Patent Publication Number: US-8534384-B2

Title: Drill bits with cutters to cut high side of wellbores

Description:
CROSS-REFERENCE TO RELATED APPLICATION 
     This application claims priority from the U.S. Provisional patent application having the Ser. No. 61/142,081 filed Dec. 31, 2008. 
    
    
     BACKGROUND INFORMATION 
     1. Field of the Disclosure 
     This disclosure relates generally to drill bits and systems that utilize the same for drilling wellbores. 
     2. Background of the Art 
     Oil wells (also referred to as “wellbores” or “boreholes”) are drilled with a drill string that includes a tubular member that conveys a drilling assembly (also referred to as the “bottomhole assembly” or “BHA”) attached to its bottom end into the wellbore. The BHA typically includes devices and sensors that provide information about a variety of parameters relating to the drilling operations (“drilling parameters”), behavior of the BHA (“BHA parameters”) and the formation surrounding the wellbore (“formation parameters”). A drill bit attached to the bottom end of the BHA is rotated by rotating the drill string and/or by a drilling motor (also referred to as a “mud motor”) in the BHA to disintegrate the rock formation to drill the wellbore. A large number of wellbores are drilled along contoured trajectories. For example, a single wellbore may include one or more vertical sections, deviated sections and horizontal sections through differing types of rock formations. For drilling deviated wellbores, often it is desirable to cut the formation at high build rates. Build rates are typically achieved by mechanisms or devices that are uphole of the drill bit. Higher build rates may be achieved by including one or more devices in the drill bit. The present disclosure provides drill bits with one or more devices in the drill bit to form deviated wellbores. 
     SUMMARY 
     The disclosure herein, in one aspect, provides a drill bit that includes a cutting device above or uphole of the conventional cutters on the drill bit to cut the high side of the wellbore during drilling of a wellbore. In one aspect, the cutting device may be placed on a non-rotating member arranged around the drill bit body. In another aspect, the non-rotating member may be placed around a gage section of the drill bit. The cutting device may include cutters suitable for cutting into the formation along a side of the drill bit. A suitable actuation device, may be used to actuate the cutting device, which may include, but is not limited to, a hydraulic device, an electric motor, an electro-mechanical device and a mechanical device. A controller may be provided to control the operation of the actuation device during drilling of the wellbore. Sensors may be provided to determine the high side of the wellbore and the controller may be configured to cause the cutting device to orient or align along the high side of the wellbore. 
     In another aspect, the disclosure provides a method for drilling a wellbore that in one aspect may include: conveying a drill bit having cutters on a face section of the drill bit and a cutting device on a side of the drill bit; cutting a formation in front of the drill bit by rotating the face section of the drill bit; orienting the cutting device along a high side of the wellbore; and cutting the formation along the high side of the wellbore using the cutting device. The method may further include determining the high side from a sensor measurement and orienting the cutting device in response to the sensor measurement. The sensor measurements may include measurements from one or more accelerometers and/or one or more magnetometers. 
     In another aspect, a method of making a drill bit is disclosed that in one aspect may include: providing a drill bit configured to form a wellbore; providing a cutting device on a side of the drill bit configured to cut formation on a high side of the wellbore. The method of making the drill bit may further include providing the cutting device on a substantially non-rotating member around the drill bit. In another aspect, the method may further include providing an actuation device configured to rotate the cutting device. In another aspect, the method may further include providing a controller to orient the cutting device along the high side of the wellbore during drilling of the wellbore. 
     Examples of certain features of the apparatus and method disclosed herein are summarized rather broadly in order that the detailed description thereof that follows may be better understood. There are, of course, additional features of the apparatus and method disclosed hereinafter that will form the subject of the claims appended hereto. 
    
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
       The disclosure herein is best understood with reference to the accompanying figures in which like numerals have generally been assigned to like elements and in which: 
         FIG. 1  is a schematic diagram of an exemplary drilling system that includes a drill string with a drill bit made according to one embodiment of the disclosure; 
         FIG. 2  shows an isometric view of a drill bit made according to one embodiment of the disclosure; 
         FIG. 3  is a schematic illustration of a blade profile of the drill bit shown in  FIG. 2  that includes a cutting device on the gage section of the drill bit; 
         FIG. 4  is a schematic illustration of a blade profile shown in  FIG. 2  that includes a cutting device in a notch or cavity formed in the gage section of the drill bit; 
         FIG. 5  is a schematic illustration of a cross-section of a drill bit that includes a cutting device on a gage section of the drill bit; and 
         FIG. 6  shows a schematic illustration of a cross-section of a drill bit that includes a cam-type rotation cutting device. 
     
    
    
     DETAILED DESCRIPTION OF THE EMBODIMENTS 
       FIG. 1  is a schematic diagram of an exemplary drilling system  100  that may utilize drill bits made according to the disclosure herein.  FIG. 1  shows a wellbore  110  having an upper section  111  with a casing  112  installed therein and a lower section  114  being drilled with a drill string  118 . The drill string  118  is shown to include a tubular member  116  with a BHA  130  attached at its bottom end. The tubular member  116  may be a coiled-tubing or made by joining drill pipe sections. A drill bit  150  is attached to the bottom end of the BHA  130  for cutting the rock formation  119  to drill the wellbore  110 . 
     Drill string  118  is shown conveyed into the wellbore  110  from an exemplary rig  180  at the surface  167 . The exemplary rig  180  shown is a land rig for ease of explanation. The apparatus and methods disclosed herein may also be utilized with an offshore rig (not shown) used for drilling wellbores under water. A rotary table  169  or a top drive  168  coupled to the drill string  118  may be utilized to rotate the drill string  118 , BHA  130  and the drill bit  150  to drill the wellbore  110 . A drilling motor  155  (also referred to as the “mud motor”) may be provided in the BHA  130  to rotate the drill bit  150 . The drill bit may be rotated by the drilling motor  155  or by rotating the drill string  118  or by both the drilling motor and the drill string rotation. A control unit (or controller)  190 , which may be a computer-based unit, may be placed at the surface  167  to receive and process data from the sensors in the drill bit  150  and the sensors in the BHA  130  and to control selected operations of the various devices and sensors in the BHA  130 . The surface controller  190 , in one embodiment, may include a processor  192 , a data storage device (or a computer-readable medium)  194  for storing data, algorithms and computer programs  196  accessible to the processor  192 . The data storage device  194  may be any suitable device, including, but not limited to, a read-only memory (ROM), a random-access memory (RAM), a flash memory, a magnetic tape, a hard disk and an optical disk. During drilling, a drilling fluid  179  from a source thereof is pumped under pressure into the tubular member  116 . The drilling fluid discharges at the bottom of the drill bit  150  and returns to the surface via the annular space  120  (also referred as the “annulus”) between the drill string  118  and the inside wall  142  of the wellbore  110 . 
     Still referring to  FIG. 1 , the drill bit  150  includes cutters  151  at selected locations on the drill bit that are configured to cut into the formation  119 . The drill bit  150  also includes a gage section  152  that is substantially parallel to the longitudinal axis of the drill bit  150 . In one aspect, a cutting device  160  is provided in the drill bit above or uphole of the cutters  151  to cut the formation on a high side of the drill bit. In one aspect, the cutting device  160  may include a substantially non-rotating member or sleeve  154  placed around the gage section  152  and one or more cutters  156  on the non-rotating member  154 . An actuation device  157  disposed in the drill bit and/or in the BHA  130  may be utilized to operate the cutters  156 . Devices and sensors  158  may be provided in the BHA to determine the inclination, azimuth and tool face of the BHA  130 . A controller  170  in the BHA may be configured to use data from sensors  158  to determine the tool face and high side of the BHA  130  during drilling of the wellbore  110 . The controller  170  or another controller within or outside the drill bit  150  may be utilized to control the operation of the actuation device  157  to drill the wellbore along the high side of the wellbore while drilling of the wellbore. In operation, the controller  170  orients the cutting device  160  along the high side  161  of the wellbore  110  and controls the actuation device  157  and thus the cutting device  160  to cut the formation on the high side  161  of the wellbore  110 . The actuation device  157  may be any suitable device, including, but not limited to, a hydraulic device, an electrical device, and a mechanical device. One or more actuation devices  159  may be provided to articulate the BHA and thus the drill bit to drill the wellbore with a selected build rate along a desired curved path. The actuation device  159  may include force application members (ribs) and/or knuckle joints. Cutting the formation along the high side  161 , in one aspect, may increase the build rate of drilling of the wellbore  110 . 
     Still referring to  FIG. 1 , the BHA  130  may further include one or more downhole sensors (collectively designated by numeral  175 ). The sensors  175  may include any number and type of sensors, including, but not limited to, sensors generally known as the measurement-while-drilling (MWD) sensors or logging-while-drilling (LWD) sensors, and sensors that provide information relating to the behavior of the BHA  130  and the drill bit  150 , such as drill bit rotation speed (revolutions per minute or “RPM”), pressure, vibration, whirl, oscillation, bending, stick-slip and formation type. Sensor  158  may be provided to determine the tool face and high side of the wellbore. The controller  170  may be configured to control the operation of the actuation device  157  and to at least partially process data received from the sensors  158  and  175 . The controller  170  may include circuits configured to process the sensor  175  signals (e.g., amplify and digitize the signals), a processor  172  (such as a microprocessor) configured to process the digitized signals, a data storage device  174  (such as a solid-state-memory), and computer programs  176  accessible to the processor  172 . The processor  172  may process the digitized signals, control the operation of the actuation device  157 , process data from sensors  158  and  175 , control the operations of the sensors  175  and other downhole devices, and communicate data information with the controller  190  via a two-way telemetry unit  188 . The controller  170 , in one aspect may control the actuation device  157  to control the cutting action of the cutting device  160  in response to one or more parameters of interest, including, but not limited to, rate of penetration (ROP), vibration, stick-slip, whirl, oscillation, bending moment, torque, rock type, and desired build rate, based on the programmed instructions stored in the data storage device  174  and/or instructions sent by the surface controller  190 . Such adjustments may be made in-situ. Adjusting or altering the cutting device  160  operation (for example speed) may provide a desired build rate along with a smoother wellbore and extended drill bit life. 
       FIG. 2  shows an isometric view of a drill bit  150  made according to one embodiment of the disclosure. The drill bit  150  shown is a polycrystalline diamond compact (PDC) drill bit having a bit body  212  that includes a cutting section  212   a  and shank  212   b  that connects to a BHA  130 . The cutting section  212   a  includes a face section  218   a  (also referred to herein as the “bottom section”). For the purpose of this disclosure, the face section  218   a  may comprise a nose, cone and shoulder as shown in  FIG. 3 . The cutting section  212   a  is shown to include a number of blade profiles  214   a ,  214   b , . . .  214   n  (also referred to as the “profiles”). Each blade profile includes cutters on the face section  218   a . Each blade profile terminates proximate to a drill bit center  215 . The drill bit center  215  faces (or is in front of) the bottom of the wellbore  110  ahead of the drill bit  150  during drilling of the wellbore. The drill bit includes a side portion  213 , generally referred to as the gage section, that is substantially parallel to the longitudinal axis  222  of the drill bit  150 . A number of spaced-apart cutters are shown placed along each blade profile. For example, blade profile  214   n  is shown to contain cutters  216   a - 216   m . Each cutter has a cutting surface or cutting element, such as cutting element  216   a ′ for cutter  216   a , that engages the rock formation when the drill bit  150  is rotated during drilling of the wellbore. Each cutter  216   a - 216   m  is configured with a back rake angle and a side rake angle that, in combination, define the depth of cut of the cutter into the rock formation. 
     The drill bit  150  of  FIG. 2  is further shown to include a non-rotating member  154  placed in a cavity  154 ′ made in the gage section  213 . A cutting device  160  having one or more cutters or cutting elements  156  is shown placed on or carried by the non-rotating member  154 . An actuation device  157  is operatively coupled to the cutting device  160  and activates the cutting members  156 . A controller  170 / 171  disposed at a suitable location controls the operation of the actuation device  157 . 
       FIG. 3  is a schematic illustration of a blade profile  300  of drill bit  150  shown in  FIG. 2 . The blade profile  300  includes a nose section  302 , cone section  304 , shoulder section  306  and gage section  152 . Each of these sections may have cutting elements  320  thereon for cutting the formation. In one configuration, a non-rotating member  154  is placed around the periphery of the gage section  152  above or uphole of any gage cutters, such as cutter  322 . A cutting device  310  is placed on the non-rotating member  154 . One or more cutters  312  are disposed in the cutting device  310 . In one aspect, the cutting device  310  may be configured to rotate about an axis  314  by a prime mover, such as a fluid under pressure supplied by an actuation device  350 . In one aspect, the actuation device  350  may supply fluid  352  under pressure to the cutting device  310  via a fluid channel  340 . A control valve  354  placed in the fluid channel  340  may control the flow of the fluid from the actuation device  350  to the cutting device  310 . The actuation device  350 , in one aspect, may include a pump or turbine operated by the drilling fluid flowing through the drill bit or electrically-operated by motor. The fluid  352  may be the drilling fluid  179  ( FIG. 1 ) flowing through the drill bit center. Bearings  318  may be provided to facilitate the relative motion of the non-rotating member  154  with respect to the rotating gage section  152 . For the purpose of this disclosure a non-rotating member is a member that is able to remain stationary or substantially stationary relative to the borehole when the drill bit is rotating so that a cutting device thereon is able to cut the formation along a selected wellbore section during drilling of the wellbore. 
       FIG. 4  is a schematic illustration of a blade profile  400  of drill bit  150  shown in  FIG. 2  that includes a cutting device  410  in a notch or cavity  420  formed in the gage section  152  of the drill bit  150 . The cutting device  410 , in one configuration, may include a rotating member  412  configured to rotate about pivot points  416  in the cavity  420 . The rotating member  412  may be a cylindrical element or a roller that includes cutting elements  414  thereon configured to cut the formation. The cutting elements  414  may be arranged in any manner, including in rows  418   a ,  418   b , etc. around the rotating member  412 . The rotating  412  may be a powered member or a non-powered member. Power may be provided by a fluid under pressure via a fluid channel  440  in a manner similar to as described in reference to  FIG. 3 . In another aspect, the rotating member  412  may be rotated by an electrical device, such as a motor. 
       FIG. 5  is an illustration of a cross-section of a drill bit  500  that includes a cutting device  520  on a gage section of the drill bit. The drill bit  500  includes blade profiles  510   a - 510   n  respectively carrying cutting elements  512   a - 512   n . One cutting device  520  on the gage section includes a rotating member  522  carrying cutting elements  524 . The outer diameter of the gage section is shown by dotted circle  514 . In one aspect, a flow orienting device  550 , such as a flow orienting ring, may be utilized to supply a fluid under pressure to the cutting device  520 . The flow orienting device  550 , in one aspect, may include an open fluid flow section  552  that during drilling orients along a fluid channel  540  to supply the fluid to the cutting device  520 . Other sections  554  of the flow orienting device  550  are closed. 
       FIG. 6  shows a cross-section view  600  of a drill bit that includes a cam-type rotation cutting device  610  for cutting the formation on the high side of wellbore. The cutting device  610  is placed on a sleeve around the drill bit  600 . The cutting device  610  may include a first rotating member  620  that rotates a second member  630  that has cutters  632  thereon. The members  620  and  630  may include interlocking teeth or gears. Power to the member  620  may be provided by a fluid under pressure or by an electrical motor. When the cutting element  630  is engaged with the formation, the center  640  of the sleeve carrying the cutting device may be offset from the center  642  of the drill bit, as shown in  FIG. 6 . 
     Thus, in one aspect, a drill bit is disclosed that in one configuration may include a cutting device or cutters placed on a selected section of the drill bit, which cutting device is configured to cut formation surrounding the drill bit along a high side of the formation during drilling of a wellbore. In one aspect, the selected section may be the gage section of the drill bit or another suitable location. In another aspect, the cutting device may comprise a cutting element disposed on a non-rotating member placed around the selected section. A suitable actuation device may be configured to supply power to the cutting device. Any suitable actuation device may be utilized for the purpose of this disclosure, including, but not limited to: a mechanical device; a hydraulic device; an electrical device; and an electro-mechanical device. In another aspect any suitable cutting device may be used, including, but not limited to devices containing: a rotor having one or more cutting elements thereon placed on a non-rotating sleeve around a gage section of the drill bit; a cam-type rotation device having cutters thereon; and a rotor having cutters thereon disposed in a cavity on a gage section of the drill bit. In another aspect, a controller in the drill bit and/or in a BHA may be utilized to control power to the cutting device. The controller may be configured to orient the cutting device along a high side of the wellbore before activating the cutting device. 
     In another aspect, a method for drilling a wellbore is provided, which may include: drilling a wellbore by a drill bit; and cutting a formation on a high side of the wellbore to obtain a desired build rate. The method may further include orienting a cutting device on the drill bit to the high side of the wellbore and activating the cutting device to cut the formation on the high side of the wellbore. The method may further include orienting the cutting device along the high side before cutting the formation on the high side of the wellbore. 
     The disclosure herein describes particular configurations of cutting devices on a side of a drill bit. Any suitable cutting device configured to cut the formation along the high side of the wellbore, however, may be utilized for the purpose of this disclosure. Also, any suitable device or method may be utilized to power the cutting devices.