Patent Publication Number: US-2010108390-A1

Title: Apparatus and method for controlling fluid flow in a rotary drill bit

Description:
BACKGROUND 
     Rotary drill bits are commonly used for drilling boreholes or wells in earth formations. Examples of such rotary drill bits include roller cone bits that generally include three roller cones mounted on support legs extending from a bit body, and fixed cutter bits that generally include an array of cutting elements secured to a face region of the bit body. A hard, superabrasive material, such as mutually bonded particles of polycrystalline diamond, may be provided on a surface of each cutting element to provide a cutting surface. Such cutting elements are often referred to as “polycrystalline diamond compact” (PDC) cutters. 
     Rotary drill bits generally include one or more nozzles extending from a mud conduit through the drill bit to cool the cutters and remove cuttings from the drill bit. Mud or other fluid is pumped down a drillstring and into the drill bit where it flows out of the nozzles and across the face of the cutters, cooling and cleaning them. The mud then flows up junk slots formed in the drill bit and into a borehole annulus, carrying the cuttings to the surface. The rate of fluid flow should be controlled in order to ensure that the correct components are cleaned and the fluid flow is sufficient to carry cuttings away from the drill bit. However, the number and configuration of the nozzles may be severely restricted due to the configuration and size of the drill bit and due to the need to avoid interference between nozzles. 
     SUMMARY 
     An apparatus for drilling a borehole in an earth formation includes: an earth-boring rotary drill bit including a bit body having a plurality of cutters engagable with a subterranean earth formation; a fluid conduit disposed in the bit body, the fluid conduit being in fluid communication with a source of drilling fluid and configured to receive a portion of the drilling fluid; a nozzle extending between the fluid conduit and a surface of the bit body, the nozzle configured to apply a stream of the portion of the drilling fluid to a first location of the surface; and a valve assembly including an actuator and a valve, the actuator configured to move the valve and divert a flow path of the portion of the drilling fluid, thereby diverting at least part of the stream to a second location on the surface. 
     A method of drilling a borehole in an earth formation includes: rotating a drill bit body including a plurality of cutters engagable with a subterranean earth formation; pumping a drilling fluid into a fluid conduit disposed in the drill bit body; receiving a portion of the drilling fluid in a nozzle extending between the fluid conduit and a surface of the drill bit body, and applying a stream of the portion of the drilling fluid from the nozzle to a first location of the surface; and actuating a valve assembly in operable communication with the nozzle and diverting at least part of the stream from a first location to a second location. 
    
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
       The following descriptions should not be considered limiting in any way. With reference to the accompanying drawings, like elements are numbered alike: 
         FIG. 1  is a cross-sectional view of an exemplary embodiment of a well logging and/or drilling system; 
         FIG. 2  is a partial cross-sectional view of an exemplary embodiment of an earth-boring rotary drill bit of the system of  FIG. 1 ; 
         FIG. 3  is a partial cross-sectional view of an exemplary embodiment of a nozzle of the drill bit of  FIG. 2  including a control valve assembly; 
         FIG. 4  is a partial cross-sectional view of an exemplary embodiment of an actuator of the control valve assembly of  FIG. 3 ; 
         FIG. 5  is a perspective view of an exemplary embodiment of an actuator of the control valve assembly of  FIG. 3 ; 
         FIG. 6  is a top view of exemplary embodiments of the control valve assembly of  FIG. 3 ; and 
         FIG. 7  is a flow diagram illustrating a method of drilling a borehole in an earth formation. 
     
    
    
     DETAILED DESCRIPTION 
     Referring to  FIG. 1 , an exemplary embodiment of a well logging and/or drilling system  10  includes a drillstring  11  that is shown disposed in a borehole  12  that penetrates at least one earth formation  14  during a drilling, well logging and/or hydrocarbon production operation. The drillstring  11  includes a drill pipe, which may be one or more pipe sections or coiled tubing. A borehole fluid  16  such as a drilling fluid or drilling mud may be pumped through the drillstring  11  and/or the borehole  12 . The well drilling system  10  also includes a bottomhole assembly (BHA)  18 . 
     As described herein, “borehole” or “wellbore” refers to a single hole that makes up all or part of a drilled well. As described herein, “formations” refer to the various features and materials that may be encountered in a subsurface environment. Accordingly, it should be considered that while the term “formation” generally refers to geologic formations of interest, that the term “formations,” as used herein, may, in some instances, include any geologic points or volumes of interest (such as a survey area). 
     In one embodiment, the BHA  18  includes a drill bit assembly  20  including a rotary drill bit  21  and associated motors adapted to drill through earth formations. Optionally, the BHA  18  includes one or more downhole tools  22  that include various sensors for measuring selected parameters of the drilling system, the borehole  12  and/or the formation  14 . 
     In one embodiment, a surface processing unit  24  is configured as a surface drilling control unit which controls various production and/or drilling parameters such as rotary speed, weight-on-bit, fluid flow parameters, pumping parameters and others and is configured to record and is optionally configured to display real-time data including formation evaluation data and drilling parameters such as vibration data. The BHA  18  and/or the downhole tool  22  is configured to communicate with the surface processing unit  24  via any suitable connection, such as a wired connection including a wireline or wired pipe, a fiber optic connection, a wireless connection and mud pulse telemetry. The surface processing unit  24  includes components as necessary to provide for storing and/or processing data collected from the downhole tool  22 . Exemplary components include, without limitation, at least one processor, storage, memory, input devices, output devices and the like. 
     Referring to  FIG. 2 , an exemplary embodiment of an earth-boring rotary drill bit  30  having a variable fluid nozzle is shown. Examples of suitable nozzles include threaded single-piece nozzles that are sealingly attached to a threaded inlet, fixed port nozzles, and multiple-piece nozzles including multiple nozzle conduits held in place by a nut or other fastener. 
     The drill bit  10  includes a bit body  32  secured to a shank  34 , such as a steel shank. The bit body  32  includes a crown  36  and a metal blank  38  that is partially embedded in the crown  36 . In one embodiment, the drill bit  10  is a polycrystalline diamond compact (“PDC”) drill bit. Although the embodiments herein are described in conjunction with a PDC drill bit, such embodiments may be utilized with any suitable drill bit configuration, such as various types of fixed cutter and roller cone bits. 
     The bit body  32  is secured to the steel shank  34  by way of a threaded connection  40  and a weld  42  extending around the drill bit  30  on an exterior surface thereof along an interface between the bit body  32  and the steel shank  34 . The steel shank  34  includes an API threaded connection portion  44  for attaching the drill bit  30  to the drillstring  11 . 
     The bit body  32  includes a plurality of wings or blades  46 , which are separated by external channels or conduits, also known as “junk slots”  48 . One or more internal fluid passageways or nozzles  50  extend from a longitudinal bore  52 , which extends through the steel shank  34  and partially through the bit body  32 . A plurality of cutters  54  are provided on the bit body  32 . In one embodiment, the cutters  54  are provided along each of the blades  46 . 
     The nozzles  50  are disposed in the crown  36  in fluid communication with the bore  52  to allow a portion of the drilling fluid  16  to be diverted from the main fluid flow in the bore  52  and onto components of the crown  36 . For example, each nozzle  50  is directed to a surface of the junk slot  48  and is directed to a selected blade  46  so that a cooling and/or cleaning flow of fluid is provided to the blade  46 . 
     During drilling operations, the drill bit  30  is positioned at the bottom of the borehole  12  and rotated while the drilling fluid  16  is pumped to the bit body  32  through the longitudinal bore  52  and the nozzles  50 . As the cutters  54  shear or scrape away the underlying earth formation, the formation cuttings mix with and are suspended within the drilling fluid  16  and are flushed from the junk slots  48  and into the annular space between the wellbore  12  and the drillstring  11  to the surface. 
     At least one of the nozzles  50  includes a control valve assembly  56  that is configured to control the volume and/or direction of drilling fluid  16  flowing through the nozzle  50 . The control valve assembly  56  includes an actuator  58  operably connected to a valve  60 , such as via a piston. The valve  60  incorporates any suitable configuration, such as a ball valve that is rotatable to control the flow of fluid  16  through the nozzle  50  and or the direction of flow. Another example of the valve  60  is a louver-type valve that is rotatable to adjust the amount and direction of fluid flow through the nozzle  50 . 
     The actuator  58  is of any suitable configuration sufficient to rotate or advance the valve  60  in the nozzle  50 . Examples of actuators include electromagnetic (via a motor or solenoid), piezoelectric, thermal, mechanical, pneumatic and hydraulic actuating mechanisms or any combination thereof. 
     In one embodiment, the actuator  58  is a cam-type actuator having an eccentric shape such that rotation of the cam-type actuator  58  causes movement of the valve  60 . In another embodiment, the actuator  58  includes a piezoelectric element configured to move the valve  60  in response to application of a voltage to the piezoelectric element, which is controlled for example by a monitoring device. 
     Referring to  FIG. 3 , an embodiment of the valve assembly  56  is shown. The valve assembly  56  includes a piston  62  and the valve  60 . In this embodiment, the valve  60  is a piston head having a surface  64  that is inclined relative to a central axis of at least a portion of the nozzle  50 . As the valve assembly  56  is actuated, the piston head  60  moves from a peripheral location in the nozzle  50  toward a central location in the nozzle  50 , thereby diverting the flow of fluid  16  toward one side of the nozzle  50 . Movement of the piston head  60  causes the fluid  16  to divert in its path so that a different blade  46  or other location of the drill bit  30  is exposed to the fluid stream emitted from the nozzle  50 . In addition to diverting the path, movement of the piston head may also change the pressure and/or shape of the fluid stream exiting the nozzle  50 . 
     In one embodiment, the valve assembly  56  includes a spring  66  or other elastic biasing member to return the valve  60  to a rest position after actuation. Exemplary rest positions include a peripheral position in the nozzle interior, a position at an interior wall of the nozzle  50  and an exterior position relative to the nozzle  50 . The spring  66  is fixedly connected relative to the drill bit body  32  at one end and fixedly connected to the piston  62  and/or the valve  60  at another end. 
     In one embodiment, the valve  60  is movable in response to a rotation rate of the drill bit  30 . For example, the spring  66  counteracts a degree of centrifugal force caused by rotation of the drill bit  30 , an excess of which causes the spring  66  to deform and allows the valve  60  to displace in a radial direction away from the rotational axis of the drill bit  30 . Increasing the rotational rate of the drill bit  30  causes the valve  60  to displace farther into the nozzle  50 , which in turn causes the valve  60  to divert the fluid flow. 
     The surface  64  and the valve  60  is configured in any suitable manner to cause a desired diversion of the fluid flow as the valve  60  is moved into the nozzle  50 . For example, the valve may take any suitable shape, such as a cylinder or a ball. The valve  60  may include any number of passages therethrough to create one or more individual streams that are emitted from the nozzle  50  in one or more selected directions. In one embodiment, the surface  64  is tapered so that the valve  60  has a smaller radial thickness at an upstream end of the surface  64  than the radial thickness in a downstream end of the surface  64 . 
     Referring to  FIG. 4 , in one embodiment, the actuator  58  is a mechanism for causing radial displacement of the valve  60  in response to changes in the rotational rate of the drill bit  30 . The actuator  58  includes a first tapered member  68  and a second tapered member  70  positioned in slidable contact and orthogonal to the first tapered member  68 . An exemplary shape of the tapered members  68  and  70  is a conical shape. 
     The first tapered member is positioned so that a portion of the first tapered member is tapered relative to the drill bit rotational axis. In one embodiment, the first tapered member  68  is symmetrical about the rotational axis of the drill bit  30  or an axis that is parallel to the rotational axis of the drill bit  30 . The second tapered member  70  is positioned so that the members  68  and  70  are in slidable contact between their respective tapered surfaces. As the drill bit  30  rotates, the second tapered member  70  slides along the first tapered member  68  in response to a reactive centrifugal force. The second tapered member  70  moves in a direction having both vertical (i.e. parallel to the rotational axis) and radial components. The piston is operably connected to the second tapered member  70  and is movable along the radial direction. The spring  66  or other biasing member may be included to maintain a radial position of the valve  60  relative to a selected rotation rate. As the rotation rate increases, the valve  60  moves away from the center of the drill bit  30  in the radial direction, causing diversion of the fluid flow. As the rotation rate decreases, the spring  66  causes the valve to move toward the center of the drill bit to reduce diversion of the fluid flow. In one embodiment, the spring  66  and the valve  60  are configured to return the valve  60  to a rest position as the rotation rate equals or falls below a selected rotation rate. 
     Referring to  FIG. 5 , in another embodiment, the actuator  58  is a cam-type actuator including at least one eccentrically shaped cam  74  operably connected to the piston  62 . The cam  74  is rotatable about a rotating shaft or other member. The actuator  58  is operated by rotating the cam  74  to cause the piston  62  to move in a linear direction, such as a radial direction away from the rotational axis of the drill bit  30 . 
     In one embodiment, the actuator  58  includes a cam assembly having a plurality of cams having at least two distinct cam profiles. For example, the cam assembly includes the first cam  74  and a second cam  76 . The second cam  76  has a profile that is different than the first cam  74 , so that rotation of the second cam  76  causes the piston  62  to move a different distance than rotation of the first cam  74 . An adjustable pin  75  or other mechanism is included and is adjustable between a first and a second position in response to fluid pressure or actuation by a user or a processor. In one embodiment, a rocker arm is in contact with the piston  62  and has independently movable sections corresponding to each cam profile. In the first position, the pin  75  is disengaged so that only the first cam  74  is rotated, causing the valve  60  to move a first distance. In the second position, the pin  75  is engaged so that at least the second cam is rotated, causing the valve to move a second distance. An example of a cam assembly utilizing multiple cam profiles is included in the Variable Valve Timing and Lift Electronic Control (VTEC) automobile engine manufactured by Honda Motor Company. 
     Referring to  FIG. 6 , in one embodiment, the surface  64  includes at least one channel  72  or other feature therein for directing the path of the fluid  16 . In one example, the channel  72  includes at least one two-way channel. In other examples, the channel  72  is a three-way, four-way or five-way channel. The configurations of the valve  60  and/or the surface  64  described herein are exemplary and non-limiting, as any number or shape of channels  72  or other features may be utilized. 
     Any of the channels may be shaped in such a manner as to control dispersion of the fluid stream that exits the nozzle  50 . For example, the channels  72  can be tapered to control the spreading effect of the fluid stream. 
     In one embodiment, the control valve assembly  56  is connected in communication with a processor such as the surface processing unit  24  to allow for control of the valve assembly  56  by a user or directly by the processor. In another embodiment, the control valve assembly  56  is self-contained within the drill bit  30  and automatically adjusts in response to the pressure of the drilling fluid  16  and/or the rotational rate of the drill bit  30 . 
       FIG. 7  illustrates a method  80  of drilling a borehole in an earth formation. The method  80  is used in conjunction with the drill bit  30  and the valve assembly  56 , although the method  80  may be utilized in conjunction with any suitable combination of drill bits and valve assemblies. The method  80  includes one or more stages  81 ,  82 ,  83  and  84 . In one embodiment, the method  80  includes the execution of all of stages  81 - 84  in the order described. However, certain stages may be omitted, stages may be added, or the order of the stages changed. 
     In the first stage  81 , drilling is commenced by rotating the drill bit  30  and pumping drilling fluid through the conduit  52 . 
     In the second stage  82 , a portion of the drilling fluid  16  is diverted through the nozzle  50  and a fluid stream exits the nozzle  50  and is directed to a location of the drill bit  30 , such as one of the blades  46 . The location and shape of the stream is dependent on the direction and configuration of the nozzle  50 . 
     In the third stage  83 , the valve  60  is actuated to adjust the stream. Adjustment of the stream may include adjusting the direction and/or shape of the stream to control the location on the drill bit surface that is affected by the stream. 
     In one embodiment, the valve  60  is actuated by an input signal provided by the surface processing unit  24  or other processor. In another embodiment, actuation of the valve assembly  58  is adjusted in accordance with rotational speed of the drill bit  30 , such as the rotation (RPM) of the drill bit  30  in the case of a fixed cutter bit or the rotation of the individual cones in a roller cone bit. In another embodiment, the valve  60  is actuated automatically based on the rotational speed of the drill bit  30 . 
     In the fourth stage  84 , the fluid stream is directed away from the drill bit  30  via the junk slots  48  and into the annular region between the drillstring  11  and the borehole walls. The fluid stream, which includes cuttings from the drill bit, is further directed toward a surface location. 
     Generally, some of the teachings herein are reduced to instructions that are stored on machine-readable media. The instructions are implemented by a computer such as the surface processing unit  24  or other processor and provide operators with desired output. 
     The systems and methods described herein provide various advantages over prior art techniques, such as greater control over the direction and amount of fluid flow applied to the drill bit surface without the need to adjust or replace nozzles. Other advantages include a reduced number of nozzles required, allowing for improved design flexibility. 
     In support of the teachings herein, various analyses and/or analytical components may be used, including digital and/or analog systems. The system may have components such as a processor, 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 aspects of the teachings herein. For example, a sample line, sample storage, sample chamber, sample exhaust, pump, piston, power supply (e.g., at least one of a generator, a remote supply and a battery), vacuum supply, pressure supply, refrigeration (i.e., cooling) unit or supply, heating component, motive force (such as a translational force, propulsional force or a rotational force), magnet, electromagnet, sensor, electrode, 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. 
     One skilled in the art will recognize 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 by those skilled in the art 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 by those skilled in the art 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.