Patent Application
20140151122
Various types of drill strings are deployed in a borehole for exploration and production of hydrocarbons. A drill string generally includes drill pipe and a bottomhole assembly (BHA). While deployed in the borehole, the drill string may be subject to a variety of forces or loads. For example, the BHA or other components can experience rotation vibrations having various frequencies. Such vibrations, including high frequency vibrations, can cause irregular downhole rotation and reduce component life.
An apparatus for reducing vibration includes: a damping assembly configured to be fixedly attached to a downhole component, the downhole component configured to rotate within a borehole in an earth formation, the damping assembly having a damping frequency that is tuned relative to a selected natural vibration frequency of the rotating downhole component to reduce vibration due to component rotation.
A method of reducing vibration includes: disposing a downhole component into a formation, the downhole component fixedly attached to a damping assembly, the downhole component configured to rotate within a borehole in an earth formation; performing a downhole operation that includes rotating the downhole component; and reducing vibration due to component rotation by the damping assembly, the damping assembly having a damping frequency that is tuned relative to a selected natural vibration frequency of the rotating downhole component.
The subject matter, which is regarded as the invention, is particularly pointed out and distinctly claimed in the claims at the conclusion of the specification. The foregoing and other features and advantages of the invention are apparent from the following detailed description taken in conjunction with the accompanying drawings, wherein like elements are numbered alike, in which:
Disclosed are exemplary apparatuses, systems and methods for reducing or mitigating harmful vibrations that occur in downhole components, such as drill strings and bottomhole assemblies (BHAs), during borehole operations. An embodiment of an apparatus and method include utilization of a tuned mass damper (TMD) disposed in one or more downhole components of a borehole string as an added degree of freedom to mitigate rotational oscillations occurring in the string. In one embodiment, the tuned mass damper is actively tuned to damp rotational oscillations having high frequencies that occur due to rotational motion of the string.
Referring to
As described herein, “string” refers to any structure or carrier suitable for lowering a tool or other component through a borehole or connecting a drill bit to the surface, and is not limited to the structure and configuration described herein. The term “carrier” as used herein means any device, device component, combination of devices, media and/or member that may be used to convey, house, support or otherwise facilitate the use of another device, device component, combination of devices, media and/or member. Exemplary non-limiting carriers include casing pipes, wirelines, wireline sondes, slickline sondes, drop shots, downhole subs, bottomhole assemblies and drill strings.
The drilling assembly 18, which may be configured as a bottomhole assembly (BHA), includes a drill bit 20 that is attached to the bottom end of the drill string 14 via various drilling assembly components. The drilling assembly 18 is configured to be conveyed into the borehole 12 from a drilling rig 24. The drilling assembly components includes various components that provide structural and operational support to the drill bit 20 and to drill bit cutters 22, as well as operably connect the drill bit 20 and the cutters 22 to the drill string 14. Exemplary drilling assembly components include a drill bit body 26 operably connected to the cutters 22, and other drilling assembly components 30, such as a drilling motor, stabilizer and/or steering assembly.
A processing unit 32 is connected in operable communication with the drilling assembly 18 and may be located, for example, at a surface location, a subsea location and/or a surface location on a marine well platform or a marine craft. The processing unit 32 may also be incorporated with the drill string 14 or the drilling assembly 18, or otherwise disposed downhole as desired. The processing unit 32 may be configured to perform functions such as controlling the drilling assembly 18, transmitting and receiving data, processing measurement data, monitoring the drilling assembly 18, and performing simulations of the drilling assembly 18 using mathematical models. The processing unit 32, in one embodiment, includes a processor 34, a data storage device (or a computer-readable medium) 36 for storing, data, models and/or computer programs or software 38.
In one embodiment, the drill bit 20 and/or drilling assembly 18 includes one or more sensors 40 and related circuitry for estimating one or more parameters relating to the drilling assembly 18. For example, a distributed sensor system (DSS) is disposed at the drilling assembly 18 and includes a plurality of sensors 40. The sensors 40 perform measurements associated with the motion of the drilling assembly 18 and/or the drill string 14, and may also be configured to measure environmental parameters such as temperature and pressure. Non-limiting example of measurements performed by the sensors include vibrations, accelerations, velocities, distances, angles, forces, moments, and pressures. In one embodiment, the sensors 40 are coupled to a downhole electronics unit 42, which may receive data from the sensors 40 and transmit the data to a processing system such as the processing unit 32. Various techniques may be used to transmit the data to the processing unit 32, such as mud pulse, electromagnetic, acoustic telemetry, or wired pipe.
In order to reduce or mitigate such vibrations, the system 10 includes a tuned damping assembly 44 configured to mitigate rotational vibrations experienced by BHAs or other component. As described herein, “rotational vibrations” refer to vibrations that occur due to the rotational motion of the string and/or components thereof (e.g., BHAs, Logging-while-drilling subs, drill bits and others). Rotational vibrations can be distinguished from vibrations due to axial movement, e.g., due to the drill bit contacting the bottom of the borehole, and vibrations due to stick-slip and other behaviors. Exemplary rotational vibrations include high frequency vibrations (e.g., on the order of hundreds of Hz), although rotational vibrations can be experienced at various other frequencies, and thus rotational vibration frequencies that can be mitigated or reduced by the damping assembly 44 are not limited to the specific examples described herein. In one example, such high frequency rotational vibrations can occur at about 25 Hz to about 300 Hz or higher. Exemplary high frequency rotations are illustrated in
In one embodiment, the damping assembly 44 includes a tuned mass damper (TMD). A TMD is a vibrating auxiliary mass that has vibration movements that are contrary to those of the component or structure to which it is attached. The auxiliary mass is elastically supported and tuned for the frequency that is to be reduced or eliminated. Vibration of the auxiliary mass causes inertial forces that compensate the component's movements by depriving vibration-energy from the component, which increases damping.
The damping sub 54 includes a housing 56 that defines or includes an interior cavity 60, within which the damping assembly 44 is disposed. The housing 56 or a portion thereof is attached to the damping assembly 44 such that rotational motion is transferred from the housing 56 to the assembly 44. The housing 56 is attached or coupled to the drill string 14 and/or drilling assembly such that torque is transferred from the mud motor or surface drive.
In the example of
In one embodiment, the damping sub 54 includes a conduit or other mechanism to allow fluid to be circulated or advanced therethrough, such as drilling fluid to be circulated during a drilling operation. For example, the housing 56 and/or the damping assembly 44 may define a fluid conduit 58 or other means to allow fluid such as drilling mud to flow therethrough. The mass 48 may be formed as a ring having a central opening, and the hollow pipe 50, the mass 48 and the housing 56 define a central fluid conduit 58.
In one embodiment, the cavity 60 is configured to retain a viscous damping fluid therein. For example, as shown in
The damping fluid viscosity provides a damping effect due to viscous resistance to shear created by the relative movement of the mass 48 and the housing 56 or other primary mass. In some embodiments, the inertial or auxiliary mass 48 has a shape configured to provide a gap a having a relatively constant thickness that is sufficient to produce a damping effect based on shear resistance. For example, the inertial mass 48 has a cylindrical or toroid shape defining an outer surface that works in conjunction with the damping fluid and a cylindrical inner surface of the cavity.
For example, as shown in
In one embodiment, shown in
In one embodiment, the assembly 44 is configured as an active tuned damping assembly having damping properties or parameters that can be actively adjusted or tuned prior to deployment and/or downhole during a drilling operation. The assembly can be tuned by actively changing damping parameters such as damping properties of the fluid, stiffness properties of the spring 50 or inertia properties of the inertia mass 48. The parameters may be adjusted or controlled by a user (e.g., a human operator) and/or processor. For example, the surface processing unit 32 and/or the downhole electronics unit 42 may be configured as a controller that receives vibration and/or rotation information from the sensors 40 and adjusts damping parameters based on such information. The controllers may use various types of devices or actuators for adjusting the damping, such as an electric device, e.g., a coil in a magnetic field or an eddy current brake.
In one embodiment, the assembly is configured to adjust characteristics of the damping fluid. For example, viscosity of the fluid may be adjusted using various catalysts or the fluid can be tuned by adjusting an orifice or a throttle.
An exemplary damping fluid has a viscosity that is adjustable based on exposure to a catalyst. For example, the fluid is a smart fluid such as a magnetorheologic (MR) fluid having a viscosity that can be adjusted by applying a magnetic field. In this example, an actuator such as an electromagnet is included proximate to the fluid, e.g. inside or near the cavity 60 and/or the gap 62, for application of the magnetic field. The electromagnet may be electrically connected to a surface or downhole power source that is controlled by a processor such as the surface processing unit 32. Other examples of catalysts that may be used with this embodiment include electrodes applied to electrorheologic fluids, temperature controls and chemical additives that can be applied to the fluid, e.g., via a reservoir and controllable valve in the damping sub 54, to alter the fluid viscosity.
In one embodiment, the physical and/or inertial properties of the inertia mass 48 are adjustable to change the natural frequency of the assembly 44. For example, the inertia mass may include a hydraulically expandable or retractable ring, or a piezoelectric material. Adjustment of the inertia mass 48 results in a change in rotational inertia, which in turn changes the natural frequency of the assembly.
In one embodiment, the spring stiffness can be adjusted downhole. For example, the spring may be a variable stiffness spring that includes an actuator connected to the spring 50. The actuator can be actuated by a suitable mechanism (e.g., electric, pneumatic or hydraulic) to apply a twisting force to the spring 50.
The embodiments described herein can be used to adjust the natural damping frequency ωa of the assembly 44 relative to a selected natural frequency ωn of the rotating string or other component. In one embodiment, the drill string or other downhole component may have multiple natural frequencies, and the assembly is adjusted to one of these frequencies, such as the natural frequency that is or would be considered most harmful.
The damping response of the component depends on the ratio of these two frequencies. The response is the least when the ratio is equal to unity, and thus an optimal tuned frequency of the damping assembly 44 may be selected as a fraction or percentage of the natural frequency ωn.
For example,
In one embodiment, one or more computer models of rotating components based on, e.g., the finite element method or other numerical methods may be used to identify the component's natural frequency and the frequency to be tuned. Such computer models may utilize modal, forced vibration or transient analysis in the time domain, frequency domain, or a hybrid domain. The model may be generated prior to deploying the assembly and/or generated or updated based on various measurements after deployment, e.g., during a downhole operation. For example, the identified natural frequency based on a model may be used as an initial estimate and then improved in combination with measurements in closed-loop calculations downhole.
In one embodiment, the assembly 44 is configured to be able to reduce axial vibration as well as torsional or rotational vibration. For example, the inertia mass 48 or other auxiliary mass is operably connected to a mechanism that couples torsional or rotational movement and axial movement. For example, instead of the bearing 64, the inertia mass 48 is configured as a ring and is mounted on a slanted splined shaft 66 shown in
The types and configurations of damping assemblies that may be used are not limited to the specific embodiments and configurations described herein. Any suitable damping mechanism that mitigates rotational vibration may be used, such as various types of rotary dampers or rotary dashpot devices.
The damping assembly 44 may be utilized in a method of controlling vibration in a downhole carrier, such as the drill string 14. The method may be executed by a user and/or a computer processing system (e.g., the processing unit 32 and/or the processor 42. The method includes one or more stages. In one embodiment, the method includes the execution of all of stages in the order described. However, certain stages may be omitted, stages may be added, or the order of the stages changed. In addition, the method may be performed in real-time or near real-time during a downhole operation, and may be performed on a substantially continuous or periodic basis.
In a first stage, the carrier, e.g., the drill string 14, is disposed at a borehole or formation, and a drilling operation is commenced. The first stage may also include manufacture, assembly and/or initial tuning of the damping assembly 44, such as by selecting inertia mass properties, selecting or adjusting spring stiffness and/or selecting or adjusting damping fluid properties.
In the second stage, drill string 14 or other component (e.g., BHA) vibration characteristics are measured and/or calculated. For example, the sensors 40 may include vibration sensors, accelerometers, stress or strain sensors or other types of sensors that are used to transmit vibration data, and/or parameters data related to vibration, to a processor or user.
In the third stage, the damping sub 54 is adjusted to adjust the natural frequency of the damping assembly 44, i.e., the damping frequency, to improve or maximize the damping effect on the drill string 14. For example, an electric current or magnetic field is applied to the damping fluid to alter the viscosity and thereby change the damping assembly's frequency to coincide with a selected ratio. In other examples, the spring stiffness may be adjusted, or parameters of the inertial mass are adjusted to change the rotation and/or clearance gap.
The systems, apparatuses and methods described herein provide various advantages over prior art techniques. For example, the apparatuses described herein may be semi-active and/or active designs, having the capability to modify parameters of the damper (e.g., stiffness, damping or inertia) adaptively, such that rotational vibration can be effectively mitigated even as vibrational forces change downhole.
Generally, some of the teachings herein are reduced to an algorithm that is stored on machine-readable media. The algorithm is implemented by the computer processing system and provides operators with desired output.
In support of the teachings herein, various analysis components may be used, including digital and/or analog systems. The digital and/or analog systems may be included, for example, in the downhole electronics unit 42 or the processing unit 32. The systems may include components such as a processor, analog to digital converter, digital to analog converter, storage media, memory, input, output, communications link (wired, wireless, pulsed mud, optical or other), user interfaces, software programs, signal processors (digital or analog) and other such components (such as resistors, capacitors, inductors and others) to provide for operation and analyses of the apparatus and methods disclosed herein in any of several manners well-appreciated in the art. It is considered that these teachings may be, but need not be, implemented in conjunction with a set of computer executable instructions stored on a computer readable medium, including memory (ROMs, RAMs), optical (CD-ROMs), or magnetic (disks, hard drives), or any other type that when executed causes a computer to implement the method of the present invention. These instructions may provide for equipment operation, control, data collection and analysis and other functions deemed relevant by a system designer, owner, user or other such personnel, in addition to the functions described in this disclosure.
Further, various other components may be included and called upon for providing for aspects of the teachings herein. For example, a power supply (e.g., at least one of a generator, a remote supply and a battery), cooling component, heating component, motive force (such as a translational force, propulsional force, or a rotational force), digital signal processor, analog signal processor, sensor, magnet, antenna, transmitter, receiver, transceiver, controller, optical unit, electrical unit or electromechanical unit may be included in support of the various aspects discussed herein or in support of other functions beyond this disclosure.
It will be recognized that the various components or technologies may provide certain necessary or beneficial functionality or features. Accordingly, these functions and features as may be needed in support of the appended claims and variations thereof, are recognized as being inherently included as a part of the teachings herein and a part of the invention disclosed.
While the invention has been described with reference to exemplary embodiments, it will be understood that various changes may be made and equivalents may be substituted for elements thereof without departing from the scope of the invention. In addition, many modifications will be appreciated to adapt a particular instrument, situation or material to the teachings of the invention without departing from the essential scope thereof. Therefore, it is intended that the invention not be limited to the particular embodiment disclosed as the best mode contemplated for carrying out this invention, but that the invention will include all embodiments falling within the scope of the appended claims.
