Patent Publication Number: US-7591327-B2

Title: Drilling at a resonant frequency

Description:
CROSS REFERENCE TO RELATED APPLICATIONS 
     This Patent Application is a continuation-in-part of U.S. patent application Ser. No. 11/686,636 filed on Mar. 15, 2007 and entitled Rotary Valve for a Jack Hammer. U.S. patent application Ser. No. 11/686,636 is a continuation-in-part of U.S. patent application Ser. No. 11/680,997 filed on Mar. 1, 2007 now U.S. Pat. No. 7,419,016 and entitled Bi-center Drill Bit. U.S. patent application Ser. No. 11/680,997 is a continuation-in-part of U.S. patent application Ser. No. 11/673,872 filed on Feb. 12, 2007 now U.S. Pat. No. 7,484,576 and entitled Jack Element in Communication with an Electric Motor and/or generator. U.S. patent application Ser. No. 11/673,872 is a continuation-in-part of U.S. patent application Ser. No. 11/611,310 filed on Dec. 15, 2006 and which is entitled System for Steering a Drill String. This Patent Application is also a continuation-in-part of U.S. patent application Ser. No. 11/278,935 filed on Apr. 6, 2006 now U.S. Pat. No. 7,426,968 and which is entitled Drill Bit Assembly with a Probe. U.S. patent application Ser. No. 11/278,935 is a continuation-in-part of U.S. patent application Ser. No. 11/277,394 which filed on Mar. 24, 2006 and entitled Drill Bit Assembly with a Logging Device. U.S. patent application Ser. No. 11/277,394 filed Mar. 24, 2006, now U.S. Pat. No. 7,398,837 is a continuation-in-part of U.S. patent application Ser. No. 11/277,380 also filed on Mar. 24, 2006 and entitled A Drill Bit Assembly Adapted to Provide Power Downhole. U.S. patent application Ser. No. 11/277,380 is a continuation-in-part of U.S. patent application Ser. No. 11/306,976 which was filed on Jan. 18, 2006 and entitled “Drill Bit Assembly for Directional Drilling.” U.S. patent application Ser. No. 11/306,976 is a continuation-in-part of Ser. No. 11/306,307 filed on Dec. 22, 2005, entitled Drill Bit Assembly with an Indenting Member. U.S. patent application Ser. No. 11/306,307 is a continuation-in-part of U.S. patent application Ser. No. 11/306,022 filed on Dec. 14, 2005, entitled Hydraulic Drill Bit Assembly. U.S. patent application Ser. No. 11/306,022 is a continuation-in-part of U.S. patent application Ser. No. 11/164,391 filed on Nov. 21, 2005, which is entitled Drill Bit Assembly. All of these applications are herein incorporated by reference in their entirety. 
    
    
     BACKGROUND OF THE INVENTION 
     This invention relates to the field of subterranean drilling. Typically, downhole hammers are used to affect periodic mechanical impacts upon a drill bit. Through this percussion, the drill string is able to more effectively apply drilling power to the formation, thus aiding penetration into the formation. 
     The prior art has addressed the operation of a downhole tool actuated by drilling fluid. Such issues have been addressed in the U.S. Pat. No. 4,979,577 to Walter, which is herein incorporated by reference for all that it contains. The &#39;577 patent discloses a low pulsing apparatus that is adapted to be connected in a drill string above a drill bit. The apparatus includes a housing providing a passage for a flow of drilling fluid toward the bit. A valve which oscillates in the axial direction of the drill string periodically restricts the flow through the passage to create pulsations in the flow and a cyclical water hammer effect thereby to vibrate the housing and the drill bit during use. Drill bit induced longitudinal vibrations in the drill string can be used to generate the oscillation of the valve along the axis of the drill string to effect the periodic restriction of the flow or, in another form of the invention, a special valve and spring arrangement is used to help produce the desired oscillating action and the desired flow pulsing action. 
     BRIEF SUMMARY OF THE INVENTION 
     In one aspect of the invention, a method for drilling a bore hole includes the steps of deploying a drill bit attached to a drill string in a well bore, the drill bit having an axial jack element with a distal end protruding beyond a working face of the drill bit; engaging the distal end of the jack element against the formation such that the formation applies a reaction force on the jack element while the drill string rotates; and applying a force on the jack element that opposes the reaction force such that the jack element vibrates and causes the formation to vibrate at its resonant frequency which causes the formation to degrade. A spring force or a hydraulic force may vibrate the jack element, thus, vibrating the formation. 
     A motor or a piston may adjust the force on the jack element by compressing a spring of the spring mechanism. In some embodiments up to 15,000 lbs may be loaded to the jack element. In other embodiment, the spring force may be controlled hydraulically. In some embodiments, the jack element may be rotationally isolated from the drill string. A sensor disposed proximate the jack element may sense vibrations of the jack element and/or drill bit, so that the spring force may be adjusted as needed during the drilling process. The spring force may be adjusted to compensate for different hardnesses in the formation which will alter the reactive forces opposing the jack element. 
     The spring mechanism may comprise a compression spring, a tension spring, a coil spring, a Belleville spring, a gas spring, a wave spring, or combinations thereof. A stop disposed in the bore of the drill string may restrict the oscillations of the jack element. The stop may be a shelf formed in the bore or it may be an element inserted into the bore. In some embodiments, the spring mechanism comprises a second spring engaged with the jack element. A portion of the jack element may be disposed in a wear sleeve that has a hardness greater than 58 HRc. 
     At least one nozzle may be disposed within an opening of the working face of the drill bit and/or a portion of the nozzle may be disposed around the jack element. In some embodiments, the distal end of the jack element may comprise a pointed or blunt geometry. The distal end may be brazed to a carbide segment. The distal end may comprise a material selected from the group consisting of chromium, tungsten, tantalum, niobium, titanium, molybdenum, carbide, natural diamond, polycrystalline diamond, vapor deposited diamond, cubic boron nitride, TiN, AlNi, AlTiNi, TiAlN, CrN/CrC/(Mo, W)S2, TiN/TiCN, AlTiN/MoS2, TiAlN, ZrN, diamond impregnated carbide, diamond impregnated matrix, silicon bounded diamond, and/or combinations thereof. Cutting elements disposed on the working face of the drill bit may contact the formation at negative or positive rake angles such that the formation being drilled may contribute to the vibrations of the drill string. The drill string may comprise a dampening system adapted to reduce top-hole vibrations. In some embodiments, the dampening system is located immediately above the drill bit. The dampening system may be located within 200 ft. from the drill bit. 
    
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
         FIG. 1  is a perspective diagram of an embodiment of a drill string suspended in a bore hole 
         FIG. 2  is a cross-sectional diagram of an embodiment of a drill bit. 
         FIG. 3  is a cross-sectional diagram of another embodiment of a drill bit. 
         FIG. 4  is a cross-sectional diagram of another embodiment of a drill bit. 
         FIG. 5  is a cross-sectional diagram of another embodiment of a drill bit. 
         FIG. 6  is a cross-sectional diagram of another embodiment of a drill bit. 
         FIG. 7  is a cross-sectional diagram of an embodiment of a cutting element positioned on a drill bit. 
         FIG. 8  is a graph that shows an embodiment of a frequency. 
         FIG. 9  is a cross-sectional diagram of another embodiment of a drill bit. 
         FIG. 10  is a cross-sectional diagram of another embodiment of a drill bit. 
         FIG. 11  is a diagram of an embodiment of a method for drilling a bore hole. 
         FIG. 12  is a perspective diagram of an embodiment of a distal end of a shaft. 
         FIG. 13  is a perspective diagram of another embodiment of a distal end of a shaft. 
         FIG. 14  is a perspective diagram of another embodiment of a distal end of a shaft. 
         FIG. 15  is a perspective diagram of another embodiment of a distal end of a shaft. 
         FIG. 16  is a perspective diagram of another embodiment of a distal end of a shaft. 
         FIG. 17  is a perspective diagram of another embodiment of a distal end of a shaft. 
     
    
    
     DETAILED DESCRIPTION OF THE INVENTION AND THE PREFERRED EMBODIMENT 
       FIG. 1  shows a perspective diagram of a downhole drill string  100  suspended by a derrick  101 . A bottom-hole assembly  102  is located at the bottom of a well bore  103  and comprises a drill bit  104 . As the drill bit  104  rotates downhole the drill string  100  advances farther into the earth. The drill string  100  may penetrate soft or hard subterranean formations  105 . The bottomhole assembly  102  and/or downhole components may comprise data acquisition devices which may gather data. The data may be sent to the surface via a transmission system to a data swivel  106 . The data swivel  106  may send the data to the surface equipment. Further, the surface equipment may send data and/or power to downhole tools and/or the bottom-hole assembly  102 . U.S. Pat. No. 6,670,880 to Hall which is herein incorporated by reference for all that it contains, discloses a telemetry system that may be compatible with the present invention; however, other forms of telemetry may also be compatible such as systems that include wired pipe, mud pulse systems, electromagnetic waves, radio waves, and/or short hop. In some embodiments, no telemetry system is incorporated into the drill string. In the preferred embodiment, a dampening system  107  may be disposed on the drill string  100  such that vibrations of the drill string  100  do not cause the surface equipment or supporting equipment to vibrate. The dampening system  107  may be located within 200 feet from the drill bit  104  so that the lower portion of the drill string  100  may vibrate and not affect the equipment above ground and/or the drill rig. In some embodiments, the dampening system may be located immediately above the drill bit. In other embodiments, it may be beneficial to use a portion of the tool string as a spring to help induce a resonant frequency into the formation  105 . 
       FIG. 2  is a cross-sectional diagram of a preferred embodiment of a drill bit  104 . The drill bit  104  may be attached to a drill string  100  in a well bore  103 . The drill bit  104  may have an axial jack element  200  with a distal end  201  protruding beyond a working face  202  of the drill bit  104 . In this embodiment the distal end  201  may comprise a pointed, thick geometry. In other embodiments, the distal end may have a blunt geometry. More specifically, in this embodiment the distal end may have a substantially pointed geometry with a sharp apex  203  having a 0.050 to 0.125 inch radius. The distal end  201  may also have a 0.100 to 0.500 inch thickness from the apex  203  to a non-planar interface  204 . The distal end  201  may comprise a superhard material selected from the group consisting of chromium, tungsten, tantalum, niobium, titanium, molybdenum, carbide, natural diamond, polycrystalline diamond, vapor deposited diamond, cubic boron nitride, TiN, AlNi, AlTiNi, TiAlN, CrN/CrC/(Mo, W)S2, TiN/TiCN, AlTiN/MoS2, TiAlN, ZrN, diamond impregnate carbide, diamond impregnated matrix, silicon bounded diamond, and/or combinations thereof. The distal end  201  may be bonded to a carbide segment  209 , which is press fit into a steel portion of the jack element. 
     The jack element  200  may also be attached to a spring mechanism  205 . In this embodiment, the spring mechanism  205  comprises a Bellville spring. In other embodiments, the spring mechanism may comprise a compression spring, a tension spring, a coil spring, a gas spring, a wave spring, or combinations thereof. During a drilling operation, the distal end  201  may engage the formation  105  such that the formation  105  applies a reaction force in a direction, indicated by the arrow  206 , on the jack element  200  while the drill string  100  rotates. A force in another direction, indicated by the arrow  207 , may be applied on the jack element  200  that opposes the reaction force  206  such that the jack element vibrates. It is believed that by tuning the weight on bit (WOB) and the spring force of the spring mechanism with the reaction force imposed by the formation  105  that a resonant frequency of the formation may be produced causing the formation proximate the jack element to self destruct. The mechanical resonant frequency of the formation  105  may be the optimum working frequency. The WOB and the spring force may be approximately 15,000 lbs. The WOB may be adjusted depending on the hardness of the formation being drilled. It may be desired to vibrate the drill string  100  so that it vibrates at the resonant frequency of the formation  105 . In some embodiments, the driller may know that the formation is vibrating at its resonant frequency because the rate of penetration (ROP) may be dramatically high. As the formation changes its hardness the ROP may drop and the drill may adjust the WOB until the ROP again increases dramatically. In other embodiments, downhole sensors and feed back loops may adjust and the spring force of the spring mechanism automatically to impose the resonant frequency. In other embodiments a telemetry system and/or an automatic feedback loop may communicate with surface equipment that automatically adjust the WOB or communicate with the driller to adjust the WOB. A portion of the jack element  200  may be disposed in a wear sleeve  208  having a hardness greater than 58 HRc. 
       FIG. 3  is a cross-sectional diagram of another embodiment of a drill bit  104 . In this embodiment, a drill bit  104  may be attached to a drill string  100  in a well bore  103 . The drill bit  104  may have an axial jack element  200  with a distal end  201  protruding beyond a working face  202  of the drill bit  104 . In this embodiment, the distal end  201  may have a blunt geometry. The distal end  201  may be bonded to a carbide segment  209 . In this embodiment, carbide segment  209  may be brazed to another carbide segment  300 , which is press fit into a steel portion of the jack element. 
     A reaction force may be applied by the formation  105  to the distal end of the jack element  200  and an opposing force, such as a WOB and the spring force, may be applied to the jack element from the drill string  100 . In this embodiment, the spring mechanism  205  comprises a coil spring. As the drill string  100  rotates during operation, the jack element  200  may be rotationally isolated from the drill string  100 . A stop  301 , such as a shelf, may be disposed in a bore  302  of the drill string  100  to restrict the vibrations and/or travel of the jack element  200 . The sharpness of the distal end of the jack element affects how much force is applied to the formation, thus in some embodiments, it may be advantageous to may a blunt geometry where in other embodiments, a sharper geometry may be more effective. In some embodiments, the distal end of the jack element may be asymmetric causing a drilling bias which may be used to steer the drill bit. 
     In the embodiment of  FIG. 4 , the spring mechanism comprises an electric motor  400  disposed in the bore  302  of the drill string  100  and is adapted to change the spring force. In this embodiment, the spring mechanism  205  comprises a wave spring. The jack element  200  may comprise a proximal end  401  with a larger diameter than the distal end  201  such that the proximal end  401  has a larger surface area to contact the wave spring. The electric motor may be adapted to rotate a threaded pin  402  thereby extending or retracting it with respect to the motor  400 . The jack element  200  may also comprise an element  403  intermediate the threaded pin  402  and the spring  205 . The intermediate element  403  may be attached to either the threaded pin  402  or the spring  205  such that as the threaded pin  402  rotates downward the spring  205  is compressed, exerting a greater downward force on the jack element  200 . Alternatively, the motor may rotate in the opposite direction, relieving the compression on the spring and exerting a lesser downward force on the jack element  200 . The hardness of the formation  105  may determine whether the motor  400  increases or decreases the spring force such that the distal end  201  of the jack element  200  vibrates at a frequency equal to that of the resonant frequency of the formation  105  being drilled. 
     At least one nozzle  404  may be disposed within an opening  405  of the working face  202  of the drill bit  104 . A portion of the nozzle  404  may be disposed around the jack element  200 . In this embodiment, the portion of the nozzle  404  may be disposed within an axial groove  406  in a side of the jack element  200 . This may allow the nozzle  400  to be positioned closer to the jack element  200 . The axial groove  406  may provide the shortest path for the fluid to exit from the bore  302  of the drill bit  104 . The axial groove  406  may also have a geometry that angles the stream of fluid in a direction that is non-perpendicular to the working face  202  but that travels in a general direction of the junk slots. 
     Referring now to  FIG. 5 , the spring mechanism  205  may comprise a hydraulic mechanism  500  to control the spring force. During a drilling operation a fluid channel  501  directs the drilling fluid from the bore  302  of the drill string  100  to at least one nozzle  403 . Drilling fluid from the bore  302  may enter a first section  502  through a first aperture  503  formed in the piston mechanism  500  and exposed in the fluid channel  501 . A first actuator  504  may be used to control the amount of drilling fluid allowed to enter the first section  502  by selectively opening or closing the first aperture  503 . The first actuator  504  may comprise a latch, hydraulics, a magnetorheological fluid, electrorheological fluid, a magnet, a piezoelectric material, a magnetostrictive material, a piston, a sleeve, a spring, a solenoid, a ferromagnetic shape memory alloy, or combinations thereof. When the first aperture  503  is open, a second aperture  505  formed in a second section  506  of the hydraulic mechanism  500  may also be open. The second aperture  505  may be exposed in the fluid channel  501 . As drilling fluid enters the first section  502 , drilling fluid may be exhausted from the second section  506 . Since the sections  502 ,  506  of the hydraulic mechanism  500  are divided by a separator  507  that keeps pressure from escaping from one section to another, the hydraulic mechanism  500  may move such that it engages the spring in communication with the jack element  200 . Thus, the distal end  201  of the jack element  200  may extend beyond the working face  202  of the drill string  100 . When the first and second apertures  503 ,  505  are closed, a third and fourth aperture  508 ,  509  may be opened; aperture  508  may pressurize the second section  506  and the aperture  509  may exhaust the first section  502 . In this manner the spring may be extended. When all of the apertures  503 ,  505 ,  508 ,  509  are closed the spring may be held rigidly in place. Thus the equilibrium of the section pressures may be used to control the position of the spring. During a drilling operation, the distal end  201  of the jack element  200  may engage the formation  105 , which will exert a formation pressure on the spring and change the pressure equilibrium and thereby change the position of the spring. 
       FIG. 6  shows a coil spring  205  in communication with a side  600  of the proximal end  401  of the jack element  200 . Another spring  601  may contact the other side  602  of the proximal end  401  of the jack element  200  such that the jack element  200  may compress and/or relieve each spring as it oscillates. 
     A sensor  603  may be attached to the jack element  200 . The sensor  603  may be a geophone, a hydrophone, a piezoelectric device, a magnetostrictive device, acceleratometer, or another vibration sensor. In some embodiments, the sensor  603  may receive acoustic reflections  604  produced by the movement of the jack element  200  as it oscillates or vibrates. Electrical circuitry  605  may be disposed within a wall  606  of the drill string  100 . The electrical circuitry  605  may be adapted to measure and maintain the orientation of the drill string  100  with respect to the formation  105  being drilled. The electrical circuitry  605  may also control the motor  400 , which in turn controls the compression of the spring. 
       FIG. 7  is a cross-sectional diagram of an embodiment of a cutting element  700  positioned on a working face  202  of a drill bit  104 . The cutting element  700  may comprise a contact angle  701  such that the angle  701  is less than 90 degrees. During a drilling operation, the cutting element  700  may slide across a formation  105 , such that the formation  105  exhibits a force in a direction, indicated by an arrow  702 , against the drill bit  104  and a force in a direction, indicated by an arrow  703 , also against the drill bit  104 . These forces  702 ,  703  may help to vibrate the drill bit  104 , which in turn vibrates the formation  105 . 
     During a drilling operation a distal end of a jack element may oscillate against a formation, causing the formation to vibrate at some frequency. The formation may comprise a resonant or a natural frequency such that when the drill string vibrates the formation at this frequency, the ROP improves. The graph of  FIG. 8  shows an embodiment of an amplitude of a frequency wave  800  over time. During a drilling operation, characteristics such as density and porosity of the formation may change over time. The graph shows the amplitude of the frequency wave  800  increasing to a maximum over time as the spring adjusts to the hardness of the formation. At the resonant frequency, the amplitude is at a maximum 
       FIG. 9  is a cross-sectional diagram of an embodiment of a drill bit  104 . At least a portion of a nozzle  404  may be disposed within the proximal end  401  of the jack element  200 . A bore  1000  may be formed into the jack element  200  and drill bit  104  after the jack element  200  has been inserted into the working face  202 . The bore may be lined with a hard material in order to protect the nozzle  404  from wear due to high pressures and velocities of the fluid passing through the nozzle  404 . A spring mechanism  205  may comprise at least two springs engaged with the jack element  200 . The jack element  200  may compress and/or relieve each spring as it oscillates. 
       FIG. 10  is a cross sectional diagram of another embodiment. This embodiment does not require a spring mechanism. As fluid engages a proximal end of the jack element, the jack element is pushed towards the formation. Fluid pass-by passages allow flow through the proximal end of the jack element. More flow is allowed around the jack element once the proximal end reaches pockets formed in the bore of the drill bit. The extra flow will drop the pressure exerted on the proximal end and a reaction force pushing on the jack element by the formation may push the proximal end back from the pockets. A oscillation motion may then occur as the drilling fluid pressure is then increased, pushing the jack element towards the formation again until the pressure is relieved by the pockets. 
       FIG. 11  is a diagram of an embodiment of a method  900  for drilling a bore hole. The method  900  includes deploying  901  a drill bit attached to a drill string in a well bore. The method also includes engaging  902  a distal end of a jack element against a formation such that the formation applies a reaction force on the jack element while the drill string rotates. Further the method  900  includes applying  903  a force on the jack element that opposes the reaction force such that the formation substantially vibrates at its resonant frequency. By vibrating the formation at its resonant frequency, the formation may more easily break up and thus, maximize the ROP. 
       FIGS. 12-17  disclose several asymmetric geometries that may be used with the present invention. It is believed that certain asymmetric geometries may have various advantages over other asymmetric geometries depending on the characteristics of the formation. Such characteristic may include hardness, formation pressure, temperature, salinity, pH, density, porosity, and elasticity. In some embodiments, all the geometries shown in  FIGS. 12-17  may comprise superhard coatings although they are not shown. 
       FIG. 12  shows an asymmetric geometry  1603  with a substantially flat face  1700 , the face  1700  intersecting a central axis  1701  of the shaft  1204  at an angle  1702  between 1 and 89 degrees. Ideally, the angle  1702  is within 30 to 60 degrees.  FIG. 13  shows a geometry  603  of an offset cone  1800 .  FIG. 14  shows an asymmetric geometry  1603  of a cone  1900  comprising a cut  1901 . The cut  1900  may be concave, convex, or flat.  FIG. 15  shows a geometry  1603  of a flat face  1700  with an offset protrusion  11000 . The embodiment of  FIG. 16  shows an offset protrusion  11000  with a flat face  1700 . The asymmetric geometry  1603  of  FIG. 17  is generally triangular. In other embodiments, the asymmetric geometry  1603  may be generally pyramidal. 
     Whereas the present invention has been described in particular relation to the drawings attached hereto, it should be understood that other and further modifications apart from those shown or suggested herein, may be made within the scope and spirit of the present invention.