context of this invention) with a moment of inertia J, the acceleration x is equal to the acceleration of the excited mode of vibration and the corresponding mode of vibration in the position of the attachment, provided that there is sticking in the contact interaction.

The normal force and the friction force need to be adjusted to ensure the sliding phase is within the appropriate or acceptable amplitude range. The permissible amplitude range can be defined by the amplitude that lies between the zero value and the load limits, which, for example, are given in industry specifications for tools and components. The limit can also be set as a percentage of the expected amplitude without the damper. The dissipated energy, which can be compared with the input energy, for example by forced action or self-excitation, is one quantity to determine the effectiveness of the damper. Another quantity is the provision of equivalent damping to the system, which is proportional to the ratio of the energy dissipated during one period of harmonic vibration to the potential energy during one period of vibration in the system. This value is especially effective in the case of self-excited systems. In the case of self-excited systems, excitation can be approximated by a negative damping factor, and both equivalent damping and negative damping can be compared directly. The damping force provided by a damper is non-linear and highly dependent on amplitude.

As shown in FIG. 20, damping is zero in the sticking phase (left end of the graph in FIG. 20), when the relative movement between interacting objects is zero. If, as described above, the limit between the sticking phase and the sliding phase is exceeded by the force that is transmitted through the contact interface, a relative sliding movement occurs which causes energy dissipation. The damping ratio provided by frictional damping is then increased to a maximum and then decreased to a minimum. The amplitude that will appear depends on the excitation, which can be described by the term negative damping. Herein, the maximum provided damping shown in FIG. 20 must be higher than the negative damping from the self-excitation mechanism. The amplitude that appears in the so-called limit cycle can be determined by the intersection of the negative damping ratio and the equivalent damping ratio that is provided by the friction damper.

The curve depends on various parameters. It is preferable to have a high normal force and a sliding phase with a minimum amplitude. In the case of inertial mass, this can be achieved by using a high mass or by placing the contact mating at a point of high acceleration relative to the excited mode shape. In the case of contacting mates, a large relative displacement compared to the amplitude of the vibration mode at the point of contact, for example along the axial axis of the BHA, is advantageous. Thus, optimal placement of the damper according to high amplitude or relative amplitude is important. This can be achieved by applying simulation results as described below. Normal force and friction coefficient can be applied to shift the curve to lower or higher amplitudes, but this does not have much effect on the damping maximum. If more than one friction damper is implemented, this will result in overlapping similar curves as shown in FIG. 20. If the normal force and friction coefficients are adjusted to achieve a maximum at the same amplitude, it is useful to achieve overall damping. Additionally, slightly shifted damping curves would result in a resulting curve that could be broader in amplitude, which could be useful for accounting for shocks that might shift the amplitude to the right of the maximum. In this case, the amplitude will increase to a very high value in the case of self-excited systems, as indicated by negative damping. In this case, it is necessary to shift the amplitude again to the left side of the maximum, for example, by moving away from the face or reducing the system rotation speed to lower levels. The amplitude in this context depends approximately linearly on the average rotation speed, as shown and discussed with reference

- 9 045677 in Fig. 8V below.

As shown in FIG. 7, the string 704 and therefore the well system 702N rotates at a speed άφ άτ' which can be measured in revolutions per minute (RPM). The second element 712 is mounted on the first element 710. The normal force F _N between the first element 710 and the second element 712 can be selected or adjusted through the application and use of the adjusting element 716. The adjusting element 716 can be adjustable, for example, through a thread, an actuator, a piezoelectric an actuator, a hydraulic actuator, and/or a force-applying spring element that has a component in a direction perpendicular to the contact surface 714 between the first element 710 and the second element 712. For example, as shown in FIG. 7, the control element 716 may apply a force in the axial direction from the well system 702, which is converted into a force component F _N that is perpendicular to the contact surface 714 of the first element 710 and the second element 712 due to the non-zero angle between the axis of the well system 702 and the contact surface 714 of the first element 710 and a second element 712. In some configurations, the angle between the system 712 and the inertial mass element is selected or determined to provide sliding motion and prevent self-locking.

The second element 712 has a moment of inertia J. When HFTO occurs during operation of the downhole system 702, both the downhole system 702 and the second element 712 are accelerated in accordance with the mode shape (for example, determining the amplitude distribution along the dimensions of the drilling system, drill string and/or BHA ) and the amplitude of the vibration mode (for example, the scale of the amplitude of the mode). Illustrative results of such work are shown in FIG. 8A and FIG. 8B. In fig. 8A is a graph of tangential (ie, circumferential) acceleration measured at a drill bit, and FIG. 8B shows the corresponding rotation speed.

Due to the tangential acceleration and inertia of the second element 712, relative inertial forces are generated between the second element 712 and the first element 710. If these inertial forces exceed the threshold between sticking and sliding, that is, if these inertial forces exceed the static friction force between the first element 710 and the second element 710, relative movement between the elements 710, 712 occurs, resulting in energy dissipation. In such acceleration configurations, the coefficient of static and/or dynamic friction and the normal force determine the amount of energy dissipated. For example, the moment of inertia J of the second element 712 determines the relative force that must be transmitted between the first element 710 and the second element 712. High accelerations and moments of inertia increase the tendency to slide on the contact surface 714 and thus provide higher energy dissipation and equivalent damping coefficient provided by the damper.

Due to the energy dissipation caused by the frictional movement between the first element 710 and the second element 712, heat and wear will be generated on the first element 710 and/or the second element 712. To keep wear below an acceptable level, materials that can withstand wear can be used for the first and/or second elements 710, 712. For example, drill diamonds or polycrystalline diamond bits may be used for at least a portion of the first and/or second elements 710, 712. Alternatively or additionally, coatings may help reduce wear due to friction between the first and second elements 710, 712. Heat may drive to high temperatures and may affect the reliability or durability of the first element 710, the second element 712 and/or other parts of the well system 702. The first element 710 and/or the second element 712 may be made of a material with high thermal conductivity or high thermal capacity and/or may be in contact with a material with high thermal conductivity or heat capacity.

Such high thermal conductivity materials include, but are not limited to, metals or compounds including metal such as copper, silver, gold, aluminum, molybdenum, tungsten, or thermal grease containing grease, lubricant, oil, epoxy resins, silicones, urethanes and acrylates, and optionally fillers such as diamond, metal or chemical compounds including metal (eg silver, aluminum in aluminum nitride, boron in boron nitride, zinc in zinc oxide), or silicon or chemical compounds including silicon (eg , silicon carbide). Additionally or alternatively, one or both of the first element 710 and the second element 712 may be in contact with a fluid, such as drilling fluid, which is configured to remove heat from the first element 710 and/or the second element 712 to cool the corresponding element 710, 712. Additionally, an amplitude limiting element (not shown), such as a manipulator, notch, or spring element, may be provided and configured to limit energy dissipation to an acceptable limit that reduces wear.

When the damping system 700 is placed, a high normal force and/or coefficient of static or dynamic friction prevents relative sliding movement between the first element 710 and the second element 712, and in such situations, energy will not be dissipated. In contrast, low normal force and/or coefficient of static or dynamic friction may result in low frictional force and sliding occurs but the dissipated energy is negligible. In addition, a low normal force and/or coefficient of static or dynamic friction may cause the friction on the outer surface of the second element 712, such as between the second element 712 and the molding 708, to be greater than the friction between the first element 710 and the second element 712, resulting in to a situation where the relative velocity between the first element 710 and the second element 712 is not zero, but is in the range of the average velocity between the well system 702 and the formation 708. Thus, the normal force and coefficient of static or dynamic friction and the placement of the damper element relative to excitation waveforms and waveforms (eg, using control element 716) to achieve an optimized value for energy dissipation.

This can be accomplished by adjusting the normal force FN, the static friction coefficient μ ₀ , the dynamic friction coefficient μ, the placement of the damper element relative to the excited vibration mode, or combinations thereof. The normal force FN can be adjusted by placing a control element 716 and/or actuators that generate a force on one of the first and second elements with a component perpendicular to the contact surface of the first and second elements, by adjusting the pressure regime around the first and second elements, or by increasing or reducing the area over which pressure acts. For example, by increasing the external pressure that acts on the second element, such as the pressure of the flushing fluid, the normal force FN will also be increased. Control of the drilling fluid pressure in the well can be achieved by adjusting mud pumps (eg, mud pumps 34 shown in FIG. 1) at the surface or other equipment at the surface or in the well that affects the drilling fluid pressure, such as bypass valves, valves, water hammer absorbers. The normal force can be adjusted in the same way to be harmonic at the same frequency as the free oscillation frequency of the excited mode shape and thus have low normal force values for low inertial mass accelerations and high normal force values for low inertial mass accelerations , and this provides sliding motion with low acceleration values.

The normal force F _N can also be adjusted by a biasing element (not shown), such as a spring element, that applies a force to the second element 712, for example, a force in the axial direction from or to the first element 710. Adjustment of the normal force F _N can also be performed in a controlled manner based on an input signal received from the sensor. For example, a suitable sensor (not shown) may provide one or more parameter values to a controller (not shown) whose parameter value(s) are related to the relative movement of the first element 710 and the second element 712 or the temperature of one or both of the first element 710 and a second element 712. Based on the value of the parameter(s), the controller may provide a command to increase or decrease the normal force FN. For example, if the temperature of one or both of the first element 710 and the second element 712 exceeds a threshold temperature, the controller may provide a command to reduce the normal force F _N to prevent damage to one or both of the first element 710 and the second element 712 due to exposure to high temperatures. Likewise, for example, if the distance, speed, or acceleration of the second element 712 relative to the first element 710 exceeds a threshold, the controller may provide commands to increase or decrease the normal force FN to ensure optimal energy dissipation. By controlling the parameter value, the normal force FN can be adjusted to achieve the desired results over a period of time. For example, the normal force FN can be adjusted to provide optimal energy dissipation while maintaining the temperature of one or both of the first element 710 and the second element 712 below the threshold for starting drilling or a portion thereof.

In addition, the coefficient of static or dynamic friction can be adjusted using different materials, such as, but not limited to, a material with different stiffness, different roughness and/or different lubrication. For example, a surface with higher roughness often increases the coefficient of friction. Thus, the coefficient of friction can be adjusted by selecting a material with an appropriate coefficient of friction for at least one of the first and second elements or a portion of at least one of the first and second elements. The material of the first and/or second element may also affect wear of the first and second elements. To keep the wear of the first and second elements low, it is advisable to select a material that can withstand the friction that is created between the first and second elements. The inertia, coefficient of friction, and expected acceleration amplitudes (eg, as a function of mode shape and natural frequency) of the second element 712 are parameters that determine dissipated energy and need to be optimized. Critical mode shapes and acceleration amplitudes can be determined based on measurements or calculations or other known methods that will be understood by those skilled in the art. Examples are finite element analysis or transfer matrix method or finite difference method, and based on this modal analysis or analytical models. Friction damper placement is optimal when high relative displacement or acceleration is expected.

In fig. 9A and FIG. 9B shows an example of a well system 900 and associated modes. In fig. 9A is a schematic diagram of a well system illustrating the shape of the well system as a function of distance from the bit, and FIG. 9B illustrates exemplary corresponding torsional vibration waveforms that may be generated during operation of the wellbore system shown in FIG. 9A. In the images presented in FIGS. 9A and FIG. 9B, illustrates the potential position and placement of one or more damping system elements on the wellbore system 900.

As illustrated in FIG. 9A, the well system 900 has various components with different diameters (along with different masses, densities, configurations, etc.) and thus, as the well system 900 rotates, the different components may result in different shapes. The illustrative forms show that there will be very high amplitudes that may require damping through the use of a damping system. For example, as shown in FIG. 9B, a first torsional vibration waveform 902, a second torsional vibration waveform 904, and a third torsional vibration waveform 906 of the downhole system 900 are shown. Based on knowledge of the vibration modes 902, 904, 906, the position of the first elements of the damping system can be optimized. At maximum amplitude(s) of vibration modes 902, 904, 906, damping may be required and/or achieved. Accordingly, two potential positions for attaching or installing the damping system of the present invention are illustrated.

For example, the first damping position 908 is close to the drill bit of the well system 900 and primarily dampens the first and third torsional vibrations (corresponding to vibration modes 902, 906) and provides some damping relative to the second torsional vibration (corresponding to vibration modes 904). Thus, the first damping position 908 should be approximately at the peak of the third torsional vibration mode (corresponding to the vibration mode 906), close to the peak of the first torsional vibration mode 902, and about half the value to the peak relative to the second torsional vibration mode 904.

The second damping position 910 is configured to primarily again provide damping to the third torsional vibration mode 906 and provide some damping relative to the first torsional vibration mode 902. However, at the second damping position 910, damping of the second torsional vibration mode 904 will not occur because the second torsional vibration mode 904 is substantially zero at the second damping position 910.

Although in FIG. 9A and FIG. 9B shows only two positions for placing the damping systems of the present invention, the embodiments need not be so limited. For example, any number and any arrangement of damping systems along the well system may be possible to provide damping of torsional vibration on the well system. An example of a preferred mounting position for a damper is where one or more of the expected vibration modes exhibit high amplitudes.

Due to the high amplitudes in the drill bit, for example, one proper damper position is close to the drill bit or inside the drill bit. Moreover, the first and second elements are not limited to a single housing, but may take any number of different configurations to achieve the required damping. Thus, it is possible to employ multiple body first or second elements (eg, friction dampers) with each body having the same or different normal forces, friction coefficients, and moments of inertia. Such multi-body systems can be used, for example, when there is uncertainty about what mode of vibration and associated acceleration is expected at a given position along the well system.

For example, two or more element bodies may be used, which may provide different relative sliding movements between them to dissipate energy. The multiple first element bodies may be selected and assembled with different coefficients of static or dynamic friction, angles between contact surfaces, and/or may have other mechanisms for influencing the amount of friction and/or the transition between sticking and sliding. Several amplitude levels, excited mode shapes, and/or free vibration frequencies can be damped by such configurations.

For example, in FIG. 10 schematically illustrates a damping system 1000 in accordance with one embodiment of the present invention. The damping system 1000 may operate in a manner similar to that shown and described above in relation to FIG. 7. The damping system 1000 includes a first element 1010 and second elements 1012. However, in this embodiment, the second element 1012 mounted on the first element 1010 of the well system 1002 is formed from the first

- 12 045677 housing 1018 and second housing 1020. The first housing 1018 has a first contact surface 1022 between the first housing 1018 and the first element 1010, and the second housing 1020 has a second contact surface 1024 between the second housing 1020 and the first element 1010. As shown, the first housing 1018 is separated from the second housing 1020 by a gap 1026. The gap 1026 is provided to prevent interaction between the first housing 1018 and the second housing 1020 such that they may function (eg, move) independently of each other or not interact directly with each other. In this embodiment, the first body 1018 has a first static or dynamic friction coefficient μ1 and a first force FN1 that is perpendicular to the first contact surface 1022, while the second body 1020 has a second static or dynamic friction coefficient μ ₂ and a second force FN2 that is perpendicular to the second contact surface surface 1024. In addition, the first housing 1018 may have a first moment of inertia, J1, and the second housing 1020 may have a second moment of inertia, _J2 . In some embodiments, at least one of the first static or dynamic friction coefficient μ1, the first normal force FN1, and the first moment of inertia J1 is selected to be different from the second static or dynamic friction coefficient _μ2 , the second normal force FN2, and the second moment of inertia J1 respectively. Thus, the damping system 1000 may be configured to accommodate multiple different vibration modes at substantially the same position along the wellbore system 1002.

In fig. 11 is a schematic illustration of a damping system 1100 in accordance with one embodiment of the present invention. The damping system 1100 may function similarly to that shown and described above. However, in this embodiment, the second element 1112 mounted on the first element 1110 of the well system 1102 is formed from a first housing 1118, a second housing 1120, and a third housing 1128. The first housing 1118 has a first contact surface 1122 between the first housing 1118 and the first element 1110, wherein the second housing 1120 has a second contact surface 1124 between the second housing 1120 and the first element 1110, and the third housing 1128 has a third contact surface 1130 between the third housing 1128 and the first element 1110. As shown, the third housing 1128 is located between the first housing 1118 and the second housing 1020 In this embodiment, three housings 1118, 1120, 1128 are in contact with each other and thus may have normal forces and coefficients of static or dynamic friction between them.

Contact between the three housings 1118, 1120, 1128 may be established, supported, or retained by resilient coupling members, such as spring elements, between two or more members 1118, 1120, 1128. Additionally or alternatively, the first housing 1118 may have a first static or dynamic coefficient friction μ ₂ and a first force FN1 on the first contact surface 1122, the second body 1120 may have a second coefficient of static or dynamic friction μ ₂ and a second force FN2 on the second contact surface 1124, and the third body 1128 may have a third coefficient of static or dynamic friction μ ₃ and a third force FN3 on the third contact surface 1130.

Additionally or alternatively, the first body 1118 and the third body 1128 may have a fourth force F _H13 and a fourth coefficient of static or dynamic friction μ ₁₃ with each other at a contact surface between the first body 1118 and the third body 1128. Likewise, the third body 1128 and the second body 1120 may have a fifth force F _N32 and a fifth coefficient of static or dynamic friction μ ₃₂ among themselves on the contact surface between the third housing 1128 and the second housing 1120.

In addition, the first housing 1118 may have a first moment of inertia J1, and the second housing 1120 may have a second moment of inertia _J2 , and the third housing 1128 may have a third moment of inertia _J3 . In some embodiments, the static or dynamic friction coefficients μ1, μ ₂ , μ ₃ , μ ₁₃ , μ ₃₂ , forces F _N1 , F _N2 , F _N3 , F ₁₃ , F ₃₂ , and moment of inertia J1, J ₂ , J ₃ may be selected to be different from each other such that the product μ1 Fi (with i = 1, 2, 3, 13, 32) is different from at least a subrange of the relative velocities of the first element 1110, the first body 1118, the second body 1120 and the third housings 1128. Moreover, static or dynamic friction coefficients and normal forces between adjacent housings can be selected to achieve different damping effects.

Although shown and described in terms of a limited number of embodiments and specific shapes, relative sizes and numbers of elements, those skilled in the art will appreciate that the damping systems of the present invention can take any configuration. For example, shapes, sizes, geometric configurations, radial placements, contact surfaces, number of housings, etc. can be selected to achieve the desired damping effect. Although in the arrangement shown in FIG. 11, the first body 1118 and the second body 1120 are connected to each other by frictional contact with the third body 1128, such arrangement and description are not intended to be limiting. The connection between the first housing 1118 and the second housing 1120 may also be created by a hydraulic, electrical or mechanical coupling means or mechanism. For example, a mechanical connection between the first housing 1118 and the second housing 1120 may be created by a rigid or elastic connection between the first housing 1118 and the second housing 1120.

In fig. 12 is a schematic illustration of a damping system 1200 in accordance with one embodiment of the present invention. The damping system 1200 may function similarly to that shown and described above. However, in this embodiment, the second element 1212 of the damping system 1200 is partially fixed to or connected to the first element 1210. For example, as shown in this embodiment, the second element 1212 has a stationary portion 1232 (or end) and a movable portion 1234 (or end). The fixed portion 1232 is attached to the first element 1210 along the fixed connection 1236, and the movable portion 1234 is in frictional contact with the first element 1210 through the contact surface 1214 (similar to the first element 1010 in frictional contact with the second element 1012 described with respect to FIG. 10).

The moving part 1234 can be of any desired length, which can be associated with the vibration modes, as shown in FIG. 9B. For example, in some embodiments, the moving portion may be longer than a tenth of the distance between the maximum and minimum of any of the vibration modes that may have been calculated for a particular drilling assembly. In another example, in some embodiments, the moving part may be longer than one-quarter of the distance between the maximum and minimum of any of the vibration modes that may have been calculated for a particular drilling assembly. In another example, in some embodiments, the moving part may be longer than half the distance between the maximum and minimum of any of the vibration modes that may have been calculated for a particular drilling assembly. In another example, in some embodiments, the moving part may be longer than the distance between the maximum and minimum of any of the vibration modes that may be calculated for a particular drilling assembly.

Thus, even though it may not be known where the exact position of the peaks or troughs of the shape is during deployment in the well, the second element 1212 is ensured to be in frictional contact with the first element 1210 at the position of maximum amplitude to achieve optimized damping. Although it will be clear to those skilled in the art that other arrangements of partially fixed first elements are possible without departing from the scope of the present invention. For example, in one non-limiting embodiment, the fixed portion may be located in a more central portion of the first element such that the first element has two movable portions (eg, at opposite ends of the first element). As can be seen in FIG. 12, the movable portion 1234 of the second element 1212 is sufficiently elongated and can cover a portion of the vibration modes (eg, mode shapes 902, 904, 906 in FIG. 9B) that correspond to the length of the movable portion 1234 of the second element 1212. The elongated second element 1212 is in frictional contact with the first element 1210 may have advantages over shorter second elements because the shorter second elements may be located in an undesirable part of the mode shapes, such as at the damping position 910, where the second mode shape 904 is small or even zero, as described above in regarding fig. 9B. The use of an elongated second element 1212 may ensure that at least a portion of the second element is spaced away from positions in which one or more mode shapes are zero or at least near zero. In fig. 1319 and 21-22 show more varieties of elongated second elements in frictional contact with the first elements. In some embodiments, the elongated second members may be resilient such that the movable portion 1234 is movable relative to the first member 1210 while the stationary portion 1232 is stationary relative to the first member 1210. In some embodiments, the second member 1212 may have multiple contact points in a plurality of positions of the first element 1210.

In the embodiments described above and in damping systems in accordance with the present invention, the first elements are temporarily attached to the second element due to frictional friction. However, when vibrations of well systems increase and a threshold is exceeded, for example, when the inertial force exceeds the static friction force, the first elements (or parts thereof) move relative to the second elements, thereby providing damping. That is, when HFTOs increase predetermined thresholds (e.g., amplitude, distance, velocity, and/or acceleration thresholds) in downhole systems, the damping systems will automatically function, and thus, embodiments proposed herein include passive damping systems. For example, embodiments include passive damping systems that automatically operate without the application of additional energy, and therefore do not employ an additional source of energy.

In fig. 13 is a schematic illustration of a damping system 1300 in accordance with one embodiment of the present invention. In this embodiment, the damping system 1300 includes one or more elongated first elements 1310a, 1310b, 1310c,

- 14 045677

1310d, 1310e, 1310f, each of which is located within and in contact with the second element 1312. Each of the first elements 1310a, 1310b, 1310c, 1310d, 1310e, 1310f may have a length in the axial direction of the tool (for example, in a direction perpendicular to the cross section shown in Fig. 13) and optionally a fixed point at which the corresponding first elements 1310a, 1310b, 1310c, 1310d, 1310e, 1310f are attached to the second element 1312. For example, the first elements 1310a, 1310b, 1310c, 1310d, 1310e, 1310f may be attached to respective top ends, middle portions, bottom ends, or a plurality of attachment points for various first elements 1310a, 1310b, 1310c, 1310d, 1310e, 1310f or a plurality of points for a given one first element 1310a, 1310b, 1310c, 1310d, 1310e, 1310f. Moreover, as shown in FIG. 13, the first elements 1310a, 1310b, 1310c, 1310d, 1310e, 1310f may optionally be biased or engaged with the second element 1312 by a bias element 1338 (for example, by a bias spring element or a bias drive mechanism applying a force to a component second element 1312). Each of the first elements 1310a, 1310b, 1310c, 1310d, 1310e, 1310f may be positioned and selected to have the same or different normal forces, static or dynamic friction coefficients, and moments of inertia, thereby providing different damping configurations.

In some embodiments, the first elements may be substantially uniform in material, shape, and/or geometric configuration along their length. In other embodiments, the first elements may vary in shape and geometric configuration along their length. For example, with reference to FIG. 14 is a schematic illustration of a damping system 1400 in accordance with one embodiment of the present invention. In this embodiment, the first element 1410 is positioned relative to the second element 1412, and the first element 1410 has a tapering and/or spiral design relative to the second element 1412. Accordingly, in some embodiments, a portion of the first or second element may vary in geometric configuration or shape along its length relative to the second element, and such changes may also occur longitudinally around the second element and/or relative to the tool body or downhole system.

In fig. 15 is a schematic illustration of another damping system 1500 in accordance with one embodiment of the present invention. In the damping system 1500, the first element 1510 is a toothed (threaded) body that fits into a threaded second element 1512. Contact between the teeth (threads) of the first element 1510 and the threads of the second element 1512 may provide frictional contact between the two elements 1510, 1512 to provide damping. , as described in this document. Due to the inclined surfaces of the first element 1510, the first element 1510 begins to move under the influence of both axial and/or torsional vibrations. In addition, movement of the first element 1510 in the axial direction or the circumferential direction also generates movement in the circumferential direction or the axial direction, respectively, in this configuration. Thus, with the arrangement shown in FIG. 15, axial vibrations can be applied to soften or dampen torsional vibrations, and torsional vibrations can be applied to soften or dampen axial vibrations.

The positions in which axial and torsional vibrations occur can be different. For example, although axial vibrations may be uniformly distributed along the drilling assembly, torsional vibrations may follow a pattern of vibration modes as described above with reference to FIG. 9A, B. Thus, no matter where the vibrations occur, the configuration shown in FIG. 15 may be used to dampen torsional vibrations when the first element 1510 moves relative to the second element 1512 caused by axial vibrations, and vice versa. As shown, an optional tightening element 1540 (e.g., a bolt) can be used to control the contact pressure or normal force between two elements 1510, 1512 and thereby control the frictional force and/or other damping characteristics of the damping system 1500.

Further, in accordance with Fig. 16 is a schematic illustration of a damping system 1600 in accordance with another embodiment of the present invention. A damping system 1600 that includes a first element 1610 that is a rigid rod that is at one end secured within a second element 1612. In this embodiment, the end 1610a of the rod is configured to frictionally contact a stop 1612a of the second element to thereby provide damping, as described in accordance with embodiments of the present invention. The normal force between the rod end 1610a and the second member stop 1612a may be adjustable, for example, by a threaded connection between the rod end 1610a and the first member 1610. In addition, the stiffness of the rod may be selected to optimize damping or influence the mode shape in a favorable manner to provide greater relative displacement. For example, selecting a lower stiffness rod will result in higher torsional vibration amplitudes of the first element 1610 and higher energy dissipation.

- 15 045677

Further, in accordance with Fig. 17 is a schematic illustration of a damping system 1700 in accordance with another embodiment of the present invention. A damping system 1700 that includes a first element 1710 that is frictionally attached or coupled to a second element 1712 that is arranged as a rigid rod and that is fixedly connected (e.g., by welding, bolting, brazing, adhesion, etc.) with an external tubular member 1714, such as a drill collar, at a fixed connection 1716. In one aspect, the rod may be a tubular member that contains electronic components, power supplies, storage media, batteries, microcontrollers, actuators, sensors, etc. ., which are subject to wear due to HFTO. Thus, in one aspect, the second element 1712 may be a probe, such as a probe for measuring directional information, including one or more of a gravimeter, a gyroscope, and a magnetometer. In this embodiment, the first element 1710 is configured to frictionally contact, move or oscillate relative to and along the fixed rod structure of the second element 1712 to thereby provide damping as described in accordance with embodiments of the present invention. Although in FIG. 17 shows that the first element 1710 is relatively small compared to the damping system 1700, this should not imply a limitation in this regard. Thus, the first element 1710 may be of any size and may have the same outer diameter as the damping system 1700. In addition, the position of the first element 1710 may be adjustable to move the first element 1710 closer to the maximum of the vibration mode to optimize damping softening.

Further, in accordance with Fig. 18 is a schematic illustration of a damping system 1800 in accordance with another embodiment of the present invention. Damping system 1800 includes a first element 1810 that is frictionally movable along a second element 1812. In this embodiment, the first element 1810 is disposed with an elastic spring element 1842, such as a coil spring or other element or means, for engaging the first element 1810 with a second element 1810. element 1812 to thereby provide a restoring force when the first element 1810 has moved and deflected relative to the second element. The restoring force is directed toward reducing the deflection of the first element 1810 relative to the second element 1812. In such embodiments, the resilient spring element 1842 may be positioned or tuned to resonance and/or a critical frequency (e.g., the lowest critical frequency) of the resilient spring element 1842 or the vibrating system containing a first element 1810 and an elastic spring element 1842.

Further, in accordance with Fig. 19 is a schematic illustration of a damping system 1900 in accordance with another embodiment of the present invention. Damping system 1900 includes a first element 1910 that is frictionally movable about a second element 1912. In this embodiment, the first element 1910 is positioned with a first end 1910a having a first contact (e.g., the normal force FNi of the first end, the coefficient of static or dynamic friction μ _i of the first end and the moment of inertia J, the first end) and the second contact at the second end 1910b (for example, the normal force FNi of the second end, the coefficient of static or dynamic friction μ _{i of} the second end, and the moment of inertia J, the second end). In some such embodiments, the type of interaction between the respective first end 1910a or second end 1910b and the second element 1912 may have different physical characteristics. For example, one or both of the first end 1910a and the second end 1910b may have a gripping contact/engagement, and one or both may have a sliding contact/engagement. The locations/configurations of the first and second ends 1910a, 1910b may be set to provide damping as described in accordance with embodiments of the present invention.

Advantageously, embodiments provided herein relate to systems for mitigating high frequency torsional vibration (HFTO) of downhole systems by employing damping systems mounted on a rotating string (eg, a drill string). The first elements of the damping systems are at least partially frictionally connected to move circumferentially relative to the axis of the column (for example, frictionally connected to rotate about the axis of the column). In some embodiments, the second elements may be part of the drilling system or bottom hole assembly and do not necessarily need to be a separately installed component or weight. The second element, or a portion thereof, is connected to the well system such that the relative movement between the first element and the second element has a relative zero or near zero velocity (ie, no or slow relative movement) in the absence of HFTO. However, when HFTO occurs above a certain acceleration value, relative movement between the first element and the second element is possible and alternating positive and negative relative velocities are achieved. In some embodiments, the second element may be a mass or weight that is connected to the well system. In other embodiments, the second element may be part of the wellbore

- 16 045677 system (for example, part of a drilling system or BHA) with friction between a first element and a second element, such as the rest of the well system, providing the functionality described herein.

As described above, the second elements of the damping systems are selected or designed such that, in the absence of vibration (ie, HFTO) in the column, the second element will be frictionally connected to the first element by a static friction force. However, in the presence of vibration (HFTO), the second elements begin to move relative to the first element, and the frictional contact between the first and second elements is reduced, as described above with respect to FIG. 2 in such a way that the second element can rotate (move) relative to the first element (or vice versa). When moved, the first and second elements provide energy dissipation, thereby softening the HFTO. Damping systems and, in particular, their first elements are located, weighted, force-mounted and sized to provide damping of one or more specific or specified vibration modes/frequencies. As described herein, the first elements are fixedly coupled when there is no vibration of the FHTO, but are then capable of moving in the presence of certain accelerations (eg, in accordance with the vibration modes of the FHTO), thereby providing damping of the HFTO through the zero crossing of the relative speed (eg, switching between positive and negative relative rotation speeds).

In the various configurations described above, sensors can be used to evaluate and/or monitor the efficiency and energy dissipation of the damper. Measuring displacement, velocity and/or acceleration near the point of contact or surface of two interacting objects, for example in combination with force or torque sensors, can be used to estimate relative displacement and calculate energy dissipation. The force may also be known without measurement, for example when two interacting objects are engaged by a biasing element such as a spring element or an actuator. Dissipated energy can also be obtained from temperature measurements. Such measurement values may be communicated to a controller or human operator, who may provide adjustments to parameters such as normal force and/or static or dynamic friction coefficient(s) to achieve higher energy dissipation. For example, measured and/or calculated values of displacement, velocity, acceleration, force and/or temperature may be sent to a controller, such as a microcontroller, which has a set of instructions stored on a storage medium based on which it regulates and/or controls at least one of the force that interacts with two interacting objects and/or the coefficients of static or dynamic friction. Preferably, adjustment and/or control is performed while the drilling process continues to achieve optimal HFTO damping results.

Although the embodiments described herein have been described with reference to specific figures, it should be understood that various changes and substitutions of equivalent elements may be made without departing from the scope of the present invention. Moreover, many modifications will be understood to adapt a particular tool, situation, or material to the teachings of the present invention without departing from the scope thereof. Thus, it is intended that the present description is not limited to the specific embodiments described, and that the present description includes all embodiments coming within the scope of the appended claims or the description below of possible embodiments.

Intense vibrations in drill strings and bottom hole assemblies can be caused by cutting forces on the drill bit or mass imbalances in downhole tools such as drilling motors. Negative effects, among other things, reduce the rate of penetration during drilling, reduce the quality of measurements and failures in the well.

There are different types of torsional vibrations. In the literature, torsional vibrations are mainly differentiated as sticking/slippage of the entire drilling system and high-frequency torsional vibrations (HFTO). Both of them are primarily excited by self-excitation mechanisms that result from the interaction between the drill bit and the formation. The main differentiator between stick/slip and HFTO is the frequency and typical mode shape. In the case of HFTO, the frequency is more than 50 Hz compared to less than 1 Hz in the case of sticking/slipping. In addition, the excited stick/slip mode represents the mode of the entire drilling system, while the HFTO mode is usually localized to a small part of the drilling system and has a relatively high amplitude at the drill bit.

As a result of the high frequency, HFTO corresponds to high acceleration and torque values along the BHA and can have a damaging effect on electronic components and mechanical parts. Based on self-excitation theory, increased damping can soften HFTO if a certain limit of the damping value is reached (since self-excitation is unstable and can be interpreted as negative damping of the associated mode shape).

One damping concept is based on friction. Friction between two parts in a BHA or drill string can dissipate energy and reduce the level of torsional vibration.

This concept describes a design principle that the inventors believe works best for frictional damping. Damping must be achieved by frictional force, with the operating point of frictional force relative to relative speed being around point 204 shown in FIG. 2. This operating point results in high energy dissipation as frictional hysteresis is achieved, whereas point 202 shown in FIG. 2, leads to the supply of energy to the system.

As discussed above, frictional forces between the drilling system and the wellbore will not create significant additional damping in the system. This is because the relative velocity between the contact surfaces (such as the stabilizer and the wellbore) does not have a zero mean value. The two interacting friction damper objects must have an average speed or rotational speed relative to each other that is low enough that the HFTO causes the relative speed of the two interacting friction damper objects to change sign. In other words, the maximum relative speeds between two interacting objects generated by HFTO must be higher than the average relative speed between two interacting objects.

Energy dissipation occurs only in the slipping phase at the interface between the first and second damper elements. Slipping occurs if the inertial force exceeds the limit between sticking and slipping, which is the static friction force: FR > μ ₀ FN (where the static friction force is equal to the coefficient of static friction multiplied by the normal force between both contacting surfaces). The normal force and/or coefficient of static or dynamic friction can be adjusted to achieve optimal or desired energy dissipation. Controlling at least one of the normal force and the coefficient of static or dynamic friction may result in improved energy dissipation by the damping system.

As described herein, the placement of the friction damper should be in the region of high HFTO accelerations, loads and/or relative displacement. Since this can affect various mode shapes, a design that is capable of attenuating all mode shapes of the FHTO is preferred (eg, FIG. 9A and FIG. 9B).

An equivalent can be used as the friction damper of the present invention. A slotted drill collar 2100 may be used as shown in FIG. 21 and fig. 22. In FIG. 22 is a cross-sectional view of a slotted drill collar 2100. In one non-limiting embodiment, slotted drill collar 2100 has high flexibility or low stiffness, which will result in higher deformations if friction devices 2102 are not included. Higher speed will result in increased centrifugal forces, which will increase the force of friction devices 2102. to the grooves using optimized normal forces to provide significant frictional damping. In this configuration, other factors that can be optimized are the number and geometric configuration of the slots, as well as the geometric configuration of the damper. Additional normal force may be applied by spring elements, as shown in FIG. 22, drive mechanisms and/or centrifugal forces, as described above.

The advantage of this principle is that the friction devices 2102 will be directly installed in the flow of force. The twist of the drill collar due to the excited HFTO mode and associated vibration shape will be partially supported by the friction devices 2102, which will move up and down during one period of vibration. The high relative displacement together with the optimized coefficient of friction and normal force results in high energy dissipation.

In this case, the goal is to prevent amplitude increases in FHTO amplitudes (in this case represented by tangential acceleration amplitudes). The (modal) damping that must be added to each variable torsional mode by a friction damper system must be greater than the energy input to the system. The energy input does not occur instantly, but over many periods until the worst case amplitude is reached (zero drill bit rotation speed).

With this concept, a short collar can be used because the friction damper applies relative movement along the distance from the bit. There is no need for high tangential acceleration amplitude, but only some deflection (twisting) of the collar is required, which will be achieved at almost every location along the BHA. The weighted pipe and dampers must have a similar mass-to-stiffness ratio (impedance) compared to the BHA. This will ensure propagation of the vibration mode in the friction weighted tube. High damping will be achieved which will soften the HFTO if the parameters described above are adjusted (normal force due to springs, etc.). An advantage over other friction damper principles is the application of friction devices directly to the deflection force flow to the HFTO vibration mode. The relatively high relative speed between the friction devices and the weight pipe will result in high energy dissipation.

The damper will be quite useful and will be suitable for various applications. HFTO results in high costs due to significant repair and maintenance efforts, reliability issues with unproductive use of time, and low market share. The proposed friction damper would operate below the engine (this separates the HFTO) as well as above the engine. It can be installed anywhere on the BHA, which also includes placement above the BHA if the vibration mode extends to that point. The vibration mode propagates through the entire BHA if the distribution of mass and stiffness is relatively uniform. The optimal placement can, for example, be determined by a torsional vibration operator, which allows the critical FHTO modes and corresponding vibration modes to be calculated.

Additionally, as noted above, due to the high amplitudes on the drill bit, one damper position as described herein may be located within the drill bit. Thus, in accordance with some embodiments of the present invention, dampers may be integrated into and included in a drill bit or other disintegration device. In such embodiments, the distance to the bit is zero or substantially zero.

In some such embodiments, the damper may be formed from mass or inertia that couples to the drill bit or string damper element only through damping force or torque. The damping force, for example and without limitation, may be generated by viscous damping, frictional damping, hydraulic damping, magnetic damping (eg, eddy current damping), piezoelectric (shunt) damping, etc. In some such embodiments, the damper may be combined with a spring that may provide a tunable damper, such as a tunable friction damper. In these cases, the natural frequency of the damper can be tuned to the natural frequency of the waveform that is to be damped. In addition to being mounted or secured on or near the drill bit (ie, at the end of the well string), the damper can be installed in any position within or on the BHA and thus located near the end of the well string.

As described above, the placement of vibration damping devices along the drill string affects the effectiveness of vibration damping. Typical HFTO modes, because these modes are higher order, have multiple nodes and peaks along the BHA string section. Placing a vibration damper that responds to vibration amplitude at a position inside or on top of a BHA that has a low amplitude or zero (node) amplitude vibration mode may result in reduced damping efficiency for the corresponding vibration mode. However, positioning the damper at a local maximum of the vibration mode to be damped creates increased damping for that vibration mode, as described above.

In accordance with some embodiments of the present invention, drill string elements, further waveform adjustment elements, with specified or selected lengths and/or diameters can be used to increase the amplitude of a local maximum at a specific location in the waveform, for example, in a mass-normalized waveform. . This reinforcement can improve damping efficiency. Thus, intentional and specific modification of the drill string and/or BHA can provide control of the location and amplitude of a local maximum waveform, such as a mass-normalized waveform, thereby controlling and/or increasing damping efficiency, which can be implemented as described above , with the inclusion of elements for adjusting the vibration shape.

For example, using simulation or other software, individual waveform trim elements can be selected to realize improved or optimal damper placement on a custom-designed BHA. Such modeling or software can be applied to provide special custom properties (e.g. dimensions such as length or diameter, material and/or mechanical properties such as stiffness, flexibility, mass, moment of inertia, density or modulus of elasticity (shear and core). mass)), as well as for the positioning/location of vibration shape adjustment elements, and/or for the positioning/location of one or more damping elements. Additionally, in some embodiments, the software/simulation may be configured to select from a set (eg, as shown in FIG. 29A) or a list of specific predetermined waveform trim elements to be used in combination with one or more damper elements. Software/simulation can also be used to create and optimize a set of waveform trim elements. In addition to length and diameter, custom values for mode shape, density, shape, elastic modulus (shear and bulk) and/or other parameters that affect the flexibility or inertia of the string and/or BHA can be specified to control the amplitude of the local maximum.

- 19 045677

HFTO damping, and in particular the placement of devices for enhanced or optimized HFTO damping, is a fairly new technology. The basic theory is described in Hohl et al. (2015): Derivation and experimental verification of an analytical criterion for identifying self-excited vibration modes in drilling systems, published in the Journal of Sound and Vibration, 342, pp. 290-302, the contents of which are incorporated herein by reference in their entirety. One idea of adjusting the mode shape to minimize vibration at certain positions in the BHA and reduce excitability S _c (eg, the smallest slope of the torque characteristic for which the system is minimally stable) is described in US Patent No. 9,976,405, entitled Method for reducing induced vibration bits by intentionally modifying the vibration modes of drill strings through changes in mass or stiffness, issued May 22, 2018, the contents of which are incorporated herein by reference in their entirety. However, artificial maximization of the amplitude of the vibration mode at the actual position of the damping element has not been described. For example, the use of waveform tuning elements, as described herein, can be used to enhance or even maximize the waveform at a particular position and thus provide increased damping efficiency of the HFTO. Examples of waveform tuning elements may be torsionally compliant elements (e.g., coiled tubing) and/or high inertia components (e.g., high mass sections), or combinations thereof of varying lengths, used to enhance the amplitude of the modem at the damping element position. (eg a damping element as described above and below).

Placing dampers at random positions along the drill string is one method, but such random placement may result in ineffective damping. Such random placement may be selected based on a particular BHA or other feature/characteristic of the string such that dampers are placed in locations that make sense based on other features of the string. This lack of damping effect is a result of most positions having significantly lower damping capacity than the maximum (eg, at positions other than the maximum waveform positions, such as the mass normalized waveform shown and described above). This results in essentially random positioning of the damping elements and therefore in relatively low damping efficiency.

In addition to determining the position of the damper at the location of ineffective damping, more than one HFTO mode is often present during a drilling operation. Each oscillation mode has a corresponding characteristic frequency and oscillation shape with different local maxima and minima (depending on the wavelength). If HFTOs are likely to occur in more than one mode (which is typically the case), it is preferable that all (or most) of these modes be sufficiently damped.

In fig. Figure 23 shows the mass-normalized mode shapes of some examples of HFTO BHA modes (top graph) and normalized damping (normalized to maximum damping value at distance from bit = 0) for vibration modes (bottom graph) as a function of distance from bit. The top graph in Fig. 23 shows that at least four vibration modes are generated for a given BHA, corresponding to frequencies of 162 Hz, 216 Hz, 270 Hz and 324 Hz. The maximums and minimums of the four vibration modes are located in different positions. For example, the first maximum of the 324 Hz mode is approximately 10 m from the bit, while the first maximum of the 270 Hz mode is approximately 6 m from the bit. As shown, with the exception of the drill bit (distance 0), the damping varies with distance from the bit, but is always less than 25% of the maximum damping and is therefore quite small. Thus, embodiments of the present invention are directed to optimizing the placement of one or more dampers at effective positions along or preferably at the top of the BHA to effectively dampen or reduce all high frequency torsional vibration modes of the BHA. For example, depending on the position of one or more dampers relative to the BHA (for example, if one or more dampers are located outside the BHA or at the top or bottom of the BHA), it may preferably be possible to use a damper element or a sub with a damper element without an electrical connection and/or or a damper element or damper element sub that does not have a wire connection from the top to the bottom of the damper element or damper element sub.

Embodiments of the present invention relate to the placement of dampers and adjustment of vibration modes to obtain acceptable damping of all modes of vibration that are likely to occur during drilling with a particular BHA design. To cover all potential vibration modes, the damping elements do not need to be located at the maximum position of each vibration mode to provide sufficient damping, but can be placed at positions that exhibit acceptable vibration mode amplitudes. In this way, a compromise is reached for all oscillation modes and positioning options, together with the selection of applicable

- 20 045677 elements for adjusting the vibration shape (for example, flexible sections and sections of significant mass) to enhance and concentrate the local maximum in certain positions. Assuming the susceptibility or severity of certain modes of vibration, weighting of certain modes can be carried out to optimize the damping of the selected or target modes.

In fig. 24A-C are schematic diagrams illustrating the placement of a damper on a drill string and/or BHA. In fig. 24A-C show the placement of a single damper for one mode of high-frequency torsional vibrations. However, it should be understood that the described method can be applied to any number of damper elements and vibration modes. In fig. 24A, a random damper placement is applied, and such random placement allows damping D to be achieved at only approximately 20% of the maximum possible damping when the damper is in the optimal position in a non-optimized BHA (e.g., a BHA that is not optimized in terms of dimensions such as length or diameter, material and/or mechanical properties such as stiffness, flexibility, mass, moment of inertia, density or modulus of elasticity (shear and bulk), and in terms of positioning/location). Although the mass-normalized vibration mode deviation is only slightly less than 50% compared to the optimal positioning, the resulting damping is significantly less due to the quadratic positioning relationship (mass-normalized mode shape φ( _i ,j)) for vibration mode i and position j on the damping effect (D is proportional to φ( _i ,j) ² ). This relationship is described in US Patent No. 9,976,405 incorporated above.

One way to optimize damper placement is to vary the length of various elements of the drill string in the vicinity of the damper. For example, by extending the pipe, the damper can be moved toward the maximum mode shape (shown in FIG. 24B), resulting in an increased damping effect (ie, an optimal position within the original BHA). The length of the elements can be increased by including one or more shape-tuning elements in the column and/or replacing a conventional column element with a mode-shaping element. The resulting damping can reach an efficiency of up to 100% (i.e., complete damping of a given HFTO mode due to the placement of the damper and the tuning/shifting of the mode shape due to the mode tuning elements).

In addition to changes in length, one or more mode shape adjustment elements can be applied to change the moment of inertia of the column. This allows for a local increase in the amplitude of the vibration mode(s) by combining the compliant and high-inertia components of the drill string. In fig. 24C shows the position of the damper in a BHA when the two components have been changed in length and diameter (i.e., replaced by shape trimmers) compared to the maximum damping without the shape trimmers, with the damper position resulting in a value of 140% of maximum damping of a BHA that is not optimized in terms of dimensions such as length or diameter, material and/or mechanical properties such as stiffness, flexibility, mass, moment of inertia, density or modulus of elasticity (shear and bulk), and positioning/ location. Thus, the use of elements to adjust the vibration mode for an element of a specific length and diameter in order to optimize the position relative to the maximum of a given vibration mode makes maximum damping of more than 100% possible.

The waveform adjustment elements of the present invention provide local changes in the properties of the drill string and/or BHA. Shape trim elements can be used as additional string elements or can be used as replacements for standard string or BHA components. Waveform trim elements provide the ability to select diameter, length, density, modulus of elasticity, material, geometric shape, cross-sectional geometric properties, etc. to adjust or offset the waveform and thus allow dampers to be applied at specific locations to achieve maximum damping efficiency. The use of mode shape adjustment elements can result in local changes in mode shapes (e.g., amplitude) in one, several (e.g., critical modes), or all modes at the damper location, as well as the entire mode (e.g., on a drill bit) . In addition, the use of waveform adjustment elements may change the frequency of one, several, or all modes of vibration (eg, modes of vibration may become critical or non-critical). In addition, waveform tuning elements may change the excitability of one, several, or all modes of vibration (eg, modes of vibration may become critical or non-critical). For example, a combination of torsionally compliant type waveform tuning elements (eg, coiled tubing) combined with components having high inertia (eg, sections of significant mass) and varying lengths can enhance the amplitude of the waveform at the damping element position.

For this reason, the optimization methods of the present invention can be applied to

- 21 045677 definition of damping achieved by one or more dampers in relation to different vibration modes. By changing local components (eg, by replacing components with one or more mode-shaping elements), the location affects not only the damping effect, but also the ability to excite critical modes of vibration.

Optimization methods that may be applied in accordance with embodiments of the present invention may include analysis/calculation/simulation (eg, numerical simulation) of one or more HFTO modes for a BHA or drilling system to determine the maximum mode shape or damping efficiency. At the second stage, a damper and/or an element for adjusting the vibration shape with a given characteristic can be selected. Such characteristics may include, but are not limited to, dimensions such as length or diameter, material and/or mechanical properties such as stiffness, flexibility, mass, moment of inertia, density or modulus of elasticity (shear and bulk). A position will be selected where a damper and/or a shape trimmer will be added to the BHA to produce a modified BHA. In the next step, analysis/calculations/modeling (e.g., numerical simulation) will be performed on the modified BHA to evaluate one or more HFTO modes of the modified BHA to determine the modified maximum mode shape or modified damping efficiency. If the modified BHA meets a criterion (e.g., a pre-selected criterion such as a threshold value that is related to the maximum mode shape, excitation ability, mode derivative, damping efficiency, or amplitude difference between two mode shapes), then the modified BHA can be applied to drilling a section of a wellbore in the specified formation. Otherwise, the modified BHA can be further modified by adding/removing/moving damper(s) and/or a waveform trim element with a given characteristic until the criterion is achieved. Thus, the preferred placement and selection of dampers and shape-tuning elements can be determined through an iterative process.

In an additional or alternative embodiment, the preferred placement and selection of dampers and shape-tuning elements can be determined using a (numerical) inversion method. Such an inversion method may include, for example, an automated or semi-automated inversion method. Additionally, in an additional or alternative embodiment, the preferred placement and selection of dampers and waveform trim elements may be determined using optimization techniques, which may include, but is not limited to, gradient-based optimization. Such gradient-based optimization may involve the Nelder-Mead method. As will be appreciated by those skilled in the art, other possible optimization methods are Monte Carlo models, Levenberg-Marquardt optimization, genetic algorithm, simulated normalization, least squares algorithm, ant colony optimization algorithm, conjugate gradient method, Krylov subspace method, biconjugate gradients or any other optimization method. Optimization criteria or a penalty function are set primarily to maximize damping, but limited optimization based on geometric factors or a set of predefined waveform tuning elements or other constraints can also be applied. Advantageously, during optimization, one, several or all vibration modes can be weighted using a weighting factor or weighting function, for example to determine optimization criteria or a penalty function. It should be understood that both the adjustment of the mode shape and the location and influence of the damping elements can be taken into account when designing the layout/configuration.

Let us now turn to FIG. 25, which shows the mode shapes as well as the normalized minimum damping of the four (4) modes of vibration. In the configuration used for illustration in FIG. 25, the BHA uses one or more waveform adjustment elements to shift or change the location of the peak (eg, compared to that shown in FIG. 23). As shown in FIG. 25, at a distance of approximately 7.5 m from the drill bit, a minimum normalized damping of greater than 60% can be determined for all vibration modes. Thus, this position is very suitable for stabilizing all vibration modes. Accordingly, through the use of vibration mode adjustment elements, the maximum position of a plurality of different vibration modes can be substantially aligned, allowing a damper (or multiple dampers) to reduce high-frequency torsional vibrations of the column.

Moreover, as shown in FIG. 25, if it is necessary to install not one but two dampers in the drill string, the position 18 m from the drill bit can also be considered as suitable due to the alignment with the other maximum. However, the minimum normalized damping at the new position (18 m) may be small compared to the damping at the 7.5 m position, and a combination of both positions may provide improved damping compared to a single damping system. Two vibration modes (at 218 Hz and 263 Hz) have high mode shape deviations at the 7.5 m position, and two vibration modes (160 Hz and 317 Hz) have high mode shape deviations at the 18 m position. As a result, the placement of damper elements at positions 7.5 m and 18 m from the drill bit can lead to damping in all vibration modes.

To provide mode control, one or more structural elements may be added to the drill string or BHA, or they may be used to replace a standard part with a modified part that is a mode control element. Thus, by incorporating one or more waveform adjustment elements, the tool string (i.e., drill string plus BHA) can be adapted such that one or more peaks associated with the HFTO can be shifted in position and a plurality of different peaks can be shifted to one position or to close approximation to one location so that a single damper element can be used to damp HTFOs with different vibration modes or orders. The waveform adjustment elements may include, for example, a section of metal pipe with a selected or predetermined length, diameter, and/or geometric properties that is attached to the drill string in close proximity to the BHA. This mode-shaping element can introduce additional mass and/or flexibility (or inflexibility) into the drill string at its attachment point, thereby changing (and shifting) the high-frequency torsional vibration peak of the system. Based on this offset, a damper element may be installed to dampen one or more selected HFTO modes.

An advantage is that waveform adjustment elements added to a section of the drillstring, outside, near, in the assembly or on the BHA can be applied to shift the position of the HFTO peak and allow one or more damper elements to provide increased damping efficiency. The position of the waveform elements relative to the BHA may provide the preferred use of waveform elements without electrical connection and/or waveform elements that do not have wire connections from the top to the bottom of the said mode element. The operational properties of the used damper elements can be significantly improved by including elements for adjusting the vibration shape, which, in turn, can lead to a reduction in the number of damper elements. In addition, such optimization or improved efficiency may result in the use of smaller and/or lower cost damping elements and more effective damping under various vibration modes.

It should be understood that embodiments of the present invention are directed not only to improving the location of the damper taking into account a particular vibration mode. Namely, embodiments of the present invention are directed to changing the properties of drill strings and/or the composition of the BHA or area in close proximity thereto. Such modifications improve the performance of installed dampers in accordance with positioning and mode modification (ie, mode adjustment, adjustment and/or displacement). By changing one or more characteristics or properties (eg, length, diameter, density, geometry, etc.) of the column for one or more HFTO modes, improved damping (eg, greater than 100%) can be achieved.

In fig. 26A-26B are illustrations of a well string 2600 having two dampers. In fig. 26A is a schematic representation of the design of the well string 2600, and FIG. 26B shows waveforms modified or tuned using waveform trim elements 2602. As shown in this embodiment, two damper elements 2604 are provided, positioned at an offset maximum such that a plurality of high frequency torsional vibration modes can be covered by the damper elements 2604. In this illustration, the well string 2600 is an example of a BHA having damping elements 2604 installed thereon. BHAs are subject to critical vibration conditions and, therefore, damping such vibrations is preferred. In all BHA configurations, only a few waveform trim elements 2602 (eg, coiled tubing segments and heavy mass tubing segments) are required to achieve maximum damping effect from the installation of damper elements 2604.

In accordance with some embodiments of the present invention, it may be possible to consistently achieve a specific response for all HFTO modes in a position through the use of certain components (e.g., waveform trim elements, special damper elements, separating devices, etc.) . For example, separating devices are shown and described in joint US patent application No. 2019/0284882A1, entitled Dampers for reducing vibration of downhole tools and a device for isolating vibrations on a bottom hole assembly, joint US patent application No. 62/899,331, entitled Shock-absorbing coupling coupling designed to reduce high-frequency torsional vibrations in the drill string, joint U.S. patent application no.

- 23 045677

62/899,332, entitled Shock Absorbing Coupler for Attenuating Vibrations in a Drill String, which is incorporated herein by reference in its entirety. Additionally, it should be understood that such adjustments and waveform shifts are not limited to friction dampers. For example, in accordance with some embodiments of the present invention, damping principles based on stiffness properties may be applied. The optimal location when applying damping principles based on stiffness properties does not depend on the amplitude of the vibration mode, but on its derivative. Thus, for damping based on stiffness properties, the difference between two mode amplitudes (mode shape difference) can be taken into account. The optimum for damping based on stiffness properties are nodes, since the relative displacement is greatest in them.

As mentioned above, in addition to adding length and/or mass in the form of shape-tuning elements, said mode-shaping elements in accordance with the present invention may provide other modifications to the string and/or BHA so that the mode shape is shifted or adjusted to a specific position, thereby increasing the efficiency of damping elements installed on or as part of the string and/or BHA. For example, elongation of the tubular segments may be applied to increase the flexibility of the column, modification in shape or geometric characteristics (other than diameter changes), changes in density and/or elastic modulus may be applied to achieve a shift in the HFTO mode shape, or other properties may be modified or adapted. columns/BHA. Thus, a combination of shape-tuning elements and damping elements can be used as part of a downhole system to improve the damping efficiency of the HFTO and reduce tool vibration, and thus the associated adverse effects can be reduced, prevented or eliminated.

In fig. 27-28 are schematic illustrations of the damper elements 2700, 2800. The damper elements 2700, 2800 are configured to be mounted within the blade of the disintegration device as described above. Each damper element 2700, 2800 includes a corresponding housing 2702, 2802 for housing and containing components of the respective damper elements 2700, 2800. The first damper element 2700 has a substantially rectangular geometric configuration (with curved corners), and the second damper element 2800 has a substantially circular geometric configuration. configuration The housings 2702, 2802 are configured to be installed in the blade of the disintegration device (for example, as shown in Fig. 26).

Each of the damping elements 2700, 2800 contains a mass element 2704, 2804, mounted movably inside the housings 2702, 2802. The mass element 2704, 2804 is located between the mounting element 2706, 2806 and the contact element 2708, 2808. The mounting elements 2706, 2806 are made with the ability to apply a force to the corresponding mass element 2704, 2804 towards the contact elements 2708, 2808. Thus, frictional contact can be achieved between the corresponding mass element 2704, 2804 and the contact elements 2708, 2808. The mass elements 2704, 2804 may be positioned with one or more stops 2710, 2810 within respective housings 2702, 2802.

The stops 2710, 2810 may include optional stiffness or hydraulic elements to dampen the movement of the mass elements 2704, 2804.

In addition, the stops 2710, 2810 may prevent the mass elements 2704, 2804 from becoming stuck on one edge of the housing 2702, 2802. The stops 2710, 2810 may be provided with springs or other elements to prevent damage to the mass elements 2704, 2804 and press the mass elements 2704 , 2804 to the middle position or resting position relative to the body. In some embodiments, it may be preferable to optimize the spring rate and/or clearance in the housing 2702, 2802 to allow the mass elements 2704, 2804 to move within the housing 2702, 2802. The damping elements 2700, 2800 may be arranged as inserts (e.g., housing 2702 , 2802 is designed to be installed). Insertable damper elements 2700, 2800 may be installed such that the mass elements 2704, 2804 are placed at a high radius position relative to the axis of the drilling system to increase rotational inertia.

The mounting member 2706, 2806 is configured to apply a normal force to the mass members 2704, 2804 (eg, a force that is perpendicular to the mounting member 2706, 2806 or the mass members 2704, 2804). For example, the mounting element 2706, 2806 may be arranged as spring housings to press the mass elements 2704, 2804 into contact with the contact element 2708, 2808. In addition, the mounting elements 2706, 2806 and/or contact elements 2708, 2808 may be configured to control tangential movement of mass elements 2704, 2804 to provide HFTO damping. In some embodiments, the mounting elements 2706, 2806 press the mass elements 2704, 2804 into contact with the contact element 2708, 2808 to create a frictional force. The frictional force is applied, for example, through a material that is useful relative to the coefficient of friction and expected

- 24 045677 wear, which should be as low as possible.

In accordance with embodiments of the present invention, damping means may be integrated into the drill bit or other location on the drill string (eg, near or within the BHA). Damping can be applied by any axial, tangential and/or radial force or suitable torque capable of dissipating energy. In the case of coupled vibration modes, damping forces in the axial direction are also capable of dissipating energy away from the torsional direction. Bonding can also be achieved kinetically, for example through bit-rock interaction. As described for frictional damping, contact surfaces applied with coefficient of friction and normal force can be optimized and/or selected to dampen one or more critical mode shapes. In some embodiments, beneficial materials or designs may be used to prevent wear (eg, copper or polycrystalline diamond bits). To configure a system with an advantageous friction coefficient or characteristic, a variety of contacts with different properties can be used.

Another form of damping that can be used is hydraulic damping. Such hydraulic damping may be provided by a system either in or near the bit blades or elsewhere on the drill bit or disintegration device, or along the length of the BHA or well string. One example of a hydraulic damper is shown and described in US Cooperative Patent Application No. 62/899,291, entitled Viscous Torsional Vibration Damping, which is incorporated herein by reference in its entirety. In some such embodiments, viscous fluid (eg, viscous fluid in chambers) may be located and mounted in similar positions as described above. In some such applications, fluid (shear) stresses between the inertial ring/mass and the drill bit may be selected to achieve a (damping) force that acts in the direction of tangential acceleration and associated harmonic displacement to damp torsional vibrations, such as HFTO. drilling system. In the case of annular shear, the fluid provides a damping force between the inertial ring/mass and the drill bit. In this case, the ring may require a closed housing and possibly a well-defined geometric configuration of the gaps between the ring and the housing. In hydraulic damping, viscous damping forces are sensitive to changes in clearance parameters and viscous fluid. Thus, a liquid that is insensitive to temperature or a liquid that is less sensitive to temperature may be preferred. To achieve a useful regime, fluids with different shear stresses can be used depending on the shear rate. Examples of such fluids include, but are not limited to, Newtonian fluids, dilatant fluids (eg, shear thickening fluids), pseudoplastic fluids, Bingham plastic fluid, Bingham pseudoplastic fluids, etc. Preferably, solids may be added to the liquid to achieve liquid dispersion behavior.

Additionally, in some embodiments, magnetic damping may be used. Magnetic damping can be achieved by using a permanent magnet (eg mounted on an inertial ring/mass) that is capable of moving relative to the coil and which can be used to dampen the HFTO. Depending on the magnet principle, the damping force characteristic may be similar to a hydraulic force (for example, in the case of eddy currents) or a frictional force (hysteresis). In some such configurations, the force will act in the direction of the tangential acceleration or in any other direction that may result in damping in the circumferential direction or in the direction to be damped.

Additionally, in some embodiments, piezoelectric damping principles may be applied to prevent torsional vibrations such as HFTO in a drill bit or drill string. A piezoelectric material may be applied, attached to the inertial ring/mass on one side, and to a section of the well string on the other side. The electrodes of the piezoelectric material may be connected to a circuit including coils, resistors and capacitors, or semi-active or active components. A combination of electrical components can be used to achieve beneficial damping characteristics between the inertial ring/mass and the well string components. The circuit can be adjusted to the free vibration frequency of the system to act as a tuned damper (i.e., for one or more desired vibration modes). The resistor may be configured to directly dissipate energy if the piezoelectric block is deformed by the relative force acting between the inertial ring/mass and the well string component. Additionally, the stiffness of the piezoelectric material and the inertial ring/mass can also be tuned to a specific frequency. Piezoelectric material electrodes may be configured to damp torsional vibrations. The direction of the damping forces may differ from the direction of the electrodes due to the effect of favorable conversion of mechanical force into an electrical signal, which is provided

- 25 045677 design of the piezoelectric element. Well-known effects of piezoelectric coefficients are D ₃₃ (in the direction of force), D ₃₁ (perpendicular to the direction of force) and D ₁₅ (shear stress). The piezoelectric material can be placed to optimize or control the coupling between the mechanical and electrical system for a particular mode shape or multiple mode modes that are critical to HFTO. In addition, various materials in which mechanical force or stress or associated loads are converted into electrical signals can be used without departing from the scope of the present invention.

Additionally, internal damping and resulting material forces can be applied to reduce HFTO. Thus, material damping can be achieved in a passive manner due to the damping properties of high damping materials. Some such materials may include, but are not limited to, polymers, elastomers, rubbers, and the like, as well as the damping effect of multifunctional materials such as shape memory alloys. The material properties of some materials, such as shape memory alloys, can be actively influenced or controlled to achieve greater damping effects.

Other damping configurations are possible without departing from the scope of the present invention. For example, negative capacitances and semi-active components can be applied using switching techniques. Additional damping techniques and components may be employed, and the embodiments and variations described above are for illustrative and explanatory purposes and are not intended to be limiting. All damping principles described herein can be adjusted to operate as a tuned damper by adding mechanical springs adjusted to a specific frequency and by adding any type of damping. In addition, one or more of the damping principles described herein (or other methods/mechanisms) can be combined in a multi-base configuration. For example, ring-type dampers or tangential mass/inertial dampers may be installed within or attached to the breaker blades or other locations within the drill string. In addition, magnetic, hydraulic, frictional, piezoelectric, and material damping forces and principles can be combined to achieve a reliable damping effect, for example with respect to temperature.

As described above, one or more damping elements may be incorporated into the drill bit or other disintegration device, or at other locations along the well string or BHA. For example, a bit damper may be located on or near the bit shank. In some configurations, the damper inertia ring may be lubricated with flushing fluid or covered by the coupling structure. In some configurations, a closed or solid ring may be used. In other configurations, partial arcs may be assembled around the wellbore string (for example, they may be installed if the ring cannot be otherwise assembled). In some such embodiments, two semi-circular arcs may be used. In other embodiments, more than two annular arcs may be used to form a full (longitudinal) annular casing structure or a less than full (longitudinal) annular casing structure depending on the particular configuration employed.

In some embodiments, a split ring design may be used in which discrete masses are located behind or adjacent to the drill bit blades. In another example, the complete annular structure may be located adjacent to the blades, but specific additional mass elements or ring elements may be located relative to specific blades of the drill bit. One such example may have a relatively thick ring at the blade position and a lower thickness to allow flow of rock pieces along the drill bit. In addition, such rings may be located at other locations along the well string (eg, BHA).

In some embodiments, a stop may be provided that may prevent the inertial ring/mass from moving freely around the circumference of the drill bit. Such a stop may be provided in embodiments in which a mass or higher mass is located behind or adjacent to particular blades. In such cases, the limiter can ensure that the inertial ring/mass remains in the desired position relative to the blades or that the space in which the inertial ring/mass can move is limited.

It should be understood that radial and/or axial contact forces may be used to generate circumferential frictional forces in the friction-type damping elements of the present invention. Radial frictional forces can be generated by springs, pressure differences, or the elastic structure of the inertial ring or its segments, which may have two or more casings and are prestressed. Axial normal force can be achieved using springs, pressure differences and/or the weight of the inertial ring/mass in a non-horizontal wellbore. The material of the drill bit or other disintegration device may be steel or matrix composite, etc. In some embodiments, a bearing may be used to provide radial movement of the inertia ring/mass. Thus, a bearing may be provided to provide circumferential and/or tangential movement of the damper element. An axial bearing can be used to separate the potential normal force spring assembly from rotational motion.

In some embodiments, as an alternative to or in combination with a ring-type damper element, damper elements may be implemented in or on the blades of a disintegrator, stabilizer, or in or on other components of the well string. In some such embodiments, damper elements may be mounted within housings that screw into blades or recesses, liners, or manhole covers. In some such configurations, one or more stops may be provided to prevent the damper elements from sticking or jamming at the edge or corner of the housing. Contact between the limiting stop and the damper mass may be achieved by means of springs or other biasing elements or structures. In some embodiments, the spring rate or housing clearance may be selected to allow the damper mass to move within the housing and thereby provide vibration damping as described above.

Control elements can also be used that change the contact properties between the contacting elements in the well string. For example, the normal force can be adjusted in the frictional contact. In addition, the normal force or damper efficiency can be measured using load and acceleration or other vibration measuring devices, and adjusted based on these measurements.

Let us now turn to FIG. 29A, B, which schematically depicts various types of waveform adjustment elements. In fig. 29A shows a set of examples of waveform trim elements 2902-2916, and FIG. 29B illustrates a well string 2920 (e.g., a BHA) having various waveform trim elements 2922 (e.g., one or more of the exemplary waveform trim elements 2902-2916) mounted thereon to adjust or offset or reduce one or more HFTO mode peaks. and thus providing damping of such vibrations from the HFTO in the wellbore string 2920.

As shown in FIG. 29A, the waveform adjustment elements may have different sizes. Each of the waveform elements 2902-2916 has a different length and, as shown, the waveform elements 2902, 2904 have large diameters and can be configured as weight-added (ie, having significant mass) waveform elements. In contrast, the waveform trim elements 2906, 2908, 2910, 2912, 2914, 2916 have a smaller diameter and can provide flexibility to the column to which they are attached (ie, coiled tubing). The waveform trim elements 2902-2916 may also vary in torque stiffness. Also in FIG. 29A shows a sub 2918 with a damper element. A well string, such as the well string 2920 shown in FIG. 29B may be configured with one or more waveform adjustment elements to allow one or more HFTO peaks to be shifted and then provide improved damping provided by the damper element sub 2918.

As shown in FIG. 29B, the well string 2920 includes a motor 2924, one or more waveform control elements 2922 (which, for example, may be selected from the waveform control elements 2902-2916 shown in FIG. 29A), a damper element sub 2918, flexible a stabilization sub 2926, a set of drilling elements 2928 (eg, measurements while drilling, logging while drilling, a guide mechanism, etc.) and a disintegration device 2930 (eg, a drill bit) located at its end. Incorporation of waveform trim elements 2922 into the well string 2920 allows one or more HFTO peaks to be adjusted or offset, whereby HFTO can be reduced when the elements are located within a BHA that is sensitive to HFTO. In addition, the inclusion of waveform trim elements 2922 in the wellbore string 2920 allows one or more HFTO peaks to be tuned or offset, that is, the location of the damping element sub 2918 can be optimized to dampen such vibrations.

Accordingly, embodiments of the present invention relate to determining the position of a damping system, such as a ring-type damper or a tangential damper, within a well string, that is, near or within a drill bit or other disintegration device, or at other specific locations within/on/along well string. By locating the damping system at specific locations within/on/along the well string (eg, in the guide mechanism, in the drill bit, or other locations), improved damping of HFTO or other vibration modes can be achieved. In addition, the mode control elements may be configured to place one or more damping elements at or near the end of the drill string, at the end of the BHA, in the immediate vicinity or on the drill bit (for example, within 10 m of the drill bit). bit, for example, within 5 m of the drill bit or even within 3 m of the drill bit), at one or more peaks of one or more modes, or at one or more nodes of the modes to effectively provide damping of one or more HFTO modes with one damping element. Thus, as described herein, a maximum number of different HFTO modes can be aligned (tuned) to provide an optimal location of the damping element to dampen one or more HFTO modes and thereby reduce downhole system vibrations.

Embodiment 1. A system for damping high frequency torsional vibration (HFTO) of a downhole system, the downhole system comprising: a downhole drilling system located at an end of the downhole system in operative connection with a drill bit; a damping system mounted on the downhole drilling system, said damping system comprising at least one damping element configured to damp at least one HFTO mode; and at least one waveform adjusting element located on the drilling system, wherein said at least one waveform adjusting element is located on the drilling system and is configured to change at least one of: HFTO mode shape, HFTO mode frequency, excitation ability HFTO mode and damping efficiency of at least one damping element.

Embodiment 2. The system of any preceding embodiment, wherein the at least one mode shape control element is located on the drilling system and is configured to change the shape of the HFTO mode at the location of the at least one damper element.

Embodiment 3. The system of any preceding embodiment, wherein the at least one waveform element is selected based on at least one of: the size of the at least one waveform element, the material properties of the at least one waveform element and mechanical properties of at least one vibration shape adjustment element.

Embodiment 4. The system according to any preceding embodiment, wherein the location of at least one mode tuning element on the drilling system is selected to at least one of the HFTO mode mode shape modifications in the position of the at least one damping element and optimizing the damping efficiency of at least at least one damping element.

Embodiment 5. The system of any preceding embodiment, further comprising a plurality of shape control elements, of which at least one mode control element is selected for placement on the drilling system.

Embodiment 6. The system of any preceding embodiment, wherein at least one waveform control element is selected for placement on the drilling system based on a HFTO numerical simulation of at least a portion of the well system.

Embodiment 7. The system according to any preceding embodiment, wherein at least one of at least one damping element and at least one waveform adjusting element is located and/or selected based on numerical inversion.

Embodiment 8. The system as in any preceding embodiment, wherein the damping system is at least one of a viscous damping system, a frictional damping system, a hydraulic damping system, a magnetic damping system, and a piezoelectric damping system.

Embodiment 9. The system of any preceding embodiment, further comprising a separating element.

Embodiment 10. The system as in any of the preceding embodiments, wherein at least one damping element is located within 10 meters of the drill bit.

Embodiment 11. A method for damping high frequency torsional vibration (HFTO) of a downhole system, wherein the method comprises: drilling with a downhole drilling system into the subsurface of the earth, wherein said downhole drilling system is in operative connection with a drill bit and contains a damping system that includes at least one damping element and at least one waveform adjustment element located on the drilling system; selecting a configuration and arrangement of at least one drilling system waveform adjustment element to change at least one of the HFTO mode shape, the HFTO mode frequency, the HFTO mode excitation ability, and the damping efficiency of the at least one damping element; and damping the at least one HFTO mode with the at least one damping element.

Embodiment 12. The method of any preceding embodiment, wherein the at least one waveform control element is located on the drilling system and is configured to change the shape of the HFTO mode at the location of the at least one

- 28 045677 damper element.

Embodiment 13. The method of any preceding embodiment, further comprising selecting at least one waveform control element for placement in the drilling system based on at least one of: the size of the at least one waveform control element, the material properties of at least at least one vibration shape adjustment element and mechanical properties of at least one vibration shape adjustment element.

Embodiment 14. The method of any preceding embodiment, further comprising selecting a position of at least one mode shape adjustment element on the drilling system for at least one of modifying the mode shape of the HFTO at the position of the at least one damping element and optimizing the damping efficiency of at least at least one damping element.

Embodiment 15. The method of any preceding embodiment, further comprising selecting at least one waveform control element from a plurality of waveform control elements for placement in the drilling system.

Embodiment 16. The method of any preceding embodiment, further comprising: performing a HFTO numerical simulation of at least a portion of the well system; and selecting at least one waveform control element for placement in the drilling system based on the HFTO numerical simulation of a portion of the well system.

Embodiment 17. The method as in any preceding embodiment, further comprising: performing a numerical inversion and at least one of positioning and selecting at least one of: at least one damper element and at least one mode shape adjustment element based on numerical inversion.

Embodiment 18. The method as in any preceding embodiment, wherein the damping system is at least one of a viscous damping system, a frictional damping system, a hydraulic damping system, a magnetic damping system, and a piezoelectric damping system.

Embodiment 19. The method as in any preceding embodiment, wherein the downhole drilling system further comprises a separating element.

Embodiment 20. The method as in any preceding embodiment, wherein at least one damping element is located within 10 m of the drill bit.

Embodiment 21. A system for damping torsional vibrations of downhole systems, the system comprising: a drilling system comprising a bottom hole assembly located at the end of the drill string; at least one waveform control element located on the drilling system, said at least one waveform control element configured to shift the location of one or more high frequency torsional vibration (HFTO) peaks; and a damping system provided on the drilling system, wherein said damping system comprises at least one damping element located closer to the offset location of one or more peaks than without the mode shape adjustment element located on the drilling system.

Embodiment 22. The system of any preceding embodiment, wherein the at least one waveform control element is a section of pipe having at least one of a predetermined size, such as a predetermined length or a predetermined diameter, a material and/or a predetermined mechanical properties such as specified stiffness, specified flexibility, specified weight, specified moment of inertia, specified density or specified modulus of elasticity (shear and bulk), and specified positioning/disposition.

Embodiment 23. The system of any preceding embodiment, wherein the damping system comprises a damping element sub that includes at least one damping element.

Embodiment 24. The system as in any one of the preceding embodiments, wherein the damping system is configured to provide at least one of viscous damping, frictional damping, hydraulic damping, piezoelectric damping, eddy current damping, and magnetic torsional damping of the drilling system.

Embodiment 25. A method for damping torsional vibrations of a downhole system in a wellbore, the method comprising: installing at least one mode control element on the drilling system, wherein the at least one mode control element is configured to shift the location of one or more peaks high-frequency torsional vibration (HFTO) mode of the drilling system; and installing a damping system on the drilling system, wherein said damping system comprises at least one damping element located closer to the offset maximum location than would be the case without the waveform adjustment element mounted on the drilling system.

- 29 045677

Embodiment 26. The method according to any preceding embodiment, wherein the at least one waveform tuning element is a section of pipe having at least one of a predetermined size, such as a predetermined length or a predetermined diameter, a material and/or a predetermined mechanical properties such as specified stiffness, specified flexibility, specified weight, specified moment of inertia, specified density or specified modulus of elasticity (shear and bulk), and specified positioning/disposition.

Embodiment 27. The method of any preceding embodiment, wherein the damping system comprises a damping element sub that includes at least one damping element.

Embodiment 28. The method as in any one of the preceding embodiments, wherein the damping system is configured to provide at least one of viscous damping, frictional damping, hydraulic damping, piezoelectric damping, eddy current damping, and magnetic torsional damping of the drilling system.

Various analysis components, including digital and/or analog systems, can be used to support the ideas presented in this paper. For example, controllers, computer processing systems, and/or geonavigation systems provided herein and/or used with the embodiments described herein may include digital and/or analog systems. Systems may have components such as processors, storage media, storage, inputs, outputs, communication lines (e.g., wired, wireless, optical, or others), user interfaces, software products, signal processors (e.g., digital or analog), and others. similar components (eg, such as resistors, capacitors, inductors, and others) to enable operation and analysis of the apparatus and methods described herein in any of several methods well established in the art. It is believed that these ideas may, but are not necessarily, implemented in combination with a set of computer-executable instructions stored in a non-volatile computer-readable medium, including a storage device (e.g., ROM, RAM), an optical device (e.g., CD-ROM), or a magnetic device (eg, disks, hard drives) or any other type of device that, when executed, causes a computer to implement the methods and/or processes described herein. These commands may provide equipment operation, control, data collection, analysis, and other functions deemed relevant by the system designer, owner, user, or other similar personnel, in addition to the functions described herein. The processed data, such as the result of the implemented method, can be transmitted as a signal via the output interface of the processor to the signal receiving device. The signal receiving device may be a screen monitor or a printer to present the result to the user. Alternatively or additionally, the signal receiving device may be a storage device or storage medium. It should be understood that storing a result in a storage device or storage medium may convert the storage device or storage medium to a new state (ie, containing the result) from a previous state (ie, not containing the result). Additionally, in some embodiments, an alert signal may be sent from the processor to the user interface if the result exceeds a threshold value.

In addition, various other components may be included and described to provide aspects of the ideas presented herein. For example, a sensor, transmitter, receiver, transceiver, antenna, controller, optical unit, electrical unit, and/or electromechanical unit may be included in support of various aspects described herein or in support of other functions that deviate from the scope of the present disclosure.

The use of the singular and plural forms and similar references in the context of the specification (especially in the context of the claims below) are to be understood to include both the singular and plural unless otherwise indicated herein or unless clearly inconsistent with the context. Additionally, it should be noted that the terms first, second, etc. herein do not imply any order, quantity or importance, but are used to distinguish one element from another. The definition of about, when used in connection with a quantity, includes a specified quantity and has a meaning determined by the context (for example, it includes the degree of error associated with measuring a certain quantity).

It should be understood that various components or technologies may provide certain necessary or useful functionality or features. Accordingly, these functions and features, which may be required to support the appended claims and variations thereof, are recognized as inherently part of the teachings presented herein and part of the present invention.

The ideas presented herein can be used in a wide variety of well operations. These activities may include the use of one or more treatment agents to treat the formation, fluids present in the formation, the wellbore and/or equipment.

- 30 045677 in the wellbore, such as production tubing. Treatment agents may be in the form of liquids, gases, solids, semi-solids and mixtures thereof. Examples of treatment agents include, but are not limited to, fracturing fluids, acids, steam, water, brine, anti-corrosion agents, cement, permeability modifiers, drilling fluids, emulsifiers, demulsifiers, indicators, anti-turbulence additives, and the like. Examples of well operations include, but are not limited to, hydraulic fracturing, stimulation, tracer injection, cleaning, acidizing, steam injection, waterflooding, cementing, and the like.

Although the embodiments described herein have been described with reference to various embodiments, it should be understood that various changes and substitutions of equivalent elements may be made without departing from the scope of the present invention. Moreover, many modifications will be understood to adapt a particular tool, situation, or material to the teachings of the present invention without departing from the scope thereof. Thus, the present invention is not intended to be limited to the specific embodiments described as the best embodiment provided for implementing the described features, but the present invention is intended to include all embodiments falling within the scope of the claims.

Accordingly, embodiments of the present invention should not be construed as being limited by the above description, but instead are limited only by the scope of the appended claims.

Claims (15)

1. A system for damping high-frequency torsional vibrations (HFTO) of a downhole drilling system (10), equipped with a drill bit located at its end, containing a damping system (70°, 1000, 1200, 1300, 1400, 1500, 1600, 1700, 1800, 1900 ) installed on the downhole drilling system (10), wherein said damping system (700, 1000, 1200, 1300, 1400, 1500, 1600, 1700, 1800, 1900) contains at least one damping element (2604, 2700, 2800) , configured to damp at least one mode of high-frequency torsional vibrations; and at least one element for adjusting the vibration shape (2602, 2902, 2904, 2906, 2908, 2910, 2912, 2922), located on the downhole drilling system (10) and performed, based on the results of preliminary analysis/calculations/modeling of one or more HFTO modes for the bottom hole assembly (BHA) or drilling system in order to determine the effectiveness of damping, in the form of a component separate from the damping element, placed on the downhole drilling system (10) as an additional component or replacement of a component of a string or bottom hole assembly (BHA), wherein at least one waveform adjustment element (2602, 2902, 2904, 2906, 2908, 2910, 2912, 2922) is configured to change at least one of HFTO mode shapes, HFTO mode frequency, HFTO mode excitation ability. 2. The system according to claim 1, in which at least one waveform adjustment element (2602, 2902, 2904, 2906, 2908, 2910, 2912, 2922) is configured to enhance the HFTO mode at the location of at least one damping element (2604, 2700, 2800) on the downhole drilling system. 3. The system according to any of the preceding paragraphs, in which at least one element for adjusting the vibration shape (2602, 2902, 2904, 2906, 2908, 2910, 2912, 2922) is made in the form of a pipe section and is selected based on at least one of: the size of at least one waveform control element (2602, 2902, 2904, 2906, 2908, 2910, 2912, 2922), the material properties of at least one waveform control element (2602, 2902, 2904, 2906, 2908, 2910, 2912, 2922) and mechanical properties of at least one waveform adjustment element (2602, 2902, 2904, 2906, 2908, 2910, 2912, 2922). 4. The system according to any of the preceding paragraphs, in which the location of at least one mode adjustment element (2602, 2902, 2904, 2906, 2908, 2910, 2912, 2922) on the downhole drilling system (10) is selected with the possibility of modifying the mode shape HFTO in position of at least one damper element (2604, 2700, 2800) on the downhole drilling system. 5. The system as claimed in any one of the preceding claims, further comprising a plurality of waveform control elements (2602), of which at least one waveform control element (2602, 2902, 2904, 2906, 2908, 2910, 2912, 2922) is selected for placement on the downhole drilling system (10). 6. The system as claimed in any one of the preceding claims, wherein at least one waveform control element (2602, 2902, 2904, 2906, 2908, 2910, 2912, 2922) is selected for placement on the downhole drilling system (10) based on numerical simulation HFTO of at least a portion of the well system (1002), preferably at least one of at least one - 31 045677 th damper element (2604, 2700, 2800) and at least one vibration shape adjustment element (2602, 2902, 2904, 2906, 2908, 2910, 2912, 2922) are located, executed and/or selected based on numerical inversion . 7. The system as claimed in any one of the preceding claims, wherein the damping system (700, 1000, 1200, 1300, 1400, 1500, 1600, 1700, 1800, 1900) is at least one of a viscous damping system, a friction damping system, a hydraulic damping system, magnetic damping system and piezoelectric damping system. 8. The system according to any of the preceding claims, further comprising a separating element. 9. A system as claimed in any one of the preceding claims, wherein at least one damper element (2604, 2700, 2800) is located within 10 m of the drill bit. 10. A method for damping high-frequency torsional vibrations (HFTO) of a well system (10), including preparing at least one vibration shape adjustment element (2602, 2902, 2904, 2906, 2908, 2910, 2912, 2922), performed based on the results of a preliminary analysis /calculation/simulation of one or more HFTO modes for the assembly of the bottom hole string (BHA) or drilling system in order to determine the effectiveness of damping, in the form of a component separate from the damping element, placed on the downhole drilling system (10) as an additional component or replacement for a string component or bottom hole assembly (BHA), wherein the choice of configuration and location of said at least one vibration shape adjustment element (2602, 2902, 2904, 2906, 2908, 2910, 2912, 2922) on the downhole drilling system (10) is carried out to change at least one of HFTO mode shape, HFTO mode frequency, HFTO mode driving ability; drilling with the help of a borehole drilling system (10) of the subsoil of the earth, and the specified borehole drilling system (10) is equipped with a drill bit and contains a damping system (700, 1000, 1200, 1300, 1400, 1500, 1600, 1700, 1800, 1900), which includes at least one damping element (2604, 2700, 2800) and said at least one waveform adjustment element (2602, 2902, 2904, 2906, 2908, 2910, 2912, 2922) located on the downhole drilling system ( 10); and damping the at least one HFTO mode using at least one damping element (2604, 2700, 2800). 11. The method according to claim 10, further comprising selecting at least one vibration shape adjustment element (2602, 2902, 2904, 2906, 2908, 2910, 2912, 2922), made in the form of a pipe section, for placement as part of a downhole drilling system (10) based on at least one of: the size of the at least one waveform control element, the material properties of the at least one waveform control element, and the mechanical properties of the at least one waveform control element. 12. The method according to any one of claims 10, 11, further comprising the location of at least one vibration shape adjustment element (2602, 2902, 2904, 2906, 2908, 2910, 2912, 2922) on the downhole drilling system (10) to enhance the mode HFTO at the location of at least one damper element (2604, 2700, 2800) on the downhole drilling system. 13. The method according to any one of claims 10-12, further comprising selecting at least one waveform control element (2602, 2902, 2904, 2906, 2908, 2910, 2912, 2922) from a set of waveform control elements (2602, 2902 , 2904, 2906, 2908, 2910, 2912, 2922) for placement as part of a downhole drilling system (10). 14. The method according to any one of claims 10-13, further comprising performing a numerical HFTO simulation of at least a section of the downhole drilling system (1002); and selecting at least one waveform adjustment element (2602, 2902, 2904, 2906, 2908, 2910, 2912, 2922) for placement within the downhole drilling system (10) based on the HFTO numerical simulation of a portion of the downhole system (1002). 15. The method according to claim 14, additionally containing: performing numerical inversion; and at least one of: positioning and selecting at least one of at least one damping element (2604, 2700, 2800) and at least one waveform adjustment element (2602, 2902, 2904, 2906, 2908, 2910, 2912, 2922), based on numerical inversion.