For detailed understanding of the present invention, references should be made to the following detailed description of the preferred embodiment, taken in conjunction with the accompanying drawings, in which like elements have been given like numerals and wherein:
The teachings of the present invention can be applied in a number of arrangements to generally improve the drilling process by actively applying a dampening profile and/or a controlled vibration to a drill string and/or bottomhole assembly (BHA). Such improvements may include improvement in ROP, extended drill string life, improved bit and cutter life, reduction in wear and tear on BHA, and an improvement in bore hole quality. The term vibration as used herein refers generally to motion of a body but is not meant to imply an particular type of motion or time duration for the motion. The present invention is susceptible to embodiments of different forms. There are shown in the drawings, and herein will be described in detail, specific embodiments of the present invention with the understanding that the present disclosure is to be considered an exemplification of the principles of the invention, and is not intended to limit the invention to that illustrated and described herein.
Embodiments of the present invention control the behavior of a drill string and/or bottomhole assembly (BHA) in order to prevent or minimize the occurrence of harmful drill string/BHA motion and/or to apply a vibration to the drill string/BHA that improves one or more aspects of the drilling process (e.g., borehole quality, tool life, rate of penetration, etc.).
Referring initially to
Exemplary measurements 100 include measurements of parameters such as axial vibration, torsional vibration, drill string whirl, bit bounce, slip-stick, and other motion that, if of sufficient magnitude and duration, could damage the drill string and/or BHA. Other measurements include parameters such as drilling rate of penetration (ROP) and borehole quality that can affect the overall cost of drilling the wellbore. These measurements can be taken continuously, on specified intervals, or as-needed and transmitted to a surface and/or downhole processing unit for analysis 200. The processing unit can utilize any number of schemes for processing the measurement data. In one arrangement, pre-run modeling of the BHA and drill string is done to define optimal tool signatures, optimal drilling parameters, and out-of-norm vibration levels. The measurement data is processed and compared against the pre-run modeling to determine the nature and extent of any non-optimal or out of norm conditions (hereafter “non-beneficial condition”), if any.
If needed, the processing unit initiates corrective action 300 to address the non-beneficial condition by operating an active vibration device, which is discussed in detail below. In one arrangement, the processing unit can cause the active vibration device to apply a dampening profile and/or vibration over a range of frequencies and measure the drill string and/or BHA response to determine whether the non-beneficial condition has been alleviated. Merely for illustration, there is shown in
The effectiveness of the corrective action can be periodically checked in successive frequency sweeps. Periodicity of corrective action such as a frequency sweep can be based on one or more elements of the drilling operation such as a change in formation, a change in measured ROP, detection of a pre-determined condition, and/or a predetermined time period or instruction from the surface.
Aspects of the
A number of arrangements can be used to create vibrations or oscillations that counter a non-beneficial condition shifting a drill string or BHA condition from a non-optimal condition to a optimal or near optimal condition and/or mitigating one or more out of norm conditions. The terms vibrations and oscillation will be used interchangeably hereafter.
In one embodiment, a control unit 60 in conjunction with one or more active vibration control devices 62 applies a set of forces, displacements and/or frequencies to the drill string and/or BHA. Merely for convenience, such forces, displacements and frequencies will generally be referred to as vibrations. The control unit 60 selects operating parameters for the active vibration control device 62 that cause the active vibration control device 62 to generate a vibration that is calculated to mitigate a detected non-beneficial condition.
The control unit 60 can include a downhole processor and/or the surface processor that includes some or all of the processing, analyzing and communication capabilities discussed in
In one embodiment, the control unit 60 includes a calculation engine module adapted to process sensor data and determine corrective action as discussed in connection with
The calculation engine module can be configured to employ one or a combination of several user selectable control methodologies. Generally speaking, the calculation engine module can be set to manage drilling performance (efficiency) or mitigate harmful motion/vibration or some blend of both. As discussed earlier, mitigation of potentially damaging motion can be accomplished by imparting beneficial vibrations into the drilling system that cancel or reduce the damaging vibrations.
For managing drilling performance, the control unit 60 can include a drilling efficiency enhancement driver module as discussed previously. Using sensor measurement data and other input in real-time, this driver module is programmed to monitor drilling efficiency as defined by specific energy required to penetrate a given volume of rock divided by energy provided to the drilling system during this period of time. Using both predictive techniques and optionally real-time optimum parameter searching, the calculation engine module would alter the control signal provided to one or more active vibration control devices so as to super impose a non-damaging and controlled torsional and/or axial oscillation (vibration) on to the BHA to enhance the drilling efficiency as defined above.
In one embodiment, the active vibration control device is an active device that is capable of relatively fast response and can operate in axial, lateral and torsional modes. A single device need not provide all three modes of vibration cancellation nor do separate devices have to separately provide each mode of operation. By “active” it is meant that the device reacts to real-time dynamics of the BHA and drill string by adding energy (e.g., applying vibrations) that improves those dynamics in some manner if needed. By “relatively fast” it is meant that the active vibration control device can apply corrective action to a detected a non-beneficial condition quickly enough to alleviate that non-beneficial condition.
The active vibration control device can include of one or more materials having properties (volume, shape, deflection, elasticity, etc.) that exhibit a predictable response to an excitation or control signal. Suitable materials include, but are not limited to, electrorheological (ER) material that are responsive to electrical current, magnetorheological (MR) fluids that are responsive to a magnetic field, piezoelectric materials that responsive to an electrical current, electro-responsive polymers, flexible piezoelectric fibers and materials, and magneto-strictive materials. This change can be a change in dimension, size, shape, viscosity, or other material property. Additionally, the material is formulated to exhibit the change within milliseconds of being subjected to the excitation signal/field. Thus, in response to a given command signal, the requisite field/signal production and corresponding material property can occur within a few milliseconds. Thus, hundreds of command signals can be issued in, for instance, one minute. Accordingly, command signals can be issued at a frequency ranging from a small fractional to a large multiple of conventional drill strings and/or drill bits (i.e., several hundred RPM). The fluid or material response can be controlled to actively dampen unwanted vibrations and/or produce controlled oscillations in the required frequency range.
Referring now to
In one embodiment, the biasing elements 502 includes twin spring elements having a ‘K factor’ that allows full drilling and over pull forces to be transferred without bottoming or topping out the device 500. In another arrangement, two or more spring elements are coupled in parallel and a controllable coupling device 506 selectively couples a combination of spring devices to the sub housing 508 to create a wide ranging ‘K factor’ for different operations and to offer an additional degree of active control.
The damping chamber 504 is connected to the biasing element 502 with a shaft 510. The damping chamber 504 can include a controllable fluid 512. By altering a material property of the controllable fluid 512, the coefficient of damping provided by the chamber 504 can be increased or decreased. Thus, axial displacement and velocity of displacement can be user defined and actively controlled via the control unit 60 (
Referring now to
The device 520 can be controlled by a calculation engine module in a control unit 60 (
In some embodiments, a plurality of devices 520 are coupled together and controlled by one calculation engine module. Using a multiple set of stacked devices 520 can extend the range of available energy input (e.g., by the additive effect of the mass, velocity and direction).
The active axial device 520 can be used to cancel drill string motion such as unwanted bit bounce or could be used to actively induce axial forces at the drill bit to create a percussion effect. Using the device 520 in conjunction with passive or active damping and/or coupling device can allow a small section of the drill string to oscillate axially as desired (e.g., the drill bit), while the remainder of the string remained more or less axially fixed. In this case, the resulting axial ‘hammer’ can be located near the drill bit and decoupled from the drill string by placing a damping device above and between the axial hammer and the remainder of the BHA.
In another embodiment not shown, an axial hammer includes a mass suspended on a system of biasing members (complex springs) such that the mass oscillates axially and in a torsional mode. In one mode, the mass can be suspended to allow free rotation in only one direction while axially oscillating. During use, upon appropriate signals from the calculation engine module, a coupling device couples the mass to the system and imparts an axial and rotational impulse to the system. Selective coupling and/or selective rotation coupled with the axial hammer discussed above can produce a vertical and rotational impulse to the drill bit.
The coupling device 526 can be made in a number of embodiments. In one embodiment, controllable fluids such as MR or ER fluids are selectively energized with current to connect the mass 522 to the drill string 524. In another embodiment, magnets and electric coils are selectively energized to produce magnetic forces that connect the mass 522 to the drill string either directly or via MR/ER fluids. In still another embodiment, a mechanical clutch or MR/ER fluids coupled with slotted devices like ‘level-wind’ shafts can be utilized.
Referring now to
In one variation to the above-described embodiment, a fluid of fixed property flows via a flow circuit between a pair of chambers configured such that one chamber can increase in volume when the other chamber decreases in volume to thereby permit momentary relative rotation between the upper and lower subs 70,72. A controllable element associated with a flow restrictor can be used to actively change the flow rate in the flow circuit.
In another variation, the biasing elements include pairs of bow or leaf spring whose long axis is aligned with the axis of the drill string. System functionality remains the same and all aspects of the fluid damping elements remain the same.
Referring now to
Referring now to
Two common drill string torsional excitation modes are cyclic torsional vibrations from the drill bit and momentary sticking of the drill string to the bore hole wall, which is generally known as stick-slip. In both cases, the drilling string will torsionally bounce or oscillate while rotating at an average rotary rpm. Devices made in accordance with the present invention can be used to minimize, negate or arrest these torsional oscillations. Further, the imparting of beneficial torsional oscillations can be used to enhance cutting efficiency of the drill bit, which is discussed in commonly assigned and co-pending application titled “Improving Drilling Efficiency Through Beneficial Management Of Rock Stress Levels Via Controlled Oscillations Of Subterranean Cutting Elements”, U.S. Ser. No. 11/038,889, filed on Jan. 20, 2005, which is hereby incorporated by reference for all purposes.
Exemplary devices to actively control and manage or impart beneficial torsional vibrations into the drill string include torque converter based systems, high speed and high density mass flywheel systems, and torsional spring mass devices.
Referring still to
In another application, the torque converter 600 can create beneficial torsional vibrations by allowing a baseline degree of continuous slip across the driven sub 72 versus the driving sub 70. Depending on the degree of slip, a heat rejection exchanger (not shown) could be required. A low level of slip can be established by selecting an ER fluid current value that results in, for example, a ten to fifteen percent average slip. After a time and frequency is determined by the control unit 60 (
The torsional vibrations spikes imparted above could be used independently or together with other disclosed devices to produce beneficial vibrations of the drill bit. The concurrent use of dampers in the system could prevent these induced vibrations from reaching other components within the drilling assembly.
The low level continuous slip torque converter disclosed above could also be used to remove other torsional vibrations by allowing the base line slip ratio to continually vary as required. If the slip was increased to be greater than the base line, then damping of other torsional string vibrations would occur. As noted above, reducing the base line slip would induce a torsional force. Thus, an appropriately programmed control unit could in real-time modulate the current supplied to the ER fluid so as to create a selected torque and speed pattern on the driven shaft regardless of input shaft speed fluctuations. The methodology of additive and subtractive superposition allows a single torque converter device to create a wide range of driven shaft behavior, from ‘dead’ smooth, to ‘square wave’ rough. Appropriately positioned motion sensors can be used to provide data regarding the relative movement of the several components.
Additionally, flywheel systems operating at high speed and having high mass spinning cylinders made of high density material, coupled with MR or ER fluids can be used to both damp and excite torsional behavior in a drilling assembly.
Referring now to
The cylinder 652 can rotate in the same direction of the rotation of the drill string 658 or rotate counter to the direction of the rotation of the drill string 658. If both rotations are the same, the momentary coupling creates a torque or speed spike. In a counter rotation scenario, momentary coupling dampens torque or speed spike in the direction of the string rotation. Also, a pair of controlled coupled counter spinning flywheels can be used to arrest torsional vibrations in either direction.
In another embodiment, a semi-active to passive version of the
Referring now to
In some embodiments, several units are employed and controlled by the control unit 60 (
As disclosed above, the torsional mass device could be independent or integral to one or more of the devices and systems discussed within.
Additionally, the active torsional control device 680 can be used to impart beneficial torsional vibrations to the bit to improve drilling performance or efficiency. To continually add energy to keep the torsional spring and mass arrangement ‘fully charged, a magnetic/coil interface (not shown) driven by an external or internal power source is can be used. In another arrangement, a hydraulic fluid powered device using a bleed stream from the high pressure drilling fluid can be used. In this case the hydraulic drive is coupled and selectively clutched (e.g., by using MR or ER fluids) to supply a torque to the mass when the mass is moving in the same direction as the hydraulic drive output. The energy level required can be extracted from the drilling fluid. This same arrangement can be used to re-supply energy to the axial mass system as well.
Further, the active torsional device can be used to cancel drill string motion, say unwanted string torsional oscillations or could be used to actively induce rotational forces at the bit to create a rotary percussion effect. One skilled in the art would also see many other cancellation and impartation actions this device could produce. The use of this device along with passive or active damping device could allow a small section of the drill string to oscillate rotationally as desired, say the bit, while the remainder of the string remained more or less torsionally stable relative to the primary string rotation. In this case a rotary ‘hammer’ would be located near the bit and decoupled for the string by placing a torsional damping device above and between the rotary hammer and the remainder of the BHA.
Drill string whirl behavior is characterized by a circular movement of the drill string within the borehole. This can be visualized as a buckled column spinning in the buckled condition where the bore hole wall acts to limit the displacement of the buckle. The speed of the whirl or rotating buckled column is typically slower than the rotation of the drill string and is often minimized by close relative diameters of the bore hole and components of the drill string.
Embodiments of the present invention can also be advantageously used to control whirling of the drill string. Whirling of the drill string damages, the bore hole wall, the drill string and at times components of tools within the drill string. Several operational and configuration procedures have been development over the years to minimize whirl and whirl related damage. However, most of these provisions tend to reduce drilling efficiency and alter the optimum way in which the well bore could be drilled. A means to actively damp whirl only when whirl was present would be beneficial.
Active Drill String Whirl Damping Devices as discussed herein sense and actively damp whirl. These devices can be independent or integral to other active devices. Additionally, these devices can be placed in single or multiple locations along the drill string and bottom hole assembly. The device could be controlled and driven by the control unit 60 (
Referring now to
The “laterally free” behavior is controlled by a group of chambers 710 dispersed circumferentially in an annular space 712 separating the drill pipe 702 and the device 700. The chambers 710, which can also be cylinders or link-like members, expand or contract as needed to dampen or stop the drill string 702 from whirling. In a manner previously described, the chambers 710 or cylinders are filled with a controllable fluid 711 such as MR or ER fluids. Using a control signal such as electrical current, the properties of these fluids and the flow of these fluids between chambers 710 or cylinders are actively altered in a manner previously described to affect the damping action.
In some embodiments, sensors 714 are placed in and around the chambers 710 to monitor and allow real-time control of the active and self-contained whirl damping device. These sensors 714 monitor conditions within the device, the movement of the drilling string 702 or both. Additionally, devices such as PZT modules or micro machines (not shown) can be imbedded in and around fluid flow ports (not shown) or within the chambers 710. Movement of the drill string 702 within the device could produce some or all of the power needed to actively operate the device 700. Excess power can be stored (batteries or capacitors) within the device or coupled to and supplied to other downhole devices. A suitable signal such as electrical current or a magnetic field is applied to the controllable fluid 711 by a control system 718 that includes a control unit, a driver and a power source in a manner previously described. The control unit can be the same as control unit 60 (
The foregoing description is directed to particular embodiments of the present invention for the purpose of illustration and explanation. It will be apparent, however, to one skilled in the art that many modifications and changes to the embodiment set forth above are possible without departing from the scope and the spirit of the invention. For example, some embodiments can combine spinning and axial masses within the same device to produce a desired combined effect. It is intended that the following claims be interpreted to embrace all such modifications and changes.