Method and apparatus for controlling drilling vibration

Abstract

A method of operating a rig includes measuring downhole vibration data in a bottom hole assembly. The measured downhole vibration data is transmitted to a downhole controller located in the bottom hole assembly. The downhole controller calculates an operational adjustment to the bottom hole assembly to decrease vibrations in the bottom hole assembly. The calculated operational adjustment is sent to the bottom hole assembly to decrease vibrations in the bottom hole assembly.

Description

METHOD AND APPARATUS FOR CONTROLLING DRILLING VIBRATIONCROSS-REFERENCE TO RELATED APPLICATIONS

[0001] This application claims benefit of priority to U.S. Provisional Patent Application No. 63 / 711,534, filed October 24, 2024, and U.S. Provisional Patent Application No. 63 / 795,899, filed April 28, 2025, each of the above referenced applications is incorporated herein by reference in its entirety.BACKGROUNDField

[0002] Embodiments of the present disclosure generally relate to rigs, such as drilling or service rigs, and particularly to the control and operation of rigs. In particular, embodiments of the present disclosure relate to controlling drilling vibrations.Description of the Related Art

[0003] When drilling for hydrocarbon and geothermal energy, a well is constructed to reach the energy reservoir located miles beneath the earth surface. With the advance of drilling engineering, longer and deeper wells are constructed. The length of the well can be over thirty thousand feet and the well construction can last for several days to months. A drillstring, measuring several inches in diameter, is utilized to transfer the applied loads, such as weight and torque, from the surface to the bottom hole to effectively form the borehole.

[0004] As slim and flexible as the drillstring is, vibrations in various forms can be excited if the drilling process is not well controlled. The drilling vibrations occur in axial, torsional, and lateral directions and are strongly coupled with each other by their nature. Also, the high frequency vibrations are localized in the bottom hole assembly (BHA), which makes them less detectable or controllable at the surface. Vibrations that may be encountered include stick-slip, bit bounce, whirl, and high frequency torsional oscillations (HFTOs). Excessive and (self-)sustained vibrations can cause damage to the drilling equipment including tool joint twist-off, bit wear or damage, downhole tool malfunctions, etc., and may ultimately lead tocompromised hole qualities and suboptimal drilling efficiencies. The latter can lengthen the time and increase the cost of well construction.

[0005] There is, therefore, a need for an efficient control of the downhole vibrations of the drillstring such that usage of the drilling tool or bit may be extended.SUMMARY

[0006] Embodiments of the present disclosure generally relate to rigs, such as drilling or service rigs, and particularly to the control and operation of rigs. In particular, embodiments of the present disclosure relate to controlling drilling vibrations.

[0007] In one embodiment, a method of operating a rig includes measuring downhole vibration data in a bottom hole assembly (BHA). The measured downhole vibration data is transmitted to a downhole controller located in the BHA. The downhole controller calculates operational adjustments to the BHA to decrease vibrations in the BHA. The calculated operational adjustments are sent to the BHA to decrease vibrations in the BHA.

[0008] In some embodiments, a downhole tool includes an upper housing having an upper bore and a lower housing having a lower bore. The lower housing is coupled to and axially movable relative to the upper housing. The downhole tool also includes a pressure chamber defined between the upper housing and the lower housing. The pressure in the pressure chamber is adjustable to axially move the lower housing, thereby adjusting a weight-on-bit applied by the downhole tool.BRIEF DESCRIPTION OF THE DRAWINGS

[0009] So that the manner in which the above recited features of the present disclosure can be understood in detail, a more particular description of the disclosure, briefly summarized above, may be had by reference to embodiments, some of which are illustrated in the appended drawings. It is to be noted, however, that the appended drawings illustrate only exemplary embodiments and aretherefore not to be considered limiting of the scope of the disclosure, as the disclosure may admit to other equally effective embodiments.

[0010] Figure 1 schematically illustrates a rig, according to some embodiments.

[0011] Figure 2 schematically illustrates a vibration control system of the rig of Figure 1.

[0012] Figure 3 schematically illustrates an exemplary controller suitable for use with the rig of Figure 1.

[0013] Figure 4 schematically illustrates another exemplary controller suitable for use with the rig of Figure 1.

[0014] Figure 5 schematically illustrates an exemplary downhole tool of the ring of Figure 1.

[0015] Figure 6 is flow diagram of a method of operating the rig of Figure 1.

[0016] Figure 7 shows Table 1 with comparison results of different vibration controlling systems.

[0017] Figure 8 illustrates another exemplary embodiment of a vibration dampening tool, according to some embodiments.

[0018] Figures 9A and 9B are partial views of the dampening tool of Figure 8.

[0019] Figure 10 is a cross-sectional view of the vibration dampening tool of Figure 8.

[0020] Figure 11 is another cross-sectional view of the vibration dampening tool of Figure 8.

[0021] To facilitate understanding, identical reference numerals have been used, where possible, to designate identical elements that are common to the figures. It is contemplated that elements and features of one embodiment may be beneficially incorporated in other embodiments without further recitation.DETAILED DESCRIPTION

[0022] Embodiments of the present disclosure provide a downhole vibration sensing and control system to proactively detect and mitigate drillstring vibrations in the downhole environment. In response to detected vibrations, a downhole controller is configured to adjust one or more drilling parameters, such as weight-on-bit, pressure, and the rate of drillstring rotation, to mitigate the drillstring vibration. In some embodiments, the adjusted drilling parameters may be calculated using only locally measured dynamic information, such as axial load, pressure, and torque. In some embodiments, the downhole weight-on-bit and the rotation rate are simultaneously controlled via downhole actuation tools. The detrimental vibrations are beneficially mitigated and decoupled. As a result, potential damages to the downhole tools from excessive and cyclic vibration loads are diminished in an efficient manner.

[0023] In some embodiments, drilling vibrations are first recorded using one or more sensors in the bottom hole assembly (BHA). The vibration data are then transmitted to a controller in the BHA that is configured to extract the lower drillstring or BHA parameters to determine vibrations on the BHA.

[0024] When undesired vibrations are detected, actuation signals for different tools in the BHA tools are calculated based on the pre-defined drillstring models and controllers. Exemplary controllers include vibration controllers designed based on H2, Hinf, and linear-quadratic-integration (LQI) approaches. In some embodiments, the vibration controllers are advantageously configured to address the uncertainties and drilling nonlinearities caused by incomplete state observations, 3D well trajectories, non-Coulomb frictions, increasing well depth, etc.

[0025] In some embodiments, the actuation signals are simultaneously sent to corresponding tools in the BHA for operation of the tools. Embodiments of the control system is characterized by a high robustness to drilling nonlinearities and convenience for implementations / practice.

[0026] Figure 1 schematically illustrates a portion of a rig 100. In some embodiments, the rig 100 is a drilling rig. In some embodiments, the rig 100 is a service rig. The rig 100 includes a derrick 102 that extends above a floor 104. A crown block 108 is located at an upper end of the derrick 102. A drawworks 120 is located at the floor 104. A traveling block 110 is suspended below the crown block 108 by a cable 106 that extends from the drawworks 120 and around the crown block 108. The traveling block 110 is raised by using the drawworks 120 to retract the cable 106, and is lowered by using the drawworks 120 to pay out the cable 106. In some embodiments, a tubular handling tool 116, such as a top drive, power swivel, or elevator, is suspended from the traveling block 110. In some embodiments, the tubular handling tool 116 is omitted.

[0027] The drillstring 325 includes interconnected sections of drill pipe 327, a bottom hole assembly (BHA) 340, and a drill bit 348. The BHA 340 may include stabilizers, drill collars, and / or measurement-while-drilling (MWD) or wireline conveyed instruments, among other components. The drill bit 348 is connected to the bottom of the BHA 340. In this example, the top drive 116 is utilized to impart rotary motion to the drillstring 325.

[0028] A mud pump system 330 delivers the mud to the drill string 325 through a hose or other conduit. The mud flows through the drill bit 348 and fills the annulus that is formed between the drill string 325 and the inside of the wellbore 335, and is circulated to the pump system 330. A choke valve 337 may be positioned between the wellhead 338 and the pump system 330 to control the fluid flow out of the wellbore 335.

[0029] The drilling rig system 100 also includes a rig control system 400 configured to control of one or more components of the drilling rig system 100. For example, the control system 400 may be configured to transmit operational control signals to one or more of the top drive 116, the drawworks 120, the BHA 340 or the mud pump system 330. The control system 400 may be installed somewhere on or near the derrick 102 or at a remote location away from the derrick 102.

[0030] In some embodiments, the control system 400 may receive one or more state variables, such as torque, differential pressure in the wellbore 335, RPM information from one the top drive 116, and weight-on-bit (WOB) at the surface from the drawworks 120. The control system 400 may also receive downhole variables such as downhole torque on bit at the BHA 340, downhole RPM at the BHA 340, and downhole WOB at the BHA 340. The control system 400 is configured to calculate values for adjusting the outputs of the top drive 116 and the drawworks 120. In some embodiments, the values are calculated in real-time using pre-defined drillstring dynamic models and control algorithms. Thus, for example, a first value may be generated to adjust the RPM of the top drive 116, while a second value may be generated to adjust the operation of the drawworks 120. In this respect, a combination of top drive speed and WOB variations is used to adjust vibrations on the drillstring 325.

[0031] In some embodiments, the control system 400 includes a system controller 410. The controller 410 includes a central processing unit 423 (CPU), a memory 424 containing instructions, and support circuits 425 for the CPU, as illustrated in Figure 2. The memory, or non-transitory computer readable medium, is one or more of a readily available memory such as random access memory (RAM), read only memory (ROM), floppy disk, hard disk, flash drive, or any other form of digital storage, local or remote. The support circuits are coupled to the CPU for supporting the CPU. The support circuits include cache, power supplies, clock circuits, input / output circuitry and subsystems, and the like. Operations and operating parameters are stored in the memory as a software routine that is executed or invoked to configure the controller 410 into a specific purpose controller to control the operations of the rig 100, such as controlling the downhole WOB and the downhole rate of rotation of the drillstring. The controller 410 is configured to conduct one or more of the operations described herein. In some embodiments, the controller 410 is configured to take action in response to data received from one or more sensors of the rig 100. The instructions stored on the memory, when executed, cause one or more of the operations described herein to be conducted.

[0032] In this embodiment, the control system 400 of the rig 100 is integrated with the top drive 116, the drawworks 120, BHA 340, and with additional components of the rig 100. In some embodiments, the control system 400 includes the controller 410, a user interface 422, and a display 426. The user interface 422 may be independent from the controller 410 or may be a part of the controller 410.

[0033] The display 426 may be used for visually presenting information to the user in textual, graphic, or video form. The display 426 may also be utilized by the user to input drilling parameters or set point data via an input mechanism of the user interface 422. The user interface 422 may be used to receive drilling parameters, including RPM and WOB before and / or during drilling operations. Additionally, a user may input information relating to the drilling parameters of the drill string 325, such as the BHA 340, drill pipe size, bit type, depth, formation information, and drill pipe material, among other things.

[0034] In some embodiments, the top drive 116 includes one or more torque sensors 265 for measuring torque on the near-surface drill-string 325 in order to mitigate drillstring vibrations. In one example, the torque sensor 265 is a torque sub located between the top drive 116 and the drill string 325. The measured torque may be sent to the controller 410 via wired or wireless transmission. Exemplary sensors include accelerometers for measuring rate of rotation, torque, and axial load. Examples of wired or wireless communication between tools, controllers, and / or sensors disclosed herein include wire such as a cable, acoustic telemetry, pressure pulse telemetry, laser, electromagnetic signals, or other suitable wired or wireless communication.

[0035] In some embodiments, the top drive 116 may also include a load sensor 275 such as a hook load sensor, a RPM sensor 290, a pump pressure sensor 280, and other suitable sensors. The load sensor 275 detects the load on the top drive 116 (or the hook) as it retains the drillstring 325. The measured load may correspond to a surface WOB measurement. The pump pressure sensor 280 is configured to detect the pressure of the pump providing mud or otherwise powering the downhole motor in the BHA 340 from the surface. The RPMsensor 290 is configured to detect the rotary RPM of the drillstring 325. The measured load, pump pressure, and RPM may be sent via electronic signal or other signal to the controller 410 via wired or wireless transmission.

[0036] The drawworks 120 may include a sensor 250 to determine the speed at which the drillstring 325 is being hoisted or lowered. The drawworks 120 may also include a controller 255. The controller 255 is used to control the speed of the cable 106 of the drawworks 120.

[0037] The pump system 330 may include a flow rate sensor 346 and a mud composition sensor 347. In some examples, the mud composition may be stored in memory 424.

[0038] The BHA 340 may include one or more sensors configured about the BHA 340 to detect parameters relating to the drilling environment, the BHA 340 condition and orientation, and other information. These may provide information that is considered by the controller 410 when it determines how to adjust the top drive 116 and / or drawworks 120 operation to adjust torque and / or force on the drill string 325.

[0039] In some embodiments, the BHA 340 includes one or more downhole sensors. The BHA 340 may also include accelerometers that are configured to detect vibrations in the BHA 340. The BHA 340 may also include a torque sensor 343 that is configured to detect the torque applied to the bit by the motor(s) of the BHA 340. The BHA 340 may also include a RPM sensor 344 that is configured to detect the RPM of the bit of the BHA 340. In some examples, the BHA 340 may also include a weight-on-bit sensor 342 that is configured to measure the downhole weight-on-bit at or near the BHA 340. In some examples, the BHA 340 may also include mud motor sensor 345 that is configured to detect a pressure differential value or range across the mud motor of the BHA 340. The data detected via one or more of these downhole sensors 341-345 may be sent via electronic signal or other signal to the controller 410 via wired or wireless transmission. Examples of wired or wireless communication between tools, controllers, and / or sensors disclosed herein include wired communication such as a cable, acoustic telemetry,pressure pulse telemetry, laser, electromagnetic signals, or other suitable wired or wireless communication.

[0040] In some embodiments, the system controller 410 is configured to adjust the weight-on-bit, the RPM of the drillstring, or both in response to the data received from one or more of the sensors. In some embodiments, the system controller 410 may be configured as multi-input-multi-output (MIMO) controllers. Exemplary MIMO controllers include a LQI controller, an H2 controller, an Hinf controller, or other suitable MIMO controllers. Other exemplary controllers include a PID controller or a state feedback controller,

[0041] Figure 3 illustrates an exemplary embodiment of the system controller 410 configured as a LQI controller. As shown in Figure 3, the system dynamic states, such as downhole weight-on-bit (“WOB”) and downhole RPM, are the inputs used to calculate the control outputs. Based on the system WOB and RPM setpoints, the downhole WOB and RPM errors are integrated before fed into the static error gain. System observed states are also normalized using the designed static state gain. Then the two terms are added to calculate the control outputs of the drilling system. In this embodiment, the control outputs are calculated for the surface top drive and / or the hook load.

[0042] Referring back to Figure 1 , the BHA 340 may also include a downhole controller 500 to proactively detect and mitigate drillstring vibrations in the downhole environment. In some embodiments, the downhole controller 500 may be independent of or part of the control system 400. In some embodiments, the downhole controller 500 may take action in conjunction with or independent of system controllers 410. In one example, the downhole controller 500 may receive data from one or more of the downhole sensors 341-345 and take action independent of the control system 400 or the controller 410. In some embodiments, the downhole controller 500 may receive data from one of the sensors or tools at the surface in addition to or as an alternative to the downhole sensors 341-345. For example, data from the load sensor 275 and the top drive torque sensor 265 can be sent to the downhole controller 500. Also, data relating to the mud flowrate, mud composition, and the choke valve opening can be sent to the downhole controller 500.

[0043] In some embodiments, the downhole controller 500 is configured to adjust the downhole weight-on-bit and / or the downhole RPM of the drillstring in response to the data received from one or more of the downhole sensors 341 -345. The downhole controller 500 may be configured as a MIMO controller such as a LQI controller, an H2 controller, an Hinf controller, or other suitable controllers for controlling vibration. In some embodiments, the MIMO controller is configured to provide for simultaneous downhole weight-on-bit and rotation speed (RPM) control. In some examples, the measured lower drillstring dynamic states and downhole drilling parameters are taken as controller inputs for calculating the vibration controller outputs. The controller outputs may include one or more of the actuation forces, torque values, and pressure values for one or more downhole actuation tools.

[0044] Figure 4 illustrates an exemplary embodiment of the downhole controller 500 configured as a Hinf controller. In Figure 4, the system dynamic states, such as downhole WOB and downhole RPM, are used to calculate the control inputs. The system WOB and RPM setpoints and the downhole WOB and RPM errors are used to calculate the control inputs of the drilling system. In this embodiment, the control inputs are the downhole torsional and / or axial actuation loads in the BHA. In comparison to Figure 3, the downhole RPM and WOB errors are the only information required to compute the system control outputs. Additionally, different from the static gains designed in the LQI controller, the Hinf controller provides the dynamic output feedback and ideally involves no state observers. Embodiments of the controllers 410, 500 are configured to suppress coupled vibrations in different directions in the BHA, such as axial and rotational directions. It is noted that other suitable vibration controllers may be designed with consideration of different aspects of the drilling vibration suppression problem.

[0045] Figure 5 illustrates an exemplary embodiment of a BHA 540, such as BHA 340, equipped with a vibration dampening tool 520 and a downhole controller 500, according to some embodiments. The BHA 540 may include one or moresensors 341-345 of the BHA 340. The vibration dampening tool 520 includes an upper housing 541 coupled to a lower housing 542. The upper end of the upper housing 541 is coupled to the lower end of the drillstring 325. The upper portion of the lower housing 542 is disposed inside the upper housing 541. An axial bore 543 in the upper housing 541 is in fluid communication with an axial bore 544 in the lower housing 542. The lower housing 542 is rotatable relative to the upper housing 541 and axially movable relative to the upper housing 541. A drill bit 348 is coupled to the lower end of the lower housing 542.

[0046] As shown in Figure 5, the upper portion of the lower housing 542 includes radially extending shoulders 545 that sealingly engage with the inner surface 546 of the upper housing 541. In this respect, a chamber 550 is defined between lower housing 542 and the outer housing 541. The pressure in the chamber 550 can be adjusted to cause the lower housing 542 to move axially relative to the upper housing 541. In this respect, the downhole WOB may be adjusted to mitigate the vibrations in the drillstring 325.

[0047] In some embodiments, the vibration dampening tool 520 is equipped with one or more radially extendable pads 560. For example, the vibration dampening tool 520 includes four pads circumferentially disposed around the outer housing 541. In one example, the pads 560 are disposed in a respective recess 562 formed in the outer housing 541. The pads 560 may be actuated into engagement with the inner surface of the wellbore 335. The pads 560 may be extended by increasing the pressure behind the pads 560 or retracted by decreasing the pressure behind the pads. The pads 560 may be urged into engagement with the wellbore wall to increase frictional contact between the drillstring 325 and the wellbore 335. In this respect, the vibrations in the drillstring 325 can be mitigated by adjusting the frictional contact between the drillstring 325 and the wellbore 335.

[0048] In operation, the measured downhole WOB and the downhole RPM are sent to the downhole controller 500. Optionally, the lower BHA states and the upper BHA states are also sent to the downhole controller 500. For example, the upper and lower BHA states sent to the downhole controller 500 include BHAcompression, torsion, rotational speed, and other suitable BHA states. The downhole controller 500 may be configured as a Hint controller, such as the Hint controller shown in Figure 4. In one example, the measured sensor data sent to the downhole controller 500 may indicate the presence of undesired vibrations. For example, vibration indicators include a low downhole WOB, a high downhole RPM, or both. When a low downhole WOB is detected, the downhole controller 500 may increase the pressure differential between the pressure in the bore 543 in the upper housing and the pressure in the chamber 550. For example, downhole controller 500 can increase pressure in the bore 543 of the upper housing, decrease the pressure in the chamber 550, or both. As a result of the increased pressure differential, the lower housing 542 is extended out of the upper housing 541, thereby increasing the downhole WOB of the BHA 540. An increase in the downhole WOB mitigates the axial vibrations of the BHA 540.

[0049] In another example, when a high downhole RPM is detected, the downhole controller 500 may increase the pressure behind the pads 560, thereby extending the pads 560 into contact with the wall of the wellbore 335 or increasing frictional contact with the wall of the wellbore 335. The increase in the frictional contact causes the downhole RPM to decrease, thereby mitigating the rotational vibrations of the BHA 540. It is contemplated that the downhole vibrations may be mitigated by adjusting one or more of the downhole WOB, the downhole RPM, or other downhole drilling parameters. In one embodiment, the signals to increase the pressures from the downhole vibration controller 500 to adjust the downhole WOB and the downhole RPM may be sent simultaneously to the respective downhole tools.

[0050] Figure 6 illustrates a flow diagram of a method 600 of mitigating vibrations of the BHA 340, 540 in a welbore 335. The method 600 may be used to detect and respond to the drilling vibrations at the BHA 340, 540.

[0051] At operation 502, the drilling vibrations are measured using one or more sensors 341-345 in the BHA 340, 540. In one example, the downhole WOB and the downhole RPM are measured using sensors in the BHA 540. Exemplary sensors include accelerometers for measuring rate of rotation and axial load. Inone example, the vibrations may be measured using distributed sensors in the BHA 540.

[0052] At operation 504, the measured vibration data are transmitted, either wired or wireless, to a downhole controller 500 located in the BHA 540. The downhole controller 500 is configured to determine the lower drillstring and / or BHA dynamic states and detect undesired vibrations. In some embodiments, the downhole controller 500 may receive data from one of the sensors or tools at the surface in addition to or as an alternative to the downhole sensors 341-345. For example, data from the load sensor 275 and the top drive torque sensor 265 can be transmitted to the downhole controller 500. Also, data relating to the mud flow rate, mud composition, and the choke valve opening can be transmitted to the downhole controller 500. The downhole controller 500 may use one or more of the downhole data or the surface data to detect downhole vibrations in the BHA 540.

[0053] At operation 506, when undesired vibrations are detected, the downhole controller 500 calculates the operational adjustments to the BHA 540, based on the preset drillstring dynamics. In one example, the downhole controller 500 is an Hinf controller that is configured to calculate the adjustments to the downhole WOB and the downhole RPM of the BHA 540. In one example, in response to detecting a low downhole WOB and high downhole RPM, the downhole controller 500 may increase the pressure differential between the pressure in the bore 543 in the upper housing and the pressure in the chamber 550. In this respect, the lower housing 542 is extended out of the upper housing 541, thereby increasing the downhole WOB of the BHA 540. In some embodiments, the downhole controller 500 may simultaneously increase the pressure behind the pads 560, thereby extending the pads 560 into contact with the wall of the wellbore 335 or increasing frictional contact with the wall of the wellbore 335. The increase in frictional contact causes the downhole RPM to decrease. The combined manipulation of the downhole WOB and RPM can thereby mitigate the coupled torsional-axial vibrations of the BHA 540.

[0054] At operation 508, the calculated operational adjustments to increase the pressure differential between the pressure in the bore 543 in the upper housingand the pressure in the chamber 550 and increase the pressure behind the pads 560 are simultaneously sent to the BHA 540. In this example, operational adjustments to the downhole WOB and downhole RPM are performed by adjusting the pressure differential in the BHA 540 and the pressure to the pads 560. In this respect, the control of the downhole WOB and the downhole RPM are coupled. In this manner, embodiments of the present disclosure provide a downhole automation system that can efficiently mitigate the vibrations in the BHA of a drillstring. Also, embodiments of the downhole automation system can effectively suppress vibrations in different directions of the BHA.

[0055] In some embodiments, the method includes using a second controller 410 in communication with one or more tools coupled to the rig 100 to mitigate the vibrations downhole. For example, the second controller 410 is in communication, either wired or wireless, with the tubular handling tool 116 such as the top drive or the drawworks 120. In some embodiments, the second controller 410 is MIMO controller such as a LQI controller, an H2 controller, or an Hinf controller.

[0056] The method also includes transmitting the measured vibration data to the second controller 410. In turn, the second controller 410 is configured to calculate the operational adjustments to at least one of the top drive 116 or the drawworks 120 to decrease vibrations in the bottom hole assembly 540. In one example, the operational adjustments to the top drive 116 includes reducing the torque applied by the top drive 116 to adjust the downhole RPM. In another example, the operational adjustments to the drawworks 120 includes extending the cable 106 supporting the top drive 116 and the drillstring 325 to adjust the downhole WOB. The calculated operational adjustments are then sent to at least one of the top drive or the drawworks to decrease vibrations in the bottom hole assembly. In some embodiments, in addition to or alternative to the second controller 410, the downhole controller 500 communicates with one or more tools coupled to the rig 100 to mitigate the vibrations downhole. In some embodiments, the downhole controller 500 calculates and sends operational adjustments to the second controller 410, or vice versa.

[0057] Figure 8 illustrates another exemplary embodiment of a vibration dampening tool 720 suitable for use with a BHA, such as BHA 340 or BHA 540, and methods disclosed herein (e.g., method 600), according to some embodiments. Figures 9A and 9B are partial views of the dampening tool 720. Figures 10 and 11 are different cross-sectional views of the vibration dampening tool 720.

[0058] In some embodiments, the vibration dampening tool 720 includes an upper housing 741 for coupling with the lower end of the drillstring 325. The vibration dampening tool 720 also includes a valve motor 747, a rotary valve 770, and a pad housing 780. The valve motor 747 and the rotary valve 770 are disposed between the upper housing 741 and the pad housing 780. The motor 747 is configured to rotate the rotary valve 770 relative to the pad housing 780. A drill bit 348 is coupled to the lower end of the vibration dampening tool 720. One or more sealing members 727, such as sealing rings, can be disposed between the components of the dampening tool 720 to prevent leakage.

[0059] In some embodiments, the rotary valve 770 includes an upper tubular body 772, a lower tubular body 778, and an annular body 775 disposed between the upper tubular body 772 and the lower tubular body 778. An axial bore 773 extends through the length of the rotary valve 770. The axial bore 773 is in fluid communication with an axial bore 743 in the upper housing 741. The upper tubular body 772 is coupled to the valve motor 747. The lower tubular body 778 extends through the pad housing 780. The rotary valve 770 is rotatable relative to the pad housing 780. In some embodiments, one or more bearings 766 is used to facilitate rotation of the rotary valve 770 relative to the pad housing 780.

[0060] In some embodiments, the upper tubular body 772 includes one or more upper channels 782. In one example, the upper tubular body 772 includes three circumferentially spaced upper channels 782. The upper channels 782 are in fluid communication with a connector channel 785 in the annular body 775. The connector channel 785 also fluidly communicates with the axial bore 773 and one or more lower channels 786 circumferentially spaced around the annular body 775. In one example, the annular body 775 includes three circumferentially spacedlower channels 786. The lower channels 786 may have any suitable cross-sectional shapes, such as circular, oval, or arcuate. In the example shown in Figures 9A and 9B, the lower channels 786 have an arcuate shape.

[0061] The pad housing 780 is equipped with one or more radially extendable pads 760. For example, the pad housing 780 includes six pads 760 circumferentially disposed around the pad housing 780. However, any suitable number of pads 760 may be used, such as two, three, four, eight, or more pads 760. In some embodiments, the pads 760 are disposed in a respective recess 762 formed in the pad housing 780. The pads 760 may be actuated into engagement with the inner surface of the wellbore 335. The pads 760 may be extended by increasing the pressure behind the pads 760 or retracted by decreasing the pressure behind the pads 760. The pads 760 may be urged into engagement with the wellbore wall to increase frictional contact between the drillstring 325 and the wellbore 335. In this respect, the vibrations in the drillstring 325 can be mitigated by adjusting the frictional contact between the drillstring 325 and the wellbore 335.

[0062] In some embodiments, the pad housing 780 includes one or more pad channels 796 in selectively fluid communication with the lower channels 786. For example, the pad housing 780 may include three circumferentially spaced pad channels 796. In this respect, rotation of the rotary valve 770 relative to the pad housing 780 will place the lower channels 786 in or out of fluid communication with the pad channels 796. The lower channels 786 fluidly communicate with the recess 762 retaining the pads 760. In this respect, when the lower channels 786 are aligned with the pad channels 796, a downhole fluid, such as mud, can be supplied to the recess 762 and apply pressure to the pads 760 to extend the pads 760 radially outward. When the lower channels 786 are not aligned with the pad channels 796, the downhole fluid is prevented from being supplied to the recess 762, thereby allowing the pads 760 to retract. In some embodiments, the alignment between the lower channels 786 and the pad channels 796 can be controlled by the valve motor 747 to achieve alignment from 0% (e.g., no fluid communication) to 100% (e.g., fluid fully supplied) to change the extension and / or retraction of the extendable pads 760. In some embodiments, the fluid leaving the pad channels 796 may return to the axial bore 773 and flow further downhole, such as to the drillbit 348. In some embodiments, the fluid leaving the pad channels 796 may directly enter the annulus between the drillstring 325 and the wellbore 335, without passing through the drill bit 348.

[0063] In some embodiments, when a high downhole RPM is detected, the downhole controller 500 may increase the pressure behind the pads 760, thereby extending the pads 760 and increasing the frictional contact between the drillstring 325 and the wellbore 335. For example, the downhole controller 500 may cause the valve motor 747 to rotate the lower channels 786 into alignment with the pad channels 796. Thereafter, downhole fluid supplied into rotary valve 770 will flow through the upper channels 782, the connecting channels 785, and the lower channels 786. Then, the fluid will flow from the lower channels 786 into the pad channels 796 and into the recesses 762 retaining the pads 760. The fluid applies pressure to the pads 760, thereby extending the pads 760 into contact with the wall of the wellbore 335 or increasing frictional contact with the wall of the wellbore 335. The increase in the frictional contact causes the downhole RPM to decrease, thereby mitigating the rotational vibrations of the BHA 540 or BHA 340.

[0064] Embodiments of the present disclosure provides systems and methods of suppressing detrimental drilling vibrations in a much faster and more efficient manner. In some examples, the disclosed controllers, such as the MIMO controllers, can reduce the stabilization time and energy consumption for drilling stabilization. Figure 7 shows Table 1 of vibration mitigation results of a commercial top drive controller (“Top drive”) and two MIMO controllers, specifically, a surface LQI of Figure 3 (“SF LQ I”), and a downhole Hinf controller of Figure 4 (“DH H inf”). In case 1 , the vibration stabilization times for the SF LQI controller and the DH Hinf controller were 3.3 seconds and 6 seconds, respectively. In contrast, the vibration stabilization times for the commercial top drive controller was more than 60 seconds. Additionally, the torsional energy consumption of the commercial top drive controller was thirty times more than the SF LQI controller and nearly ten times more than the DH Hinf controller. In case 2, the vibration stabilization times for SF LQI and the DH Hinf were 8.1 seconds and 11.2 seconds, respectively. In contrast, the commercial top drive controller failed to stabilize the vibration.

[0065] By targeting the vibrations where they occur, embodiments of the vibration control system and method can mitigate vibrations before the vibrations are fully propagated, thereby protecting drilling tools from premature damage. Embodiments of the vibration control system and method seeks to suppress of coupled vibrations in different directions in the BHA. In some embodiments, the vibration control system and method does not require communication between the BHA and surface equipment. For example, the vibration control system and method uses downhole vibration data to mitigation the vibrations in the BHA. The localize nature of the vibration control system advantageously provides for increased robustness and effective solutions for vibration-free drilling in different well trajectories and complex downhole environments, such as deep oil and gas, geothermal and CO2 / H2 / waste storage wells.

[0066] In some embodiments, a method of operating a rig includes measuring downhole vibration data in a bottom hole assembly. The measured downhole vibration data is transmitted to a downhole controller located in the bottom hole assembly. The downhole controller calculates an operational adjustment to the bottom hole assembly to decrease vibrations in the bottom hole assembly. The operational adjustment is sent to the bottom hole assembly to decrease vibrations in the bottom hole assembly.

[0067] In some embodiments, a downhole tool includes an upper housing having an upper bore and a lower housing having a lower bore. The lower housing is coupled to and axially movable relative to the upper housing. The downhole tool also includes a pressure chamber defined between the upper housing and the lower housing. The pressure in the pressure chamber is adjustable to axially move the lower housing, thereby adjusting a weight-on-bit applied by the downhole tool.

[0068] In some embodiments, the downhole controller comprises a multi-input-multi-output downhole controller.

[0069] In some embodiments, the downhole controller comprises a linear-quadratic-integration (LQI) controller, an H2 controller, a PID controller, a state feedback controller, or an Hinf controller.

[0070] In some embodiments, measuring downhole vibration data comprises measuring at least one of a downhole weight-on-bit (WOB) of the bottom hole assembly or a downhole rate of rotation (RPM) of the bottom hole assembly.

[0071] In some embodiments, calculating the operational adjustment comprises calculating the operational adjustment based on preset drillstring dynamics.

[0072] In some embodiments, calculating the operational adjustment comprises calculating the operational adjustment to a downhole weight-on-bit of the bottom hole assembly, a downhole rate of rotation of the bottom hole assembly, or both

[0073] In some embodiments, the operational adjustment to the downhole weight-on-bit is performed by adjusting a pressure differential in the BHA.

[0074] In some embodiments, the operational adjustment to the downhole rate of rotation is performed by adjusting a pressure differential in the BHA.

[0075] In some embodiments, the bottom hole assembly comprises an upper housing; a lower housing coupled to and axially movable relative to the upper housing; a chamber defined between the upper housing and the lower housing; and a radially extendable pad coupled to the upper housing.

[0076] In some embodiments, calculating the operational adjustment comprises calculating the operational adjustment to a downhole weight-on-bit of the bottom hole assembly, a downhole rate of rotation of the bottom hole assembly, or both

[0077] In some embodiments, the operational adjustment to the downhole weight-on-bit is performed by adjusting a pressure differential across the chamber.

[0078] In some embodiments, increasing the pressure differential causes the lower housing to extend outward relative to the upper housing.

[0079] In some embodiments, the operational adjustment to the downhole rate of rotation is performed by adjusting a pressure applied to the pad.

[0080] In some embodiments, increasing the pressure to the pad causes the pad to extend radially outward relative to the upper housing.

[0081] In some embodiments, the rig includes a second controller.

[0082] In some embodiments, the second controller is a multi-input-multi-output controller.

[0083] In some embodiments, the second controller comprises a linear-quadratic-integration (LQI) controller, an H2 controller, a PID controller, a state feedback controller, or an Hint controller.

[0084] In some embodiments, the second controller calculates an operational adjustment to at least one of a top drive or a drawworks to decrease vibrations in the bottom hole assembly and sends the operational adjustment to at least one of the top drive or the drawworks to decrease vibrations in the bottom hole assembly.

[0085] In some embodiments, adjusting the operational adjustment to the top drive comprises adjusting a torque applied by the top drive.

[0086] In some embodiments, adjusting the operational adjustment to the drawworks comprises adjusting a length of a cable coupled to the top drive.

[0087] In some embodiments, the method includes transmitting data from surface tools located on a rig floor to the downhole controller.

[0088] In some embodiments, the surface tools include one or more of a top drive, drawworks, mud pump system, and choke valve.

[0089] In some embodiments, data from the surface tools includes one or more of top drive torque, axial load, mud flow rate, mud composition, and choke valve opening.

[0090] In some embodiments, transmitting measured downhole vibration data comprise transmitting the measured downhole vibration data via wire or wireless communication.

[0091] In some embodiments, the method includes transmitting data from at least one of a sensor or a tool located at the surface to the downhole controller via wire or wireless communication.

[0092] In some embodiments, sending the operational adjustment comprises sending the operational adjustment via wire or wireless communication.

[0093] In some embodiments, the downhole tool includes a radially extendable pad coupled to the upper housing.

[0094] In some embodiments, the downhole tool includes a downhole controller located in the downhole tool. The downhole controller is configured to calculate an operational adjustment to the downhole tool to decrease vibrations in the downhole tool and to send the operational adjustment to decrease vibrations in the downhole tool.

[0095] In some embodiments, the operational adjustment causes the lower housing to move axially.

[0096] In some embodiments, the operational adjustment causes the pad to extend radially relative to the upper housing.

[0097] It is contemplated that any one or more elements or features of any one disclosed embodiment or example may be beneficially incorporated in any one or more other non-mutually exclusive embodiments or examples. While the foregoing is directed to embodiments of the present disclosure, other and further embodiments of the disclosure may be devised without departing from the basic scope thereof, and the scope thereof is determined by the claims that follow.

Claims

What is claimed is:

1. A method of operating a rig, comprising:measuring downhole vibration data in a bottom hole assembly; transmitting measured downhole vibration data to a downhole controller located in the bottom hole assembly;calculating, using the downhole controller, an operational adjustment to the bottom hole assembly to decrease vibrations in the bottom hole assembly; and sending the operational adjustment to decrease vibrations in the bottom hole assembly.

2. The method of claim 1, wherein the downhole controller comprises a multi-input-multi-output downhole controller.

3. The method of claims 1 or 2, wherein the downhole controller comprises a linear-quadratic-integration (LQI) controller, an H2 controller, a PID controller, a state feedback controller, or an Hinf controller.

4. The method of any preceding claim, wherein measuring downhole vibration data comprises measuring at least one of a downhole weight-on-bit (WOB) of the bottom hole assembly or a downhole rate of rotation (RPM) of the bottom hole assembly.

5. The method of any preceding claim, wherein calculating the operational adjustment comprises calculating the operational adjustment based on preset drillstring dynamics.

6. The method of any preceding claim, wherein calculating the operational adjustment comprises calculating the operational adjustment to a downhole weight-on-bit of the bottom hole assembly, a downhole rate of rotation of the bottom hole assembly, or both7. The method of any preceding claim, wherein the bottom hole assembly comprises:an upper housing;a lower housing coupled to and axially movable relative to the upper housing; a chamber defined between the upper housing and the lower housing; and a radially extendable pad coupled to the upper housing.

8. The method of any preceding claim, wherein calculating the operational adjustment comprises calculating the operational adjustment to a downhole weight-on-bit of the bottom hole assembly, a downhole rate of rotation of the bottom hole assembly, or both9. The method of any preceding claim, wherein the operational adjustment to the downhole weight-on-bit is performed by adjusting a pressure differential across the chamber.

10. The method of any preceding claim, wherein increasing the pressure differential causes the lower housing to extend outward relative to the upper housing.

11. The method of any preceding claim, wherein the operational adjustment to the downhole rate of rotation is performed by adjusting a pressure applied to the pad.

12. The method of any preceding claim, further comprising a second controller located on the rig.

13. The method of any preceding claim, further comprising:calculating, using the second controller, an operational adjustment to at least one of a top drive or a drawworks to decrease vibrations in the bottom hole assembly; andsending operational adjustment to at least one of the top drive or the drawworks to decrease vibrations in the bottom hole assembly.

14. The method of any preceding claim, further comprising transmitting data from surface tools located on a rig floor to the downhole controller.

15. The method of any preceding claim, wherein data from the surface tools includes one or more of top drive torque, axial load, mud flow rate, mud composition, and choke valve opening.

16. A downhole tool, comprising:an upper housing having an upper bore;a lower housing having a lower bore, the lower housing coupled to and axially movable relative to the upper housing; anda pressure chamber defined between the upper housing and the lower housing,wherein a pressure in the pressure chamber is adjustable to axially move the lower housing, thereby adjusting a weight-on-bit applied by the downhole tool.

17. The downhole tool of claim 16, further comprising a radially extendable pad coupled to the upper housing.

18. The downhole tool of claims 16 or 17, further comprising a downhole controller located in the downhole tool, the downhole controller configured to:calculate an operational adjustment to the downhole tool to decrease vibrations in the downhole tool; andsend the operational adjustment to decrease vibrations in the downhole tool.

19. The downhole tool of any of claims 16 to 18, wherein the operational adjustment causes the lower housing to move axially.

20. The downhole tool of any of claims 16 to 19, wherein the operational adjustment causes the pad to extend radially relative to the upper housing.

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