Patent Publication Number: US-9845648-B2

Title: Drill bits with variable flow bore and methods relating thereto

Description:
CROSS-REFERENCE TO RELATED APPLICATIONS 
     Not applicable. 
     STATEMENT REGARDING FEDERALLY SPONSORED RESEARCH OR DEVELOPMENT 
     Not applicable. 
     BACKGROUND 
     The present disclosure relates generally to drilling systems and earth-boring drill bits for drilling a borehole for the ultimate recovery of oil, gas, and/or minerals. More particularly, the present disclosure relates to drill bits with one or more selectively engageable variable flow bores incorporated therein. 
     During subterranean drilling operations, an earth-boring drill bit is connected to the lower end of a drill string and is rotated by rotating the drill string from the surface, with a downhole motor, or by both. With weight-on-bit (WOB) applied, the rotating drill bit engages the formation and proceeds to form a borehole toward a target zone. 
     During these operations, costs are generally proportional to the length of time it takes to drill the borehole to the desired depth and location. The time required to drill the well, in turn, is greatly affected by the number of times downhole tools must be changed, added, and/or repaired during drilling operations. This is the case because each time a downhole tool is changed, added, and/or repaired, the entire string of drill pipes, which may be miles long, must be retrieved from the borehole, section-by-section. Once the drill string has been retrieved and the desired operation is complete, the drill string must be constructed section-by-section and lowered back into the borehole. This process, known as a “trip” of the drill string, requires considerable time, effort and expense. Since drilling costs are typically on the order of thousands of dollars per hour, it is desirable to reduce the number of times the drill string must be tripped to complete the borehole. 
     During conventional drilling operations, it is often necessary to change, replace, and/or repair the drill bit disposed at the lower end of the drill string once it has become damaged, worn out, and/or its cutting effectiveness has sufficiently decreased. Regardless of the specific motivations, each time the drill bit is changed, replaced, and/or repaired, a trip of the drill string must be performed which thus increases the overall time and costs associated with drilling the subterranean wellbore. 
     BRIEF SUMMARY OF THE DISCLOSURE 
     Some embodiments disclosed herein are directed to a drill bit for drilling a borehole in a subterranean formation. In an embodiment, the drill bit includes a bit body having a central axis, a first end, a second end opposite the first end, and a radially outer surface. The bit body includes a flow passage extending axially from the first end, and a cutting structure disposed at the second end. In addition, the bit includes an actuating member disposed within the flow passage. The actuating member includes a throughbore, a radially outer surface, and a fluid flow port extending radially from the throughbore to the radially outer surface of the actuating member. The actuating member is configured to move axially relative to the bit body between a first position restricting fluid communication between the throughbore and the borehole through the fluid flow port and a second position allowing fluid communication between the throughbore and the borehole through the fluid flow port. 
     Other embodiments disclosed herein are directed to a drill bit for drilling a borehole in a subterranean formation. In an embodiment, the drill bit includes a bit body having a central axis, a first end, a second end opposite the first end, and an outer surface extending from the first end to the second end. The bit body includes a central flow passage extending axially from the first end, a first fluid flow bore extending from the central flow passage to the outer surface, and a second fluid flow bore extending from the central flow passage to the outer surface. The second fluid flow bore is configured to supply drilling fluid to a cutting structure mounted to the second end of the bit body. In addition, the bit includes an actuating member movably disposed within the central flow passage. The actuating member includes a throughbore, a radially outer surface, and a fluid flow port extending radially from the throughbore to the radially outer surface of the actuating member. The actuating member is configured to move axially relative to the bit body between a first position with the fluid flow port of the actuating member out of axial alignment with the first fluid flow bore of the bit body and a second position with the fluid flow port of the actuating member at least partially axially aligned with the first fluid flow bore of the bit body. The throughbore of the actuating member is configured to supply drilling fluid to the second fluid flow bore of the bit body but not the first fluid flow bore of the bit body with the actuating member in the first position. The throughbore of the actuating member is configured to supply drilling fluid to the first fluid flow bore of the bit body and the second fluid flow bore of the bit body with the actuating member in the second position. 
     Still other embodiments disclosed herein are directed to a method for drilling a borehole in a subterranean formation. In an embodiment, the method includes (a) rotating a drill bit about a central axis, the drill bit including a bit body having a first end, a second end opposite the first end, a radially outer surface, a flow passage extending axially from the first end, and a cutting structure disposed at the second end. In addition, the method includes (b) flowing drilling fluid through the flow passage of the bit body during (a), and (c) axially moving an actuating member to a first position within the flow passage. The actuating member includes a throughbore, a radially outer surface, and a fluid flow port extending radially from the throughbore to the radially outer surface of the actuating member. Further, the method includes (d) restricting fluid communication between the throughbore and the borehole through the fluid flow port during (c). Still further, the method includes (e) axially moving the actuating member to a second position within the flow passage that is axially spaced from the first position, and (f) allowing fluid communication between the throughbore and the borehole through the first flow port during (e). 
     Embodiments described herein comprise a combination of features and advantages intended to address various shortcomings associated with certain prior devices, systems, and methods. The foregoing has outlined rather broadly features and technical advantages in order that the detailed description that follows may be better understood. The various characteristics described above, as well as other features, will be readily apparent to those skilled in the art upon reading the following detailed description, and by referring to the accompanying drawings. It should be appreciated by those skilled in the art that the conception and the specific embodiments disclosed may be readily utilized as a basis for modifying or designing other structures for carrying out. It should also be realized by those skilled in the art that such equivalent constructions do not depart from the spirit and scope of the disclosure. 
    
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
       For a detailed description of the exemplary embodiments, reference will now be made to the accompanying drawings in which: 
         FIG. 1  is a schematic, partial side cross-sectional view of a drilling system including an embodiment of a drill bit in accordance with the principles disclosed herein; 
         FIG. 2  is a schematic, side cross-sectional view of the drill bit of  FIG. 1  with the actuating member disposed in a first position restricting the flow of drilling fluid through one or more of the variable flow bores; 
         FIG. 3  is a schematic, side cross-sectional view of the drill bit of  FIG. 1  with the actuating member disposed in a second position allowing drilling fluid to flow through one or more of the variable flow passages; 
         FIG. 4  is a schematic, side cross-sectional view of an embodiment of a drill bit for use with the drilling system of  FIG. 1  with an actuating member disposed in a first position restricting the flow of drilling fluid through one or more variable flow passages; 
         FIG. 5  is a schematic, side cross-sectional view of the drill bit of  FIG. 4 , with the actuating member disposed in a second position allowing drilling fluid to flow through one or more of the variable flow passages; 
         FIG. 6  is a schematic, partial side cross-sectional view of an embodiment of a drill bit for use with the drilling system of  FIG. 1  with an actuating member disposed in a first position restricting the flow of drilling fluid through one or more variable flow passages; and 
         FIG. 7  is a schematic, partial side cross-section view of the drill bit of  FIG. 6  with the actuating member disposed in a second position allowing drilling fluid to flow through one or more of the variable flow passages. 
     
    
    
     DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS 
     The following discussion is directed to various embodiments. However, one skilled in the art will understand that the examples disclosed herein have broad application, and that the discussion of any embodiment is meant only to be illustrative of that embodiment, and not intended to suggest that the scope of the disclosure, including the claims, is limited to that embodiment. 
     Certain terms are used throughout the following description and claims to refer to particular features or components. As one skilled in the art will appreciate, different persons may refer to the same feature or component by different names. This document does not intend to distinguish between components or features that differ in name but not function. The drawing figures are not necessarily to scale. Certain features and components herein may be shown exaggerated in scale or in somewhat schematic form and some details of conventional elements may not be shown in interest of clarity and conciseness. 
     In the following discussion and in the claims, the terms “including” and “comprising” are used in an open-ended fashion, and thus should be interpreted to mean “including, but not limited to . . . .” Also, the term “couple” or “couples” is intended to mean either an indirect or direct connection. Thus, if a first device couples to a second device, that connection may be through a direct connection, or through an indirect connection via other devices, components, and connections. In addition, as used herein, the terms “axial” and “axially” generally mean along or parallel to a central axis (e.g., central axis of a body or a port), while the terms “radial” and “radially” generally mean perpendicular to the central axis. For instance, an axial distance refers to a distance measured along or parallel to the central axis, and a radial distance means a distance measured perpendicular to the central axis. Any reference to up or down in the description and in the claims will be made for purposes of clarity, with “up”, “upper”, “upwardly”, “uphole”, or “upstream” meaning toward the surface of the borehole and with “down”, “lower”, “downwardly”, “downhole”, or “downstream” meaning toward the terminal end of the borehole, regardless of the borehole orientation. 
     A previously described, it is often necessary to change, replace, and/or repair the drill bit disposed at the lower end of the drill string once it has become damaged, worn out, or its cutting effectiveness has sufficiently decreased. For example, during drilling operations, drilling fluid, also referred to as “drilling mud,” is pumped from the surface, through the drill string to the drill bit, and out nozzles in the face of the drill bit. The drilling fluid exits the bit and then flows back to the surface via the annulus between the borehole and/or casing and the drill string. In general, the drilling fluid functions to lubricate and cool the drill bit during drilling, as well as flush formation cuttings back to the surface through the annulus. As drilling fluid flows through the drill bit, particulate matter suspended in the drilling fluid may collect and buildup within one or more of the nozzles of the bit, thereby restricting the outflow of drilling fluids from such nozzles. In some cases, such nozzle restrictions may be sufficient to detrimentally affect drilling operations. In addition, such nozzle restrictions may result in an increase in the pressure within the drill bit as compared to the pressure within the downhole environment. Many downhole components (e.g., rotary steerable tools, under reamers, etc.) require a specific pressure drop across the bit (or range of suitable pressure drops) for their proper operation during drilling. Thus, the increase in pressure within the bit due to the flow restriction of created by the plugged or partially plugged nozzle can also detrimentally affect the performance of such downhole components. Further, different downhole components and/or operations require different pressure drops across the bit, and thus, in situations where multiple such components and/or operations are utilized, it is difficult to select an appropriate nozzle design. 
     Accordingly, embodiments disclosed herein include drill bits having one or more variable flow bores incorporated therein and configured to selectively allow drilling fluids to flow therethrough during drilling operations. In some embodiments, the one or more variable flow bores are configured to selectively allow drilling fluids to flow therethrough based on the differential pressure between the interior of the bit and the exterior environment (e.g., the borehole). In other embodiments, the one or more variable flow bores are configured to selectively allow drilling fluids to flow therethrough based on the flow rate of drilling fluids through the bit. 
     Referring now to  FIG. 1 , an embodiment of a drilling system  10  for drilling a borehole  11  in an earthen formation  12  is shown. In this embodiment, drilling system  10  includes a drilling rig  20  positioned over borehole  11  and a drill string  30  suspended from a derrick  21  of rig  20  into borehole  11 . Drill string  30  has a central or longitudinal axis  31 , a first or uphole end  30   a  coupled to derrick  21 , and a second or downhole end  30   b  opposite end  30   a . A drill bit  100  is coupled to downhole end  30   b  of drill string  30 . In this embodiment, drill string  30  is formed by a plurality of tubular pipe joints  33  connected end-to-end, and drill bit  100  is connected to the lower end of the lowermost pipe joint  33 . 
     In this embodiment, drill bit  100  is rotated by rotation of drill string  30  from the surface  9 . In particular, drill string  30  is rotated by a rotary table  22  that engages a kelly  23  coupled to uphole end  30   a  of drill string  30 . Kelly  23 , and hence drill string  30 , is suspended from a hook  24  attached to a traveling block (not shown) with a rotary swivel  25  which permits rotation of drill string  30  relative to derrick  21 . Although drill bit  100  is rotated from the surface with rotary table  22  and drill string  30 , in general, the drill bit  100  can be rotated with a rotary table or a top drive disposed at the surface  9 , a downhole mud motor disposed downhole, or combinations thereof (e.g., rotated by both rotary table via the drill string and the mud motor, rotated by a top drive and the mud motor, etc.). For example, rotation via a downhole motor may be employed to supplement the rotational power of a rotary table  22 , if required, and/or to effect changes in the drilling process. Thus, it should be appreciated that the various aspects disclosed herein are adapted for employment in each of these drilling configurations and are not limited to conventional rotary drilling operations. 
     During drilling operations, a mud pump  26  at the surface  9  pumps drilling fluid or mud down the interior of drill string  30  via a port in swivel  25 . The drilling fluid exits drill string  30  through ports or nozzles in the face of drill bit  100 , and then circulates back to the surface  9  through the annulus  13  between drill string  30  and the sidewall of borehole  11 . The drilling fluid functions to lubricate and cool drilling bit  100 , and carry formation cuttings to the surface  14 . 
     Referring now to  FIG. 2 , drill bit  100  of drilling system  10  is shown. Bit  100  has a central or longitudinal axis  105  that may be aligned with axis  31  of drill string  30  and includes a bit body  101 , an elongate sleeve or liner  120 , and an actuating tube or member  140 . Body  101 , liner  120 , and actuating member  140  are coaxially aligned such that each shares a common central axis  105 . 
     Bit body  101  has a first or uphole end  101   a , a second or downhole end  101   b  opposite uphole end  101   a , and an outer surface  101   c  extending axially between ends  101   a ,  101   b . In addition, bit body  101  includes an externally threaded male or pin connector  106  at uphole end  101   a  for coupling bit  100  to drill string  30 , a cutting structure  102  at downhole end  101   b  for engaging and cutting the formation  12 , and a central section  107  extending axially between pin connector  106  and cutting structure  102 . In general, cutting structure  102  can be any suitable cutting structure for engaging and cutting a subterranean formation (e.g., formation  12 ) to form a borehole therethrough (e.g., borehole  11 ), such as, for example, a fixed cutter cutting structure, a rolling cone cutting structure, etc. In this embodiment cutting structure  102  is a fixed cutter cutting structure that is configured to shear off portions of borehole  11  when bit  100  is rotated about axis  105  in a cutting direction. In addition, bit body  101  includes an internal flow passage  104  extending axially from the uphole end  101   a . In this embodiment, passage  104  includes a first or uphole cylindrical section  104   a  extending axially from end  101   a , a lower chamber  104   c  proximal end  101   b , a second or downhole cylindrical section  104   b  extending axially from chamber  104   c , and an upward facing annular planar shoulder  103  extending radially between sections  104   a ,  104   b . In this embodiment, chamber  104   c  is hemispherical in shape, however, in general, chamber  104   c  may be formed in any suitable shape for receiving a volume of drilling fluid therein. 
     A pair of primary flow bores  108  extend radially from chamber  104   c  through bit body  101  to the face of bit  100  disposed at downhole end  101   b , thereby creating multiple flow paths between chamber  104   c  and the outer environment surrounding bit  100  (e.g., the borehole  11 ). Further, a pair of secondary variable flow nozzles or bores  110  extend radially from uphole cylindrical section  104   a  of passage  104  through central section  107  of body  101  to outer surface  101   c , thereby creating multiple fluid flow paths from section  104   a  of passage  104  to the outer environment surrounding bit  100  (e.g., the borehole  11 ). As will be described in more detail below, during drilling operations, drilling fluid flows into bit  100  at uphole end  101   a  and exits bit  100  through one or more of the flow bores  108 ,  110 . 
     Referring still to  FIG. 2 , elongate tubular sleeve  120  is fixably secured to bit body  101  within passage  104  and includes a first or uphole end  120   a  at end  101   a , a second or downhole end  120   b  opposite uphole end  120   a , a radially outer surface  122  extending axially between ends  120   a ,  120   b , and a radially inner surface  124  extending axially between ends  120   a ,  120   b . Inner surface  124  defines a through bore  126  extending axially through sleeve  120 . Outer surface  122  includes a first or uphole cylindrical section  122   a  extending axially from uphole end  120   a , a second or downhole cylindrical section  122   b  extending axially from downhole end  120   b , and a downward facing annular planar shoulder  122   c  extending radially between sections  122   a ,  122   b . Inner surface  124  includes a first or uphole cylindrical section  124   a  extending axially from uphole end  120   a , a second or downhole cylindrical section  124   b  extending axially from downhole end  120   b , and an upward facing annular planar shoulder  125  extending radially between sections  124   a ,  124   b . A pair of circumferentially-spaced apertures or through holes  128  extend radially between the surfaces  122 ,  124  within uphole section  122   a . As is shown in  FIG. 2 , when sleeve  120  is installed within passage  104 , uphole section  122   a  of outer surface  122  engages bit body  101  along uphole section  104   a  of passage  104 , downhole section  122   b  of outer surface  122  engages bit body  101  along downhole section  104   b  of passage  104 , shoulder  122   c  abuts or engages shoulder  103 , and apertures  128  are axially and circumferentially aligned with secondary flow bores  110 . In general, sleeve  120  can be fixably secured to bit body  101  within passage  104  by any suitable method or means, such as, for example, by engaging corresponding threads on sleeve  120  and within passage  104 . 
     In this embodiment, sleeve  120  is a wear component that slidably engages movable actuating member  140  (described below) to prevent excessive wear of bit body  101  during operations. Thus, in at least some embodiments, sleeve  120  comprises a relatively robust material such as, for example, Tungsten Carbide, that can better withstand prolonged sliding engagement with another component (e.g., actuating member  140 ), thereby increasing the effective usable life of bit  100 . 
     Referring still to  FIG. 2 , actuating member  140  is an elongate tubular member slidingly disposed in sleeve  120 . Actuating member  140  has a first or uphole end  140   a  axially positioned above end  101   a , a second or downhole end  140   b  opposite uphole end  140   a , a radially outer surface  144  extending axially between ends  140   a ,  140   b , and a radially inner surface  146  extending axially between ends  140   a ,  140   b . A flange  142  is disposed at uphole end  140   a  and has an upward facing annular planar surface  143  and a downward facing annular surface  160 . Upward facing annular planar surface  143  includes a first annular portion  143 A that is axially opposite surface  160  and has a surface area SA 143A  and a second annular portion  143 B that is radially inward of first portion  143 A and has a surface area SA 143B . Downhole end  140   b  has a downward facing annular planar surface  141  with a total surface area SA 141  Inner surface  146  defines a throughbore  148  that extends axially between ends  140   a ,  140   b  and is configured to receive drilling fluid pumped from the surface  9  during drilling operations. In this embodiment, inner surface  146  includes an upward facing frustoconical surface  151  disposed at uphole end  140   a  and a cylindrical surface  152  extending axially from surface  151  to downhole end  140   b . Frustoconical surface  151  has a total surface area SA 151 . Outer surface  144  includes a first or uphole cylindrical section  144   a  extending axially from end  140   a  and flange  142 , a second or downhole cylindrical section  144   b  extending axially from downhole end  140   b , and a downward facing annular planar shoulder  147  extending radially between sections  144   a ,  144   b . Shoulder  147  has a total surface area SA 147 . A pair of flow passages or ports  149  extend from inner surface  146  to outer surfaces  144 . In this embodiment, each port  149  extends radially outward and axially downward along a central axis  149 ′ moving from inner surface  146  to outer surface  144 . Thus, central axis  149 ′ is disposed at an acute angle θ with respect to central axis  105 . In some embodiments, the angle θ is preferably between 0° and 90°, more preferably between 30° and 60°, and most preferably equal to 45°. 
     During assembly of bit  100 , actuating member  140  is installed within throughbore  126  of sleeve  120  with uphole section  144   a  of outer surface  144  slidingly engaging uphole section  124   a  of inner surface  124 , and downhole section  144   b  of outer surface  144  slidingly engaging downhole section  124   b  of inner surface  124 . In addition, annular shoulders  125 ,  147  are axially opposed and face each other. However, shoulders  125 ,  147  are axially spaced apart, thereby forming an annulus or annular chamber  145  therebetween. As will be described in more detail below, chamber  145  is in constant fluid communication with the outer environment surrounding bit  100  (e.g., borehole  11 ) through apertures  128  and flow bores  110  such that the pressure within chamber  145  is the same or substantially the same as that outside of bit  100 . 
     Referring still to  FIG. 2 , an axial biasing member  150  is disposed between flange  142  and uphole end  101   a  of bit body  101 . In particular, biasing member  150  has a first or uphole end  150   a  engaging flange  142  and a downhole end  150   b  engaging end  101   a  of bit body  101 . Biasing member  150  is compressed between flange  142  and end  101   a , thereby biasing flange  142  and end  101   a  axially apart. In this embodiment, biasing member  150  is a coil spring disposed about actuating member  140 . 
     Referring now to  FIGS. 1-3 , during drilling operations bit  100  is coupled to downhole end  30   b  and bit  100  is rotated about the axes  31 ,  105  with weight-on-bit (WOB) applied such that cutting structure  102  engages formation  12  to lengthen borehole  11 . While rotating bit  100 , drilling fluid (e.g., drilling mud) is pumped from the surface  9  down drill string  30  to bit  100 . In addition, during these operations, actuating member  140  can be transitioned between a first or closed position with flow ports  149  axially misaligned with apertures  128  and flow bores  110  as shown in  FIG. 2 , and a second or open position with flow ports  149  at least partially axially aligned with apertures  128  and flow bores  110  as shown in  FIG. 3 . Thus, when member  140  is in the first position ( FIG. 2 ) fluid communication between throughbore  148  and bores  110  is restricted such that drilling fluids flow through throughbore  148  of actuating member  140  into chamber  104   c  and through flow bores  108 , but are restricted from flowing through flow bores  110 . Conversely, when member  140  is in the second position ( FIG. 3 ), fluid communication between throughbore  148  and bores  110  is established such that a portion of drilling fluids flows through ports  149  and flow bores  110 , while the remainder of the drilling fluids flow through throughbore  148  of actuating member  140  into chamber  104   c  and through flow bores  108 . Translation of member  140  from the first position ( FIG. 2 ) to the second position ( FIG. 3 ) occurs along a first axial direction  170  and translation of member  140  from the second position to the first position occurs along a second axial direction  171  that is opposite the first axial direction  170 . In this embodiment, axial translation of member  140  in the first direction  170  may continue until annular shoulder  147  on member  140  axially abuts and engages annular shoulder  125  on sleeve  120 . In some embodiments, axial translation of member  140  in the second direction  171  is limited by a suitable device (not shown) such as, for example, a retaining pin, a snap ring, a biasing member (e.g., a spring), etc. In other embodiments, axial translation of the member  140  in the second direction  171  is limited by engagement with the box connector of the immediately axially adjacent member to bit  100  within the drill string (e.g., drill string  30 ). 
     In this embodiment, actuating member  140  transitions between the first position and the second position in response to a sufficient pressure differential across transition member  140 . In particular, the surface areas SA 143B , SA 141 , SA 147 , SA 151  of surfaces  143 B,  141 ,  147 ,  151 , respectively, are each arranged and sized, and the biasing force supplied by member  150  is chosen, such that actuating member  140  translates in the first direction  170  when the pressure drop between throughbore  148  (and this section  104   a  of passage  104 ) and the outer environment of the bit  100  (e.g., borehole  11 ) reaches a predetermined level. In this embodiment, when the bit internal pressure P 1  is sufficiently greater than the bit external pressure P 2 , the internal pressure P 1  applied to surfaces  143 ,  151  will be sufficient to overcome the combined forces of: (1) the bit internal pressure P 1  applied to the surface  141 , (2) the biasing force supplied by biasing member  150 , and (3) the wellbore pressure, P 2 , operating on shoulder  147  through chamber  145 , such that actuating member  140  translates in the first direction  170  toward downhole end  101   b . As a result, during drilling operations, if the drop in pressure for the drilling fluids flowing from bit  100  into borehole  11  should increase above the predetermined level (e.g., if the pressure of fluid supplied by pump  26  is increased, if one or more of the flow bores  108  should become restricted, if the pressure within borehole  11  should decrease, etc.), then member  140  translates in the first direction  170  toward lower end  101   b  to allow drilling fluid to flow through flow bores  110 , thereby at least partially relieving the pressure difference between throughbore  148  and borehole  11 . As the pressure difference between throughbore  148  and borehole  11  falls to within an acceptable range, member  140  translates axially in the second direction  171  toward uphole end  101   a , such that flow ports  149  are once again misaligned with apertures  128  and flow bores  110  and the flow of drilling fluids through ports  149 , apertures  128 , and bores  110  is once again restricted. Thus, the translation of actuating member  140  within passage  104  of body  101  allows the pressure drop across bit  100  to be maintained at a predetermined value or range of values during drilling operations. In some embodiments, the previously determined pressure difference between throughbore  148  and borehole  11  that is sufficient to transition member  140  in first direction  170  toward the second position preferably ranges from 100 psi to 1000 psi, and more preferably ranges from 200 psi to 800 psi. 
     In the embodiment of drill bit  100  previously described, actuating member  140  transitions between the first position and the second position, thereby opening and closing flow bores  110  in response to a pressure difference between throughbore  148  and borehole  11 . However, in other embodiments, in accordance with the principles disclosed herein, variable flow bores are opened and closed based on the flow rate of drilling fluid flowing therethrough. For example, referring now to  FIG. 4 , an embodiment of a drill bit  200  for use in drilling system  10  is shown. Bit  200  has a central or longitudinal axis  205  that may be aligned with axis  31  of drill string  30  during operations. In addition, in this embodiment, includes a bit body  201 , an elongate sleeve or liner  220  disposed in bit body  201 , and an actuating tube or member  240  moveably disposed in sleeve  220 . Body  201 , sleeve  220 , and member  240  are coaxially aligned such that each shares a common central axis  205 . 
     Bit body  201  is substantially the same as bit body  101  previously described. In particular, bit body  201  has a first or uphole end  201   a , a second or downhole end  201   b  opposite uphole end  201   a , an outer surface  201   c  extending axially between ends  201   a ,  201   b . In addition, bit body  201  includes pin connector  106  at uphole end  201   a , cutting structure  102  at downhole end  201   b , a central section  207  extending axially between connector  106  and structure  102 , an internal passage  204  extending axially from end  201   a , and a pair of fluid flow bores  210  extending radially from passage  204  through central section  207  of body  201  to outer surface  201   c . Passage  204  includes a first or uphole cylindrical section  204   a  and a chamber  204   b . Section  204   a  extends axially from end  201   a  to chamber  204   b . Thus, unlike passage  104  of bit  100  previously described, in this embodiment, passage  204  only includes one cylindrical section  204   a  extending between end  201   a  and chamber  204   b . Further, bit body  201  also includes flow bores  208  extending from chamber  204   b  to the face of bit  200  at end  201   b  in a similar manner to that described above for bores  108  on bit  100 , previously described. 
     Referring still to  FIG. 4 , elongate tubular sleeve  220  is fixably disposed in passage  204  and includes a first or uphole end  220   a , a second or downhole end  220   b  opposite uphole end  220   a , a radially outer surface  222  extending axially between ends  220   a ,  220   b , and a radially inner surface  224  extending axially between ends  220   a ,  220   b . Inner surface  224  defines a throughbore  226  extending axially through sleeve  220 . Each surface  222 ,  224  is cylindrical, and thus, the radius of each surface  222 ,  224  does not vary between ends  220   a ,  220   b . A pair of circumferentially-spaced apertures or through holes  228  extend radially from inner surface  224  to outer surface  222 . When sleeve  220  is installed within passage  204 , apertures  228  are axially and circumferentially aligned with flow bores  210 . 
     Similar to sleeve  120  previously described, sleeve  220  is a wear component that engages with the movable actuating member  240  (described below). Thus, in at least some embodiments, sleeve  220  comprises a relatively robust material such as, for example, Tungsten Carbide, that can better withstand prolonged sliding engagement with another component (e.g., actuating member  240 ), thereby increasing the effective usable life of bit  200 . 
     Referring still to  FIG. 4 , actuating member  240  is an elongate tubular member slidingly disposed in sleeve  220 . Actuating member  240  has a first or uphole end  240   a , a second or downhole end  240   b  opposite uphole end  240   a , a radially outer surface  244  extending axially between ends  240   a ,  240   b , and a radially inner surface  246  extending axially between ends  240   a ,  240   b . An annular flange  242  is disposed at uphole end  240   a . Flange  242  has an upward facing annular planar surface  243  and a downward facing annular surface  260 . Upward facing annular planar surface  243  includes a first annular portion  243 A that is axially opposite surface  260  and has a surface area SA 243A  and a second annular portion  243 B that is radially inward of first portion  243 A and has a surface area SA 243B . Downhole end  240   b  has a downward facing annular planar surface  241  with a total surface area SA 241 . Inner surface  246  defines a throughbore  248  that extends axially between ends  240   a ,  240   b  and is configured to receive drilling fluid pumped from the surface  9  during drilling operations. Unlike sleeve  140  of bit  100  previously described, in this embodiment, throughbore  248  of sleeve  240  includes a flow restrictor  247  at uphole end  240   a . As drilling fluid flows through restrictor  247 , its fluid pressure is reduced. In this embodiment, restrictor  247  is a converging-diverging nozzle including a first or uphole upward facing frustoconical surface  247 A, a second or downhole downward facing frustoconical surface  247 C, and a cylindrical surface  247 B extending axially between surfaces  247 A,  247 C. Each of the frustoconical surface  247 A,  247 C has a total surface area SA 247A , SA 247C , respectively. In this embodiment, surfaces areas SA 247A , SA 247C  are the same. 
     Outer surface  244  is cylindrical between flange  242  and end  240   b , and thus, is disposed at a uniform radius between flange  242  and end  240   b  Inner surface  246  is cylindrical between restrictor  247  and end  240   b , and thus, is disposed at a uniform radius between restrictor  247  and end  240   b . Thus, unlike bit  100  previously described, which includes chamber  145  ( FIG. 2 ), in this embodiment, no chamber(s) are provided between passage  204 , sleeve  220 , and actuating member  240 . 
     Referring still to  FIG. 4 , a pair of flow passages or ports  249  extend radially through member  240  from inner surface  246  to outer surface  244 . In addition, a biasing member  250  is axially positioned between flange  242  and uphole end  201   a . More specifically, biasing member  250  has a first or uphole end  250   a  engaging flange  242  and a downhole end  250   b  engaging uphole end  201   a . Biasing member  250  is compressed between flange  242  and end  201   a , and thus, biases flange  242  and bit body  201  axially apart. In this embodiment, biasing member  250  is a coil spring disposed about actuating member  240 . 
     Referring now to  FIGS. 1, 4, and 5 , during drilling operations bit  200  is coupled to downhole end  30   b  of drill string  30  and bit  200  is rotated about the aligned axes  31 ,  205  with weight-on-bit (WOB) is applied such that cutting structure  102  engages with formation  12  to lengthen borehole  11  along a predetermined path. While rotating bit  200 , drilling fluid (e.g., drilling mud) is pumped from the surface  9  down drill string  30  to bit  200 . In addition, during these operations actuating member  240  can be transitioned between a first or closed position with flow ports  249  are axially misaligned with apertures  228  and flow bores  210  as shown in  FIG. 4 , and a second or open position with flow ports  249  at least partially axially aligned with apertures  228  and flow bores  210  as shown in  FIG. 5 . Thus, when member  240  is in the first position ( FIG. 4 ) fluid communication between throughbore  248  and bores  210  is restricted such that drilling fluids flow through throughbore  248  to flow bores  208 , but are restricted from flowing through flow bores  210 . Conversely, when member  240  is in the second position ( FIG. 5 ), fluid communication between throughbore  248  and bores  210  is established such that a portion of drilling fluids flow through ports  249  and flow bores  210 , while the remainder of the drilling fluids flow through passage  248  of actuating member  240  into chamber  204   b  and through flow bores  208 . Translation of member  240  from the first position ( FIG. 4 ) to the second position ( FIG. 5 ) occurs along a first axial direction  270  and translation of member  240  from the second position to the first position occurs along a second axial direction  271  that is opposite the first axial direction  270 . In this embodiment, axial translation of member  240  in first direction  270  may continue until biasing member  150  is fully compressed between flange  242  and uphole end  201   a  of body  201 . 
     In this embodiment, actuating member  240  transitions between the first position and the second position in response to the flow rate of drilling fluids flowing through bit  200 . In particular, as drilling fluid flows through throughbore  248  within bit  200 , there is a local pressure drop for drilling fluids across nozzle  247  (i.e., the pressure of the drilling fluid upstream of nozzle  247  is greater than the pressure of drilling fluid downstream of nozzle  247 ). As a result, member  240  is actuated in the first direction  270  when the pressure P 3  of the drilling fluids upstream of nozzle  247  acting on surfaces  243 B,  247 A is larger than the combination of the pressure P 4  of the drilling fluids downstream of nozzle  247  acting on surfaces  247 C,  241  and the biasing force supplied by biasing member  250 . Thus, actuation of member  240  is not necessarily dependent on the relative difference in pressure between throughbore  248  and borehole  11  as is the case for bit  100  previously described. Rather, in bit  200 , actuation of member  240  is dependent upon the pressure drop across nozzle  247 . Without being limited by this or any particular theory, the pressure drop across a converging-diverging nozzle (e.g., nozzle  247 ) is directly related to the flow rate through the nozzle, and thus, as the flow rate through a converging diverging nozzle increases, the pressure drop across the nozzle increases. In this embodiment, actuation member  240  is configured to transition from the first position to the second position at a predetermined flow rate (or within a predetermined range of flow rates) and associated pressure drop (or within a range of pressure drops) across nozzle  247  (e.g., the difference between P 3  and P 4 ). More specifically, in this embodiment, the surface areas SA 243B , SA 247A , SA 247C , SA 241  of surfaces  243 B,  247 A,  247 C,  241 , respectively, are arranged and sized, and the biasing force supplied by member  250  is chosen, such that when the flow rate of drilling fluid through nozzle  247  is at or above a predetermined value, the pressure drop across nozzle  247  is sufficient to transition member  240  in the first direction  270  from the first position ( FIG. 4 ) to the second position ( FIG. 5 ). For example, in one embodiment, actuating member  240  is configured such that a flow rate of drilling fluids between 400 and 500 GPM (gallons per minute) will not produce a sufficient pressure drop across nozzle  247  to enable member  240  to transition in the first direction  270 , however, once the flow of drilling fluids exceeds 550 GPM, the pressure drop across nozzle  247  is sufficient to axial translate member  240  to the second position (i.e., move member  240  in the first direction  270 ). 
     Actuation of member  240  within drill bit  200  to allow flow of drilling fluids through the flow bores  210  is particularly useful when an increased flow of drilling fluid through bit  200  is desired. For example, during drilling operations, it sometimes becomes desirable to flow an increased volume of drilling fluid through the drill string (e.g., drill string  30 ), bit (e.g., bit  200 ), and annulus (e.g., annulus  13 ) to sweep or clean cuttings or other materials from the wellbore (e.g., borehole  11 ). Thus, by allowing additional flow to escape bit  200  through flow bores  210  upon increasing the flow rate of drilling fluids flowing therethrough, the bit  200  is able to better accommodate such operations. 
     In the embodiments previously described, bits  100 ,  200  are fixed cutter bits including cutting structures defined by a plurality of blades and cutter elements secured thereto. However, in other embodiments, variable flow bores configured to transition between opened and closed positions in response to pressure differentials or drilling fluid flow rates can be used with other types of drill bits and downhole tools. For example, referring now to  FIG. 6 , an embodiment of a rolling cone drill bit  300  for use in drilling system  10  is shown. Bit  300  has a central or longitudinal axis  305  that may be aligned with axis  31  of drill string  30  during operations. In addition, in this embodiment, bit  300  includes a bit body  301  and an actuating tube or member  340  moveably disposed in body  301 . Body  301  and member  340  are coaxially aligned such that each shares a common central axis  305 . 
     Bit body  301  has a first or uphole end  301   a , a second or downhole end  301   b  opposite uphole end  301   a , an externally threaded male or pin connector  106  at upper end  301   a , and a cutting structure  302  at downhole end  301   b  for engaging and cutting the formation  12 . In this embodiment, cutting structure  302  comprises a plurality of rolling cones rotatably mounted to journals depending from bit body  301  and a plurality of cutting elements secured to each rolling cone to gouge or puncture formation  12 . In addition, bit body  301  includes an internal flow passage  304  extending axially from the uphole end  301   a . In this embodiment, passage  304  has a first or uphole cylindrical section  304   a  extending axially from uphole end  301   a  to an annular upward facing planar shoulder  303  and a second or downhole cylindrical section  304   b  extending axially from shoulder  303 . A plurality of circumferentially-spaced primary nozzles or flow bores  308  extend from uphole section  304   a  of passage  304  to a face of bowl of bit body  301  at end  301   b , thereby creating a flow path between passage  304  and the outer environment surrounding bit  300  (e.g., the borehole  11 ) (note: only two flow bores  308  are shown in  FIGS. 6 and 7 ). An annular sleeve member  320  is fixably disposed in passage  304  along downhole section  304   b . Sleeve member  320  has a radially inner cylindrical surface  322 . As will be described in more detail below, inner surface  322  of sleeve  320  is configured to slidingly engage with a corresponding outer surface of actuating member  340  during operations to protect bit body  301  from excessive wear. Accordingly, sleeve member  320  is preferably made of the same materials previously described above for sleeves  120 ,  220 . 
     Referring still to  FIG. 6 , actuating member  340  is an elongate tubular member having a first or uphole end  340   a , a second or downhole end  340   b  opposite uphole end  340   a , a radially outer surface  344  extending axially between ends  340   a ,  340   b , and a radially inner surface  346  extending axially between ends  340   a ,  340   b . A retaining ring or flange  342  is disposed at uphole end  340   a . Flange  342  includes an upward facing annular planar surface  343  and a downward facing annular surface  360 . Upward facing annular planar surface  343  includes a first annular portion  343 A that is axially opposite surface  360  and has a surface area SA 343A  and a second annular portion  343 B that is radially inward of first portion  343 A and has a surface area SA 343B . In addition, downhole end  340   b  of member  340  includes a downward facing frustoconical surface  341  having a total surface area SA 341 . Inner surface  346  defines a throughbore  348  extending axially through member  340  between ends  340   a ,  340   b  and is configured to receive drilling fluid pumped from the surface during drilling operations. In this embodiment, inner surface  346  includes an upward facing frustoconical surface  351  axially positioned at uphole end  340   a  and having a total surface area SA 351 . A plurality of radial flow passages or bores  349  extend radially through member  340  between the surfaces  344 ,  346  along an axis of flow  347  that is disposed at an acute angle β with respect to central axis  305  (note: only two flow passages  349  are shown in  FIGS. 6 and 7 ). In this embodiment, angle β is preferably the same as angle θ previously described above for bit  100  (and thus the potential range of values for angle β is the same as that previously described above for angle θ). 
     During assembly of bit  300 , actuating member  340  is installed within flow passage  304  of bit  300  such that uphole section outer surface  344  slidingly engages radially inner surface  322  of sleeve  320  and flange  342  axially opposes shoulder  303 . A biasing member  350 , which is similar to biasing member  150  previously described, is axially positioned between flange  342  and shoulder  303 . In particular, biasing member  350  has a first or uphole end  350   a  that axially abuts and engages flange  342  and a second or downhole end  350   b  that axially abuts and engages shoulder  303 . Biasing member  350  is axially compressed between flange  342  and shoulder  303 , and thus, biases actuating member  340  axially away from downhole end  301   b  and toward uphole end  301   a  of bit  300 . In this embodiment, biasing member  350  is a coiled spring disposed about actuating member  340 . 
     Referring now to  FIGS. 1, 6, and 7 , during drilling operations, bit  300  is coupled to downhole end  30   b  of drill string  30  and bit  300  is rotated about the axes  31 ,  305  with weight-on-bit (WOB) is applied such that the cutting structure of bit  302  engages with formation  12  to lengthen borehole  11 . While rotating bit  300 , drilling fluid (e.g., drilling mud) is pumped from the surface  9  down drill string  30  to bit  300 . In addition, during these operations actuating member  340  can be transitioned between a first or closed position with flow bores  349  axially disposed within downhole section  304   b  of passage  304  as shown in  FIG. 6 , and a second or open position with flow bores  349  extending at least partially axially past downhole end  301   b  and out from passage  304  as shown in  FIG. 7 . Thus, when member  340  is in the first position ( FIG. 6 ) fluid communication between throughbore  348  and borehole  11  through bores  349  is restricted such that drilling fluids flow through passage  304  and bores  308 , and are restricted from flowing through bores  349 . Conversely, when member  340  is in the second position ( FIG. 7 ), fluid communication between throughbore  348  and borehole  11  bores  349  is established such that a portion of drilling fluids flow through passage  304  and bores  308 , while the remainder of the drilling fluids flow through both throughbore  348  of actuating member  340  and bores  349 . Translation of member  340  from the first position ( FIG. 6 ) to the second position ( FIG. 7 ) occurs along a first axial direction  370  and translation of member  340  from the second position to the first position occurs along a second axial direction  371  that is opposite the first axial direction  370 . As member  340  translates in axial directions  370 ,  371 , outer surface  344  of member  340  slidingly engages inner surface  322  of sleeve  320  within downhole section  304   b  of passage  304 . In this embodiment, axial translation of member  340  in the first direction  370  may continue until biasing member  350  is fully compressed between flange  342  and shoulder  303 . 
     Similar to bit  100  previously described, bit  300  is arranged to actuate member  340  based on the pressure differential between internal flow passage  304  and the external environment surrounding bit  300  (e.g., borehole  11 ). In particular, in this embodiment the surface areas SA 343B , SA 341 , SA 351  of surfaces  343 ,  341 ,  351 , respectively, on member  340  are arranged and sized, and the biasing force supplied by biasing member  350  is chosen, such that such that actuating member  340  translates in the first direction  370  when the pressure drop between through passage  304  (particularly uphole section  304   a ) and the outer environment of the bit  300  (e.g., borehole  11 ) reaches a predetermined level. It should be appreciated that for the arrangement shown, downhole end  340   b  of actuating member  340  is exposed to the pressure within borehole  11  through downhole section  304   b  of passage  304 . Therefore, during drilling operations, if the drop in pressure for the drilling fluids flowing from bit  300  into borehole  11  should increase above the previously determined level (e.g., if the pressure of fluid supplied by pump  26  is increased, if one or more of the bores  308  should become restricted, if the pressure within borehole  11  should decrease, etc.), then member  340  translates in the first direction  370  toward lower end  301   b  to allow an additional flow of drilling fluid through the radial flow bores  349  such that the pressure difference between passage  304  and borehole  11  falls back to an acceptable level or within an acceptable range. As the pressure difference between passage  304  and borehole  11  falls to within an acceptable range, member  340  translates axially in the second direction  371  toward uphole end  301   a , such that flow bores  349  are once again axially disposed within downhole section  304   b  of passage  304  (such as is shown in  FIG. 6 ) and are thus restricted. Therefore, the translation of actuating member  340  within passage  304  of body  301  allows the pressure drop across bit  300  to be maintained at a desired value or range of values during drilling operations. 
     In the manner described, the flow of drilling fluid may be selectively diverted through one or more variable flow nozzles (e.g., flow bores  110 ) disposed in a drill bit (e.g., bit  100 ,  200 ,  300 ) during drilling operations based either on the differential pressure between the interior and exterior of the drill bit and/or the flow rate of drill fluids flowing through the drill bit. Through use of embodiments of drill bits in accordance with the principles disclosed herein (e.g., bit  100 ,  300 ), undesirable pressure increases within the interior of the bit are automatically accounted for by the additional outflow of excess fluid through the variable flow nozzles (e.g., flow bores  110 ). In addition, in at least some embodiments, use of a drill bit in accordance with the principles disclosed herein (e.g., bit  200 ) helps to automatically accommodate increased flow of drilling fluids therethrough (e.g., such as during a clean out operation of the wellbore) thereby further enhancing downhole operations. 
     It should be appreciated that the above described embodiments may include further modification while still complying with the principles disclosed herein. For example, in some embodiments, one or more shear pins may be engaged between the central flow passage of the bit (e.g., passage  104 ,  204 ,  304 ) and/or the sleeve (e.g., sleeves  120 ,  220 ,  320 ) and the actuating member (e.g., members  140 ,  240 ,  340 ) to resist undesired axial movement of the actuating member. During operations of such embodiment, the initial movement of the actuating member would be initiated by exerting a predetermined pressure on the actuating member (e.g., via a flow of drilling fluid) to shear off each of the one or more shear pins and thereby allow axial movement of the actuating member thereafter as previously described above. In addition, some embodiments may include annular seal assemblies radially disposed between the actuating member (e.g., members  140 ,  240 ,  340 ) and the sleeve (e.g., sleeves  120 ,  220 ,  320 ) to further restrict fluid flow between these components during drilling operations. Further, it should be appreciated that the number and arrangement of flow bores or passages (e.g., bores  108 ,  208 ,  308 ,  110 ,  210  and/or ports  149 ,  249 ,  349 ) can be greatly varied from that shown and described herein while still complying with the principles disclosed herein. 
     While preferred embodiments have been shown and described, modifications thereof can be made by one skilled in the art without departing from the scope or teachings herein. The embodiments described herein are exemplary only and are not limiting. Many variations and modifications of the systems, apparatus, and processes described herein are possible and are within the scope of the disclosure. Accordingly, the scope of protection is not limited to the embodiments described herein, but is only limited by the claims that follow, the scope of which shall include all equivalents of the subject matter of the claims. Unless expressly stated otherwise, the steps in a method claim may be performed in any order. The recitation of identifiers such as (a), (b), (c) or (1), (2), (3) before steps in a method claim are not intended to and do not specify a particular order to the steps, but rather are used to simplify subsequent reference to such steps.