Abstract:
A device and system for improving efficiency of subterranean cutting elements uses a controlled oscillation super imposed on steady drill bit rotation to maintain a selected rock fracture level. In one aspect, a selected oscillation is applied to the cutting element so that at least some of the stress energy stored in an earthen formation is maintained after fracture of the rock is initiated. Thus, this maintained stress energy can thereafter be used for further crack propagation. In one embodiment, an oscillation device positioned adjacent to the drill bit provides the oscillation. A control unit can be used to operate the oscillation device at a selected oscillation. In one arrangement, the control unit performs a frequency sweep to determine an oscillation that optimizes the cutting action of the drill bit and configures the oscillation device accordingly. One or more sensors connected to the control unit measure parameters used in this determination.

Description:
CROSS-REFERENCE TO RELATED APPLICATIONS 
     This application is a continuation of U.S. patent application Ser. No. 11/038,889 filed Jan. 20, 2005. 
    
    
     BACKGROUND OF THE INVENTION 
     1. Field of the Invention 
     In one aspect, this invention relates generally to systems and methods for controlling the behavior or motion of one or more cutting elements to optimize the cutting action of the cutting element(s) against an earthen formation. 
     2. Description of Related Art 
     To obtain hydrocarbons such as oil and gas, boreholes are drilled by rotating a drill bit attached at a drill string end. Conventionally, the drill bit is rotated by rotating the drill string using a rotary table at the surface and/or by using a drilling motor in a bottomhole assembly (BHA). Because wellbore drilling can be exceedingly costly, considerable inventive effort has been directed to improving the overall efficiency of the drilling activity. One conventional measure for evaluating the efficiency of drilling activity is Specific Input Energy (Se), which the drill bit industry defines as the energy required to drill a specific volume of rock in a given time period, i.e. the input energy required to achieve a target ROP. 
     Generally speaking, drilling efficiency has not changed substantially since industry was capable of estimating or measuring Se. The Se required to drill a volume of rock is strongly influenced by the chip or cutting size generated at the face of the bit. In general Se increases and drilling efficiency declines as cuttings become progressively smaller. This relationship is driven by the amount of energy required to remove a given volume of rock from the parent rock. One can better understand this relationship by thinking of table salt grains vs. kidney beans. For a given volume within a container, more salt grains will be present than beans. It is also evident that more of total volume is contained in fewer beans than salt grains. If one takes a drill cutting the size of the bean and continues to reduce its size until all of its volume is in particles the size of salt grains, it is clear that addition energy has been required. For further illustration, consider a borehole drilled to produce an extremely thin kerf. This could be thought of as a core that is practically the diameter of the final drilled hole. Of course this has practical limits, but does tend to define the largest possible cutting and the minimum amount of energy used to break the core into smaller pieces. In this case drilling efficiency would be maximized from a drill cutting surface to a contained volume standpoint. Said differently, one wants to maximize cutting size and keep the surface area of the cuttings to a minimum; i.e., the cuttings volume to cuttings surface area ratio should be as large as possible. 
     Herein is the classic method of improving drilling efficiency or reducing Se. The bigger the cutting, the less work done on the undisturbed volume within the cutting. Thus, attempts have been made to increase cutting size to a practical maximum by through design of drill bits and, to some degree, BHA&#39;s. Conventional drill bits are provided with a number of cutting elements or cutters on their face. Increased cutting size can be achieved by increasing cutter size, depth of cut, and by increasing bit torque as long as the increased torque produces larger cuttings. There are practical limits to these methods and only limited change to average cutting size has occurred in the past 10 or 15 years. 
     The present invention address these and other needs relating to the efficiency of drill bit. 
     SUMMARY OF THE INVENTION 
     The present invention provides systems, methods and devices for controlling the behavior of a drill bit to optimize the cutting action of the drill bit vis-à-vis the drilled formation. For example, a controlled oscillation is applied to the drill bit so that once a rock crack or fracture at the cutter/rock face interface has begun, it can be maintained so that crack restart energy (stress) is not lost at fracture. Thus, this restart energy does not have to be added back to that rock structure before the crack further propagates. In one embodiment of the present invention, a controlled torsional force is momentarily superimposed on a constant drill bit rotation in a manner that maintains a substantially average bit rotation speed. The torsional force temporarily accelerates the cutting elements of the drill bit to at least maintain contact with a fracturing earthen formation and thereby maintain the cutting element and rock surface interface stress level. Thus, the cutting element and rock surface interface experiences a significantly lower loss of stored stress energy and the remaining stored stress energy can be used to initiate the subsequent rock fracture. 
     In an exemplary arrangement, a drilling system includes a conventional surface rig that conveys a drill string and a bottomhole assembly (BHA) into a wellbore in a conventional manner. The system also includes a plurality of sensors for measuring one or more parameters of interest, an oscillation device for oscillating a drill bit in the BHA, and a control unit for operating the oscillation device. The control unit uses the sensor measurement to determine parameters such as the frequency and amplitude of the oscillations that optimizes the drill bit cutting action (or the “optimizing oscillation”). In one embodiment, the oscillation device controls behavior of the drill bit by allowing only selected vibration or vibrations in the drill string and/or BHA to reach the drill bit. In such an arrangement, the oscillation device can be a largely passive device (i.e., not require energy input). In another embodiment, the oscillation device includes a drive unit that amplifies a selected frequency and/or shifts an existing frequency to a selected frequency. In yet other embodiments, the oscillation device is positioned proximate to the drill bit to create a force or forces that produce a selected drill bit oscillation. In still other embodiments, the oscillation device is configured to provide a pre-determined oscillation (e.g., a torsional oscillation at a selected frequency and amplitude) or range of oscillations and, therefore, is not controlled by a control unit. The configuration of such an oscillation device can be based on historical performance data for the drill bit, BHA, drill string as well as formation data collected from the well or an offset well. 
     In other aspects, the teachings of the present invention can be advantageously applied to increase the efficiency of various types of cutters used in drilling and completing operations. For example, the efficiency of cutters such as under-reamers and hole openers can also be improved by the present teachings. 
     Examples of the more important features of the invention have been summarized (albeit rather broadly) in order that the detailed description thereof that follows may be better understood and in order that the contributions they represent to the art may be appreciated. There are, of course, additional features of the invention that will be described hereinafter and which will form the subject of the claims appended hereto. 
    
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
       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: 
         FIG. 1  graphically illustrates the relationship between stress levels and the effectiveness of a drill bit in fracturing a rock; 
         FIG. 2  schematically illustrates an elevation view of a drilling system made according to one embodiment of the present invention; 
         FIG. 3  shows an oscillation device for controlling a drill bit made according to one embodiment of the present invention; and 
         FIG. 4  shows a torque resistance device bit made according to one embodiment of the present invention that is used in connection with a drill bit rotated by a drilling motor; 
         FIG. 5  shows an oscillation device according to one embodiment of the present invention that is positioned in a drill string; 
         FIG. 6A  shows an oscillation device made according to one embodiment of the present invention that is positioned in a drill bit; and 
         FIG. 6B  shows an oscillation device made according to one embodiment of the present invention that is positioned adjacent a cutting element. 
     
    
    
     DETAILED DESCRIPTION OF THE INVENTION 
     The teachings of the present invention can be applied in a number of arrangements to generally improve drilling efficiency. Such improvements may include improvement in ROP without increasing work done, improved bit and cutter life (e.g., as defined by volume drilling relative to wear), a reduction in waste energy (typically heat and vibration), reduction in wear and tear on BHA, and an improvement in bore hole quality. 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. 
     As will be seen in more detail below, the inventors have perceived that a major component in the energy balance of drilling is the amount of cyclic elastic or stored energy that is added and then released as drill-cutting chips are produced by the drill bit. In most brittle or semi brittle materials, elastic strain (deformation) occurs before a fracture, crack or tear can occur. This stored energy is required to reach the point of fracture. If the fracture releases stress at a rate greater than the rate additional stress is added, then generally speaking, the fracture will self-arrest and chip size will likely be defined. The energy released during fracture is ‘lost’ and must be added again before the fracture will continue to grow. 
     Embodiments of the present invention control the behavior of a drill bit in order to minimize the loss of stored stress energy and thereby maximize the cutting action of the drill bit against a rock formation. In one arrangement, an torsional oscillation applied to the drill bit enables the drill bit&#39;s cutting elements to maintain a stress at the cutter/rock face interface at a level that minimizes the loss of stress energy. Because this energy is not lost, the energy needed for further rock fracturing does not have to be added back to that rock formation. The frequency and amplitude of this torsional oscillation can be controlled to initiate, maintain and/or optimize this action. It should be understood, however, that the principles described above can be utilized with axial oscillations, lateral oscillations, and loadings having two or more components. Merely for convenience, a torsion oscillation is described below. 
     Referring initially to  FIG. 1 , there is shown a graph that illustrates some of the teachings of the present invention. The ordinate is a dimensionless stress unit and the abscissa is time or drill bit rotation. The behavior of a conventional drill bit is shown with solid line  10  and the behavior of a drill bit controlled according to embodiment of the present invention is shown with dashed line  12 . Conventionally, a rotary power device such as a drill string and/or drilling motor rotates the drill bit at a substantially constant rotational speed. Upon start of rotation, point  14  is a time at which a cutting element of the drill bit initially engages a rock surface. Rotation of the drill bit creates a stress build up at the interface between the cutting element and the rock surface until at point  16  where the rock reaches the end of the elastic region and is forced to fail in a brittle fracture mode. Additional stress build-up beyond the elastic region ultimately causes a fracture of the rock at point  18 . Conventionally, at the point of fracture, the cutting element and rock interface experiences a rapid stress energy release that, in large measure, is caused by the failure of the cutting element to engage the rock face with sufficient force to maintain the stress level. For example, the fracture may propagate at a speed that causes a physical separation of the cutting element and the rock. Thus, conventionally, stress energy for causing a subsequent fracture begins to build only after the cutting element re-establishes an interface with the rock at point  20 . At point  20 , rotation of the drill bit begins to restore the lost stress energy until the rock again fractures at point  22 . Thus, it should be appreciated that for line  10 , the area denoted with numeral  24  represents an initial stored stress energy for causing an initial rock fracture, the area denoted with numeral  25  represents the amount of stress energy released or lost by the initial rock fracture, and the area denoted with numeral  28  represents the amount of energy restored to cause a subsequent rock fracture. 
     In one embodiment of the present invention, a controlled torsional force is momentarily superimposed on the constant drill string rotation at point  18  such that the cutting element temporarily accelerates to at least maintain contact with the fracturing rock and thereby maintain the cutting element and rock surface interface stress level at least until the drill bit at its constant rotational speed can apply the cutting element and rock surface interface stress level, which is denoted as point  30 . However, the controlled torsional force does not change the average bit rotation speed. Thus, point  30  represents the point at which the momentary torsional force is no longer applied to the drill bit. Stated differently, at point  18 , the cutting element speeds up to stay with the fracturing rock until the drill string rotating the drill bit “catches up” at point  30 . Thus, the cutting element and rock surface interface experiences a significantly lower loss of stored stress energy. This is advantageous because the remaining stored stress energy can be used to initiate the subsequent rock fracture at point  32 . As can be seen, the point of subsequent fracture  32  is reached with a much lower amount of restored energy, the area denoted with numeral  36  being the restored energy. 
     As should be appreciated, the energy that is typically lost upon fracture arrest, as shown by area  25 , is not lost because the cutter is temporarily accelerated by controlled torsional oscillations, or another type of applied oscillation, to chase the fracture and keep a fracture level stress within the rock, as shown by line  12 . While line  12  is shown as sinusoidal, other cutter behavior such as that described by a sawtooth pattern may also be utilized. Further, the cyclic action need not be symmetric either in amplitude or over time. Thus, the stress required for the next fracture is not lost and is not required to be reapplied. Also, for rock-like brittle materials, it is generally accepted that the stress level required to maintain fracture growth is lower than the stress required to start the fracture. Thus, it should be further appreciated that the drill bit cuts the rock formation with lower overall energy input. 
     In some embodiments, the frequency of an optimum torsional oscillation may be in the range from several Hz to 200 Hz depending on the size of the drill bit. The amplitude of the oscillation will be function of the frequency, rock elastic behavior, bit speed, drill string rotary inertia and other downhole factors. The application of the oscillation will be normally uniform with forward-based acceleration maximized and return to neutral position acceleration reduced to a level that ensures that velocity of all cutters on the face of the bit remains positive, i.e., the drill bit&#39;s base line rotational position advances to the angular position of the oscillation induced forward rotation without local negative (reverse) rotation of the bit face. 
     It should be understood that the  FIG. 1  graph is provided merely to facilitate the explanation of aspects of the present invention and does not reflect any specific quantitative relationship between rock stress, time values and rotational position or any measured behavior. Moreover, while the graph depicts a fairly stable cutting pattern, it should it understood that in practice the drill bit behavior may be more erratic. Thus, while the stored energy (stress) has been described as not being lost at fracture, it is believed that some portion will be lost at fracture. Accordingly, terms such as “optimal” or “optimizing” are intended to describe a condition of the drill bit as compared to a drill bit that is not subjected to controlled oscillations. 
     As should be apparent from the above-discussion, control of the cutting action of the drill bit cutting elements can be particularly relevant to improving rate-of-penetration (ROP) of a drilling assembly. As shown in  FIG. 1 , embodiments of the present invention can reduce the energy input required to fracture rock. Also, advantageously, there is a reduction in the time delay between arrest of a fracture and restart of a subsequent fracture. In the drilling operation, this may result in a reduction in drilling torque for a target ROP and/or an increase in ROP. That is, an energy savings is realized by a reduction in torque needed to maintain a target ROP and/or an increase in ROP (or volume or rock removal) is realized by increasing torque back to the level present before the efficiency increase. Stated differently, if a fixed energy input level can cause the fracture or crack to grow continuously, then both the required stress level can be minimized and the rock volume removed per unit time as a result of the induced fractures can be maximized. This leads to an increase in ROP and an improvement in drilling efficiency. 
     Referring now to  FIG. 2 , there is shown a drilling system including a conventional surface rig  50  that conveys a drill string  52  and a bottomhole assembly (BHA)  53  into a wellbore  54  in a conventional manner. The BHA  53  includes a drill bit  56  for forming the wellbore  54  as well as other known devices such as drilling motors, steering units, and formation evaluation tools. Depending on the application, the device for providing rotary power to the drill bit  56  can be the drill string  52 , a drilling motor (not shown), or a combination of these devices. A number of arrangements can be used to create oscillations (hereafter “optimizing bit cutting action oscillations” or “optimizing oscillations”) that enhance the cutting action of the drill bit  56 . 
     In some arrangements, a system for providing the optimizing oscillations can include a sensor package  58  for measuring one or more parameters of interest (e.g., rate of penetration, rotational speed, weight-on-bit, torsional oscillation, etc.), a control unit  60  for determining an optimizing frequency based, in part, on the sensor measurements, and an oscillation device  62 . The sensor package  58  can include one or more sensors S 1 , S 2 , S 3  . . . Sn distributed in and along the drill string. The measurement of these sensors can be used to determine parameters such as the frequency and amplitude of the oscillations that optimizes the drill bit cutting action (or the “optimizing frequency”). For instance, the sensors S 1 -n and control unit  60  can initially sweep a range of frequencies while monitoring a key drilling efficiency parameter such as ROP. The oscillation device  62  can then be controlled to provide oscillations at an optimum frequency until the next frequency sweep is conducted. Periodicity of the frequency sweep can be based on a one or more elements of the drilling operation such as a change in formation, a change in measured ROP, a predetermined time period or instruction from the surface. As noted earlier, the term “optimizing” is used to with referenced to a drill bit operating without applied controlled oscillations. 
     The control unit  60  can include a downhole processor and/or the surface processor. The processor(s) can be microprocessor that use a computer program implemented on a suitable machine readable medium that enables the processor to perform the control and processing. The machine readable medium may include ROMs, EPROMs, EAROMs, Flash Memories and Optical disks. Other equipment such as power and data buses, power supplies, and the like will be apparent to one skilled in the art. 
     In one embodiment, an oscillation device  62  controls behavior of the drill bit  56  by allowing only selected vibrations in the drill string and/or BHA  53  to reach the drill bit  56 . As is known, the drill string  52 , in addition to its ordinary rotation, can vibrate in different planes (e.g., torsionally, axially, laterally), frequencies and amplitudes. In one embodiment, the control unit  60 , using one or more processors programmed with algorithms, calculates or otherwise determines which of the existing vibrations in the drill string will optimize the cutting action of the drill bit  56  (i.e., the optimizing oscillation). The control unit  60  can make this determination based on the measurement(s) of the sensor package  58 , stored data, and/or dynamically updated information. Based on this determination, the oscillation device  62  is configured to isolate and pass through the optimizing frequency to the drill bit  56 . For example, the oscillation device  62  can include a filter-type arrangement that permits only an optimizing oscillation of a drill string vibration or oscillation to pass through to the drill bit  56 . 
     In another embodiment, the oscillation device  62  includes a drive unit  64 . This drive unit  64  can be used to amplify an optimizing frequency and/or shift an existing frequency to a optimizing frequency. Thus, an existing drill string vibration or oscillation is conditioned (e.g., amplified or shifted) to provide an optimizing oscillation. For example, if the desired torsional resonance (i.e., optimizing oscillation) is not present in the drill string, then the selected frequency could be used to transform an existing torsional oscillation into the optimizing frequency range. This filtering arrangement can be controllable or adjustable to allow changing the optimizing frequency. The drive unit  64  can be energized using a drill fluid pressure drop, electric energy generated by a downhole generator, a cable providing electrical energy from the surface, or suitable downhole or surface power source. 
     Referring now to  FIG. 3 , there is shown another embodiment of the present invention wherein the oscillation device  70  is placed in the drill string  72  proximate to the drill bit  74  to create a force or forces that produce the optimizing bit oscillation. In one arrangement, the oscillation device  70  is positioned in a sub  72  run in a near bit location or constructed directly into the drill bit  74 . The sub includes an upper section  76  coupled to the drill string  72  and a lower section  78  coupled to the drill bit  74 . A controllable element  80  connects the upper and lower sections  76 ,  78 . The upper section  76  and the lower section  78  rotate around a tool line axis B in a manner described below. When energized, the element  80  can momentarily increase the rotational speed of section  78 , the change in speed being denoted by a′. During operation, the drill string  72  is rotated at a speed a, which is also the nominal speed of rotation of the drill bit  74  because of the fixed relationship between the upper and lower sections  76 ,  78 . Energizing the element  80  momentarily increases the drill bit speed to a+a′. Thus, cyclically energizing the element  80  can provide a torsional oscillation to the drill bit  74 . In some embodiments, the mass of the drill string will provide a sufficient amount of reaction mass to prevent the oscillations from being transferred to the drill string. In other embodiments, a torsion resistance device  90  is positioned on the upper section  76  to prevent the oscillations from being transferred to the drill string  72  rather than the drill bit  74 . The torsion resistance device  90  can include equipment such as subs or collars that supplement the inertia of the BHA above the oscillation device  70  relative to the BHA below the oscillation device  90 . The torsion resistance device  90  can also include a sleeve or centralizer that engages the borehole wall to resist counter-rotation of the drill string such as by a slip clutch arrangement. 
     The controllable element  80  can be formed of one or more materials having properties (volume, shape, deflection, elasticity, etc.) that in response to an excitation or control signal produce controlled oscillations in the required frequency range. Suitable materials include, but are not limited to, electrorheological material that are responsive to electrical current, magnetorheological fluids that are responsive to a magnetic field, and piezoelectric materials that responsive to an electrical current. 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 in the range of rotational speeds of conventional drill strings (i.e., several hundred RPM). 
     Referring now to  FIG. 4 , in some arrangements the drill bit  74  is driven by a drilling motor  92  that connected to the surface via a coiled tubing  94 . A shaft assembly  96  transfers rotary power from the drilling motor  92  to the drill bit  74 . The oscillation device  90  can be positioned in the shaft assembly  96  to provide controlled oscillations to the drill bit  74 . The shaft assembly  96  may not have sufficient mass to prevent the oscillations from being transferred to the portion of the shaft assembly  96  uphole of the oscillation device  90 . Thus, the torsion resistance device  76  can be incorporated into the drilling motor  92  or connected to the shaft assembly  96  (e.g., as a mass acting as a torsional or axial anchor or anvil). 
     Referring now to  FIG. 5 , in another embodiment, the upper and lower sections  76 ,  78  are coupled with an element  100  that normally allow a controlled slippage between sections  76  and  78  and thus the drill string and the drill bit. The element  100  can be formed of a controllable fluid or material that undergoes a change in material property such as viscosity in response to a control signal. In one arrangement, the element  100  normally has a viscosity selected to drive section  78  at a rotational speed lower than section  76 . For instance, due to slippage, section  78  rotates at  98  RPM whereas section  76  rotates at 100 RPM. In response to an excitation or command signal, the viscosity of element  100  increases and effectively locks section  78  to section  76 . The rotational speed of section  78  then increases to approximately that of section  76  or some intermediate rotational speed. Thus, cycling the excitation signals at the appropriate frequency, a torsional oscillation is applied to drill bit  74 . 
     In still other embodiments, the oscillation device can be positioned within one or more devices forming a bottomhole assembly (BHA). For example, a bearing and shaft assembly in a drilling motor can be modified to provide a controlled oscillation to a shaft connected to the drill bit. Also, in embodiments where an electric drilling motor is used, a control unit associated with the electric drilling motor can be used modulate the rotation of the shaft driving the drill bit. 
     In still other embodiments, the teachings of the present invention can be advantageously applied to cutters such as under-reamers and hole openers in addition to drill bits. 
     In still other embodiments, a drill bit can be modified to provide controlled oscillations to the cutting elements of the drill bit. Referring now to  FIG. 6A , there is shown a roller cone drill bit  120  in which is disposed an oscillation device  122 . The oscillation device  122 , when activated, provides controlled oscillations to the drill bit  120 . Exemplary directions of oscillation applied to the drill bit  120  include axial  126  and torsional oscillation  128  as well as lateral (not shown). Referring now to  FIG. 6B , there is shown a cutting element  130  connected to an oscillation device  132 . The cutting element  130  and oscillation device  132  are fixed in a bit body  134 . When activated, the oscillation device  132  temporarily accelerates the cutting element  130  in one or more selected directions. The oscillation device  132  can be used for all or less than all of the cutting elements in a drill bit. Moreover, each such oscillation device can be adapted to operate independently. The oscillation devices of  FIGS. 6A and 6B  can include controllable elements previously described and suitable processing devices or be coupled to processing devices uphole of the drill bit through telemetry devices such as short hop transmitters. 
     It should also be understood that the teaching of the present invention can also be applied to devices and methods that do not utilize controllable materials. For example, suitable oscillations can be generated by mechanical, electromechanical, hydro-mechanical, or electrical devices. Merely by way of example, such devices include elastic elements having natural oscillation frequency and amplitude is at the required state, torque tubes, torsional cages, torsional release devices (slip clutches), a torsional sub with slip clutch torque control, axial hammers, etc. 
     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. It is intended that the following claims be interpreted to embrace all such modifications and changes.