MITIGATING DRILL STRING HFTO

Description

CROSS REFERENCE TO RELATED APPLICATIONS

This application claims priority to U.S. Provisional Patent Application No: 63/693,460, which was filed on Sep. 11, 2024, and is incorporated herein by reference in its entirety.

FIELD

Disclosed embodiments relate generally to downhole drilling operations and more particularly to mitigating high frequency torsional oscillations during such operations.

BACKGROUND

Severe dynamic conditions are often encountered while drilling subterranean wellbores (e.g., geothermal wells or oil and gas exploration and production wells). Such dynamic conditions may include, for example, axial vibrations including bit bounce, lateral vibrations including whirl, and torsional vibrations including stick slip. High-frequency torsional oscillations (HFTO) have recently been identified as a significant cause of bottom hole assembly (BHA) damage. Severe HFTO can be highly destructive, for example, causing collar cracking, damage to electronic components, thread damage from over torqued joints, and twist off failure. HFTO can also contribute to wellbore washout or hole enlargement.

Owing to their highly destructive potential, HFTO oscillations have been the subject of considerable recent evaluation. Mitigation efforts commonly involve developing balanced drill string components based on mathematical and mechanical models of the BHA system. While these efforts have increased understanding of the HFTO mechanisms, there is room for further work. In particular, there is a need for HFTO mitigation methods, and more particularly for HFTO mitigation methods that can be implemented downhole in response to HFTO measurements or other measurements indicative of potentially damaging HFTO.

SUMMARY

In one example embodiment, a wellbore operation comprises rotating a drill string in a wellbore, the drill string including a rotary steerable system having at least three pads configured to contact the wellbore wall to steer a direction of drilling; measuring an HFTO amplitude while rotating; comparing the measured HFTO amplitude with an HFTO threshold; and simultaneously actuating the at least three pads to mitigate HFTO oscillations when the measured HFTO amplitude exceeds the HFTO threshold.

In another example embodiment, a wellbore operation comprises rotating a drill string in a wellbore, the drill string including a rotary steerable system having at least three pads configured to contact the wellbore wall to steer a direction of drilling; determining operational conditions or times during the wellbore operation at which the drill string is susceptible to HFTO; and simultaneously actuating the at least three pads to mitigate HFTO oscillations at the determined operational conditions or times when the drill string is susceptible to HFTO.

This summary is provided to introduce a selection of concepts that are further described below in the detailed description. This summary is not intended to identify key or essential features of the claimed subject matter, nor is it intended to be used as an aid in limiting the scope of the claimed subject matter.

BRIEF DESCRIPTION OF THE DRAWINGS

For a more complete understanding of the disclosed subject matter, and advantages thereof, reference is now made to the following descriptions taken in conjunction with the accompanying drawings, in which:

FIG. 1 depicts a disclosed drilling rig.

FIG. 2 depicts a disclosed rotary steerable system.

FIG. 3 depicts a flow chart of one example method for mitigating HFTO.

FIG. 4 depicts a flow chart of another example method for mitigating HFTO.

FIG. 5 depicts an example hydraulic circuit that may be employed in a rotary steerable system that makes use of a roll stabilized control unit.

FIGS. 6A and 6B depict plots of steering pad force versus the relative rotational orientation of the roll stabilized control unit with respect to the tool collar for a rotary steerable system employing the hydraulic circuit depicted on FIG. 5.

FIG. 7 depicts example stick slip and harmonic stick slip oscillations in which the oscillation amplitude is depicted on the horizonal axis.

DETAILED DESCRIPTION

Disclosed wellbore operations include rotating a drill string in a wellbore. The drill string includes a rotary steerable system having at least three pads configured to contact the wellbore wall to steer a direction of drilling. The wellbore operation may further include measuring an HFTO amplitude while rotating and comparing measured HFTO amplitude with an HFTO threshold or determining operational conditions or times during the wellbore operation at which the drill string is susceptible to HFTO. The pads on the rotary steerable system may be simultaneously actuated to mitigate HFTO oscillations when the measured HFTO amplitude exceeds the HFTO threshold or when the wellbore operation is susceptible to HFTO.

FIG. 1 depicts an example drilling rig 20 positioned over a subterranean formation 70. The drilling rig may include a derrick and a hoisting apparatus (not shown) for raising and lowering a drill string 30, which, as shown, extends into wellbore 40 and includes a drill bit 32 deployed at the lower end of a bottom hole assembly (BHA) 35. In the depicted embodiment, the drill string 30 further includes a rotary steerable system (RSS) 50 deployed above the bit. The drilling rig 20 may be deployed in either onshore or offshore applications (an onshore application is depicted). Moreover, the wellbore may be inclined at substantially any angle and may include, for example, vertical, horizontal, turning, and/or building sections (as depicted). The disclosed embodiments are not limited to any particular wellbore configuration. In the depicted example, the wellbore 40 may be formed in subsurface formations 70, for example, by rotary drilling in a manner that is well-known to those of ordinary skill in the art (e.g., via known directional drilling techniques).

As is known to those of ordinary skill, the drill string 30 may be rotated, for example, at the surface to drill the well (e.g., via a rotary table) or via a hydraulically powered motor deployed in or above the BHA 50. A pump may deliver drilling fluid through the interior of the drill string 30 to the drill bit 32 where it exits the string via ports therein. The fluid may then circulate upwardly through the annular region between the outside of the drill string 30 and the wall of the wellbore 40. In this known manner, the drilling fluid lubricates the drill bit 32 and carries formation cuttings up to the surface.

It will be understood that the deployment illustrated on FIG. 1 is merely an example. Drill string 30 may include substantially any suitable downhole tool components, for example, including a steering tool such as a rotary steerable system, a downhole telemetry system, and one or more measurement while drilling (MWD) and/or logging while drilling (LWD) tools including various sensors for sensing downhole characteristics of the borehole and the surrounding formation. The disclosed embodiments are by no means limited to any particular drill string configuration.

FIG. 2 depicts a schematic of an example RSS 50 and drill bit 32. In the depicted embodiment, the RSS 50 includes a plurality of (e.g., three) circumferentially spaced steering actuators 55 (also referred to as pads or blades) that are deployed on a tool collar (or body) 52. In the depicted embodiment, the blades 55 are configured to extend radially outward from the collar 52 and engage the wellbore wall to steer the direction of drilling (e.g., by pushing the bit 32 in a desired lateral direction). It will be appreciated that other steering mechanisms are known to those of ordinary skill in the art and that the disclosed embodiments are expressly not limited to push the bit configurations such as depicted.

The RSS 50 may further include a control unit 60 including an electronic controller (not depicted in the figure). A suitable controller may include, for example, one or more programmable processors, such as a digital signal processor or other microprocessors or microcontrollers that may be connected with electronic memory (solid-state memory). The controller may be configured to execute computer-readable program code embodying logic and therefore be utilized to execute the disclosed method embodiments. The electronic controller may further include sensors (such as accelerometers and magnetometers) configured to measure downhole oscillations such as stick slip and HFTO. The controller may also be in electronic communication with sensors deployed elsewhere in the drill string 30 or BHA 35.

With continued reference to FIG. 2, in example embodiments the control unit 60 may be a roll stabilized control unit. By roll-stabilized it is meant that the control unit may be substantially non-rotating with respect to the wellbore (or may be configured to rotate independently with respect to the drill collar and the pads). For example, various PowerDrive rotary steerable systems (available from SLB) include a drill collar that is intended to fully rotate with the drill string and an internal roll-stabilized control unit that rotates independently (e.g., to remain substantially rotationally geostationary). As is known to those of ordinary skill in the art, a roll stabilized control unit may be mounted on bearings such that it is rotationally decoupled from the collar. The rotational orientation or rotational speed of the control unit may be controlled by the co-action of first and second axial opposing alternators in combination with feedback provided by sensors in the control unit. The alternators may include corresponding impellers that are configured to rotate in opposing directions and apply corresponding opposing torques to the control unit. The amount of electrical load on the alternators may be changed in response to feedback from the sensors to vary the applied torques and thereby control the orientation or rotational speed of the housing.

The rotary steerable system 50 may include substantially any suitable RSS that utilizes the above described steering pads to contact the wellbore wall and thereby steer the direction of drilling. For example, The PowerDrive X5, X6, and Orbit rotary steerable systems (available from SLB) make use of mud actuated pads that contact the borehole wall. Moreover, it will be appreciated that the RSS may include a steerable drill bit, such as the NEOSTEER® at bit steerable system available from SLB, in which the steering pads extend outward from the drill bit body into contact with the wellbore wall.

Torsional oscillations are commonly encountered during well drilling operations. Stick slip refers to a torsional oscillation induced by friction between drill string components and the borehole wall and is known to produce instantaneous drill string rotation speeds many times that of the nominal rotation speed of the table. For example, a portion of the drill string or BHA may stick to or catch on the borehole wall due to frictional forces causing the drill string to temporarily stop rotating. Meanwhile, the rotary table continues to turn resulting in an accumulation of torsional energy in the drill string. When the torsional energy exceeds the static friction between the drill string and the borehole wall, the energy is released suddenly in a rapid burst of drill string rotation. Stick slip oscillations commonly have a fundamental frequency on the order of 0.1 to 0.5 Hz depending on the length of the drill string.

Harmonic stick slip (HSS) oscillations are similar to stick slip in that these oscillations are torsional; however, harmonic stick slip oscillations occur at harmonics of the fundamental stick slip frequency. Damaging harmonics tend to be odd integer multiples of the fundamental frequency, for example, third, fifth, seventh, and so on, with fifth order harmonics and above generally being the most damaging. As such harmonic stick slip oscillations commonly occur at a frequency greater than about 0.2 Hz, for example, in a range from about 0.2 Hz to about 5 Hz. Harmonic oscillations are believed to cause severe damage to downhole tools, as well as connection fatigue, and excess wear to the drill bit and near-bit stabilizer blades.

High frequency torsional oscillations (HFTO) are fundamentally different than stick slip or HSS oscillations in that they occur in the BHA or in a lower portion of the drill string. HFTO, as the name indicates, is a higher frequency torsional oscillation that commonly has a frequency in a range from about 50 Hz to 400 Hz, depending on the BHA configuration and the corresponding wavelength of the oscillations. HFTO oscillations can exceed 200 rpm in amplitude. HFTO is also believed to cause severe damage to downhole tools, as well as connection fatigue, connection back off, and excessive wear.

One aspect of the disclosed embodiments was the realization that HFTO can be mitigated via careful control of the steering blades on a rotary steerable (RSS) tool such as a PowerDrive RSS (available from SLB). In other words, it was realized that appropriate control of the steering blades can mitigate (reduce or even substantially eliminate) HFTO oscillations.

It will be appreciated that the disclosed embodiments are not strictly limited to while drilling activities in which the drill bit is rotating on bottom. It will be further appreciated that highly damaging vibrations can (and sometimes do) occur during other drilling related activities, for example, rotating the drill string and circulating drilling fluid when the drill bit is off bottom or when rotating while tripping. Therefore, it will be understood that the term “drilling” as used herein is used in the broader context to refer to drilling related activities whether or not the drill bit is on or off bottom.

FIG. 3 depicts a flow chart of one example method 100 for mitigating HFTO oscillations during a wellbore operation. The method includes rotating a drill string in a wellbore at 102 (e.g., to drill the well). An HFTO amplitude may be measured at 104 while rotating the drill string. The measurement may include, for example, a maximum HFTO amplitude in a predetermined time interval or in a predetermined frequency range (e.g., a frequency computed based on the BHA configuration). The HFTO may be measured using any suitable measurement techniques or downhole sensors, for example, suitable to measure collar rotation speed, collar tangential acceleration, bit tangential acceleration, or bit torque. The measurement may further include an HFTO frequency that may be obtained, for example, by computing a Fast Fourier Transform (FFT) HFTO amplitude (e.g., collar rotation speed, collar tangential acceleration, bit tangential acceleration, or bit torque).

With continued reference to FIG. 3, the measured HFTO amplitude may be compared with an HFTO threshold at 106 (e.g., a predetermined threshold). When the HFTO amplitude is greater than or equal to the threshold, the RSS pads may be simultaneously actuated at 108 to mitigate the HFTO oscillations. In another embodiment, the RSS pads may be simultaneously actuated at 108 when the HFTO amplitude exceeds the threshold and the HFTO frequency is within a predetermined frequency band. Otherwise, the method may continue measuring the HFTO at 104 (as depicted).

With continued reference to FIG. 3, the intent of the simultaneous actuation of the RSS pads is to provide frictional torque that dampens the HFTO oscillations. In some embodiments, the pads may be simultaneously actuated to continuously or semi-continuously engage the wellbore wall to dampen the HFTO oscillations. For example, by continuously or semi-continuously it may be meant that the pads are simultaneously actuated for a period of time that is longer than the stick slip period (so as not to trigger stick slip). In such embodiments, the pads may be simultaneously actuated for a period of time that is at least 1.5 times (e.g., at least twice or at least three times) the stick slip period. In alternative embodiments, knowing that HFTO can attenuate rapidly in certain operational conditions, the simultaneous actuation may include short pad actuation bursts which are out of phase with the stick slip frequency. For example, such short actuation bursts may have a frequency of less than the stick slip frequency (e.g., on the order of one second). In this way (via the provided frictional torque), simultaneous actuation of the pads may mitigate HFTO (reducing the severity thereof).

In example embodiments, the pads are simultaneously actuated to provide a low force to the wellbore wall or a low frictional torque to the drill string. By low force or low frictional torque it is meant that the applied frictional force tends to have minimal impact on the rotational speed of the drill collar, for example, such that the frictional force does not trigger stick slip. In example embodiments, the applied frictional force reduces the rotational speed of the drill string (e.g., the RSS collar) by less than 10 percent (e.g., less than 5 percent).

With continued reference to FIG. 3, it will be appreciated that actuation of the RSS pads may employ substantially any actuation mechanism. For example, simultaneous actuation of the pads may be achieved via actuating each pad independently (and simultaneously) in tool embodiments that employ electronic valves to control flow of the actuating fluid. However, energizing the pads simultaneously can be hydraulically inefficient (depending on the configuration of the RSS).

In an alternative embodiment, the pad actuation scheme may make use of a flow restriction at the hydraulic exhaust (where the fluid exits the pad cylinders). This restriction limits the speed at which the pads can exhaust fluid and thereby retract. As a result, rapid sequential actuation of the pads may in practice result in the pads being simultaneously actuated into contact with the wellbore wall. Therefore, in example embodiments, the pads may be actuated simultaneously via rapid sequential actuation. By rapid it may be meant that each pad is actuated at a frequency exceeding 5 Hz (e.g., exceeding 6 Hz, exceeding 7 Hz, exceeding 8 Hz, exceeding 9 Hz, or even exceeding 10 Hz). In example embodiments including three circumferentially spaced pads, rapid sequential actuation may mean that the pads are sequentially actuated at a time interval of less than about 0.1 seconds (e.g., less than about 0.07 seconds, less than about 0.05 seconds, 0.04 seconds, or even 0.03 seconds).

In embodiments that make use of an RSS having a roll stabilized control unit, rapid sequential actuation of the pads may be achieved, for example, by rotating the roll stabilized control unit in a direction opposite that of the drill collar rotation to achieve a differential rotation rate (a difference between the rotation rate of the drill collar and the rotation rate of the control unit) that exceeds a threshold. It will be appreciated that certain example RSS's make use of a spider valve that includes the above described flow restriction to the hydraulic exhaust. Rotating the control unit to achieve the high differential rotation rate (above the threshold) results in rapid sequential actuation of the pads which in turn, in practice, may result in simultaneous actuation of the pads. In example embodiments the differential rotation rate threshold may be 350 rpm (e.g., 400 rpm, 450 rpm, or even 500 rpm).

FIG. 4 depicts a flow chart of one example method 150 for mitigating HFTO oscillations during a wellbore operation. The method 150 includes rotating a drill string in a wellbore at 152 (e.g., to drill the well). The method further includes determining times during the operation at which HFTO oscillations are favorable or likely at 154. For example, HFTO is commonly triggered by a kink (e.g., a micro-dogleg) in the well which increases the side force on the contact points of the BHA and thereby generate a vibrational node. Crossing heterogeneous formations or sections with significant micro doglegs can sometimes generate or amplify HFTO. The determining at 154 may therefore include identifying such locations in the wellbore. Moreover, HFTO is sometimes more severe at lower drill string rotation rates and higher weight on bit (WOB). Determining at 154 may therefore also include identifying times at which the drill string rotation rate falls below a threshold or the WOB exceeds a threshold. When HFTO oscillations are favorable or likely, the RSS pads may be simultaneously actuated at 156 to mitigate the HFTO oscillations.

With further reference to FIGS. 3 and 4, it will be appreciated that methods 100 and 150 may be implemented automatically. For example, HFTO may be automatically and continuously measured while drilling at 104 or conditions at which HFTO is favorable or likely may be automatically and continuously monitored at 154. The RSS pads may then be automatically actuated (simultaneously) at 108 and 156 when the measured HFTO exceeds a threshold or when HFTO is likely. In this way, HFTO oscillations may be automatically mitigated. Moreover, it will be appreciated that the measuring and evaluating steps may run automatically in the background and the RSS pad actuation may be automatically implemented only when one or more of the measured oscillations exceeds the corresponding threshold or when the operational conditions are determined to be favorable or to promote HFTO.

FIG. 5 depicts a hydraulic circuit 200 that may be employed in an RSS that makes use of a roll stabilized control unit. The hydraulic circuit 200 includes a spider valve 210 in fluid communication with first, second, and third pad actuators 220. The spider valve 210 is configured to sequentially connect and disconnect the first, second, and third pad actuators 220 from pressurized drilling fluid as a tool collar rotates with respect to a roll stabilized control unit and therefor to sequentially actuate the RSS pads. As further depicted (and described above) each of the pad actuators 220 may be vented to the wellbore annulus (outside of the RSS) through a corresponding flow restrictor 225. The depicted hydraulic circuit may further optionally include first, second, and third nonreturn (one-way check) valves 230 that provide fluid flow from the spider valve 210 to the corresponding one of the pad actuators while blocking return flow. As described in more detail below, the use of the optional nonreturn valves 230 may provide for improved stick slip, harmonic stick slip, and/or whirl mitigation.

FIGS. 6A and 6B depict plots of steering pad force versus the relative rotational orientation of the roll stabilized control unit with respect to the tool collar at differential rotation rates of 240 rpm, 300 rpm, 400 rpm, and 600 rpm. In FIGS. 6A and 6B, the steering pad force is plotted for hydraulic circuits similar to that depicted on FIG. 5 in which the nonreturn valve 230 is not including added mass (6A) and the nonreturn valve 230 includes 20 grams of added mass to slow the opening motion of the valve thereby impacting performance at higher speeds. Note that in both figures, the pad force decreases significantly with increasing relative rotation speed. In embodiments employing the hydraulic circuit configuration depicted on FIG. 5, rotating the control unit to achieve the high differential rotation rate (above the threshold) results in rapid sequential actuation of the pads which in turn may result, in practice, in simultaneous actuation of the pads but advantageously at a reduced pad force (as compared to the full steering force). The reduced pad force may advantageously not significantly reduce the rotation rate of the drill string and may further reduce wear and tear on the RSS while being sufficient to mitigate stick slip, harmonic stick slip, and/or whirl oscillations.

FIG. 7 depicts example HSS oscillations in which the stick slip amplitude is depicted on the horizonal axis (the amplitude of the wave). Note that the oscillation occurs along the length of the drill string 30′. In the example depiction, the top drive 31 may be a node for the torsional oscillation and the BHA 50′may be an antinode. It will be appreciated that the actual coupling at the top drive 31 may not be a full node as the control system can provide some coupling which will vary with frequency. Moreover, the BHA 50′tends to be stiffer than the drill string and so tends not to be a perfect antinode. Notwithstanding, to a first approximation, the top drive may be taken to be a node and the BHA (or bit) may be taken to be an antinode.

With continued reference to FIG. 7, the fundamental stick slip frequency of the drill string length may be a quarter wavelength (e.g., λ_F=4 L). The stick slip period is the reciprocal of the fundamental frequency (P_ss=1/λ_F). As described above, the higher harmonics have shorter wavelengths (and corresponding higher frequencies). For example, the third harmonic may have a wavelength λ₃=4 L/3, while the fifth harmonic may have a wavelength λ₅=4 L/5. The frequency may be given as f=v/λ, where v represents the wave speed in the drill string. The wave speed depends on the shear modulus and density of the drill string and is generally about v≈3,000 m/s. At a well depth of about 3,000 m (about 10,000 ft), the fundamental frequency may be about 0.25 Hz such that the stick slip period may be about 4 seconds.

As described above, the disclosed embodiments may include an automated system (such as an RSS) for drilling a wellbore that mitigates HFTO vibrations. The system may include computer hardware and software configured to receive or make HFTO measurements (or other measurements that determine HFTO susceptibility) and to automatically actuate the RSS pads in response to the measurements. The hardware may include one or more processors (e.g., microprocessors) which may be connected to data storage devices (e.g., hard drives or solid state memory) and user interfaces. It will be further understood that the disclosed embodiments may include processor executable instructions stored in the data storage device. The disclosed embodiments are, of course, not limited to the use of or the configuration of any particular computer hardware and/or software.

Although mitigating drill string HFTO has been described in detail, it should be understood that various changes, substitutions and alternations can be made herein without departing from the spirit and scope of the disclosure as defined by the appended claims.