Patent Publication Number: US-11377911-B2

Title: Fixed cutter drill bits including nozzles with end and side exits

Description:
CROSS-REFERENCE TO RELATED APPLICATIONS 
     This application is a continuation of U.S. application Ser. No. 16/065,652 filed Jun. 22, 2018, which is a 35 U.S.C. § 371 national stage application of PCT/US2017/014351 filed Jan. 20, 2017, and entitled “Fixed Cutter Drill Bits Including Nozzles with End and Side Exits,” which claims benefit of U.S. provisional patent application Ser. No. 62/281,461 filed Jan. 21, 2016, and entitled “Fixed Cutter Drill Bits Including Nozzles with End and Side Exits,” each of which is hereby incorporated herein by reference in its entirety for all purposes. 
    
    
     STATEMENT REGARDING FEDERALLY SPONSORED RESEARCH OR DEVELOPMENT 
     Not applicable. 
     BACKGROUND 
     The present disclosure relates generally to earth-boring bits used to drill a borehole for the ultimate recovery of oil, gas or minerals. More particularly, the disclosure relates to fixed cutter drill bits with improved hydraulics. Still more particularly, the disclosure relates to drilling fluid nozzles including end and side outlets for use with fixed cutter drill bits. 
     An earth-boring drill bit is typically mounted on the lower end of a drill string and is rotated by rotating the drill string at the surface or by actuation of downhole motors or turbines, or by both methods. With weight applied to the drill string, the rotating drill bit engages the earthen formation and proceeds to form a borehole along a predetermined path toward a target zone. The borehole thus created will have a diameter generally equal to the diameter or “gage” of the drill bit. 
     Fixed cutter bits, also known as rotary drag bits, are one type of drill bit commonly used to drill wellbores. Fixed cutter bit designs include a plurality of blades angularly spaced about the bit face. The blades generally project radially outward along the bit body and form flow channels there between. In addition, cutter elements are often grouped and mounted on several blades. The configuration or layout of the cutter elements on the blades may vary widely, depending on a number of factors. One of these factors is the formation itself, as different cutter element layouts engage and cut the various strata with differing results and effectiveness. 
     The cutter elements disposed on the several blades of a fixed cutter bit are typically formed of extremely hard materials and include a layer of polycrystalline diamond (“PD”) material. In the typical fixed cutter bit, each cutter element or assembly comprises an elongate and generally cylindrical support member which is received and secured in a pocket formed in the surface of one of the several blades. In addition, each cutter element typically has a hard cutting layer of polycrystalline diamond or other superabrasive material such as cubic boron nitride, thermally stable diamond, polycrystalline cubic boron nitride, or ultrahard tungsten carbide (meaning a tungsten carbide material having a wear-resistance that is greater than the wear-resistance of the material forming the substrate) as well as mixtures or combinations of these materials. The cutting layer is exposed on one end of its support member, which is typically formed of tungsten carbide. 
     While the bit is rotated, drilling fluid is pumped through the drill string and directed out of the face of the drill bit. The fixed cutter bit typically includes nozzles or fixed ports spaced about the bit face that serve to inject drilling fluid into the flow passageways between the several blades. The drilling fluid exiting the face of the bit through nozzles or ports performs several functions. In particular, the fluid removes formation cuttings (e.g., rock chips) from the cutting structure of the drill bit. Otherwise, accumulation of formation cuttings on the cutting structure may reduce or prevent the penetration of the drill bit into the formation. In addition, the fluid removes formation cuttings from the bottom of the hole. Failure to remove formation materials from the bottom of the hole may result in subsequent passes by cutting structure to essentially re-cut the same materials, thereby reducing the effective cutting rate and potentially increasing wear on the cutting surfaces of the cutter elements. The drilling fluid flushes the cuttings removed from the bit face and from the bottom of the hole radially outward and then up the annulus between the drill string and the borehole sidewall to the surface. Still further, the drilling fluid removes heat, caused by contact with the formation, from the cutter elements to prolong cutter element life. Thus, the positioning of the drilling fluid nozzles in the drill bit and the resulting flow of drilling fluid from the nozzles may significantly impact the performance of the drill bit. 
     BRIEF SUMMARY OF THE DISCLOSURE 
     Embodiments of drill bits for drilling in earthen formations are disclosed herein. In one embodiment, the drill bit has an uphole end and a downhole end. In addition, the drill bit comprises a bit body having a bit face disposed at the downhole end. Further, the drill bit comprises an internal plenum extending from the uphole end into the bit body. Still further, the drill bit comprises a first flow passage extending from the internal plenum to the bit face. Moreover, the drill bit comprises a nozzle assembly secured to the bit body at a downhole end of the flow passage. The nozzle is configured to distribute drilling fluid about the bit face. The nozzle assembly has a central axis and comprises an outer sleeve and an inner nozzle extending axially through the outer sleeve. The inner nozzle has a first end, a second end opposite the first end, a radially outer surface extending axially from the first end to the second end, and a radially inner surface extending axially from the first end to the second end. The radially inner surface defines a second flow passage extending axially from the first end to the second end. The second flow passage has an inlet at the first end and an outlet at the second end. The inner nozzle comprises a choke disposed along the second flow passage and a side outlet extending radially from the outer surface to the inner surface. The side outlet extends axially from the outlet. The side outlet extends axially across at least a portion of the choke. 
     Embodiment of nozzle assemblies for distributing drilling fluid from a drill bit are disclosed herein. In one embodiment, the nozzle assembly has a central axis and comprises a sleeve having a first end, a second end, a radially outer surface extending axially from the first end to the second end, and a radially inner surface extending axially from the first end to the second end. The radially inner surface defines a throughbore extending axially through the sleeve. In addition, the nozzle assembly comprises a nozzle disposed in the throughbore of the sleeve. The nozzle has a first end proximal the first end of the outer sleeve, a second end opposite the first end of the nozzle, a radially outer surface extending axially from the first end of the nozzle to the second end of the nozzle, and a radially inner surface extending axially from the first end of the nozzle to the second end of the nozzle. The radially inner surface of the nozzle defines a flow passage extending axially through the nozzle. The flow passage has an inlet at the first end of the nozzle and an outlet at the second end of the nozzle. The flow passage includes a choke. The nozzle also includes a side outlet extending radially from the outer surface of the nozzle to the inner surface of the nozzle. The side outlet extends axially from the second end and is contiguous with the outlet. The choke at least partially overlaps with the side outlet and is configured to direct at least a portion of the drilling fluid flowing through the flow passage toward the side outlet. 
     Embodiment of nozzles for distributing drilling fluid from a drill bit for distributing drilling fluid from a drill bit are disclosed herein. In one embodiment, the nozzle has a central axis and comprises a first end, a second end opposite the first end, a radially outer surface extending axially from the first end to the second end, and a radially inner surface extending axially from the first end to the second end. The radially inner surface defines a flow passage extending through the nozzle from the first end to the second end. The flow passage has an inlet at the first end and an outlet at the second end. The flow passage includes a section extending from the outlet. In addition, the nozzle comprises a side outlet extending radially from the outer surface to the inner surface. The side outlet extends axially from the second end and is contiguous with the outlet. The section of the flow passage at least partially overlaps with the side outlet. A tangent to the central axis of the flow passage in the section is oriented at an acute angle σ relative to the central axis of the nozzle. The section of the flow passage is configured to direct at least a portion of the drilling fluid flowing through the flow passage toward the side outlet. 
     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 the features and technical advantages of the invention in order that the detailed description of the invention 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 the same purposes of the invention. 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 invention as set forth in the appended claims. 
    
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
       For a detailed description of the preferred embodiments of the invention, reference will now be made to the accompanying drawings in which: 
         FIG. 1  is a schematic view of a drilling system including an embodiment of a drill bit in accordance with the principles described herein; 
         FIG. 2  is a perspective view of the drill bit of  FIG. 1 ; 
         FIG. 3  is a side view of the drill bit of  FIG. 2 ; 
         FIG. 4  is an end view of the drill bit of  FIG. 2 ; 
         FIG. 5  is a cross-sectional view of the drill bit of  FIG. 2  taken in reference plane  5 - 5  of  FIG. 4 ; 
         FIG. 6  is a partial cross-sectional schematic view of the bit shown in  FIG. 2  with the blades and the cutting faces of the cutter elements rotated into a single composite profile; 
         FIG. 7  is a perspective view of one of the drilling fluid nozzle assemblies of  FIG. 2 ; 
         FIG. 8  is a side view of the drilling fluid nozzle assembly of  FIG. 7 ; 
         FIG. 9  is an end view of the of the drilling fluid nozzle assembly of  FIG. 7 ; 
         FIG. 10  is a cross-sectional view of the drilling fluid nozzle assembly of  FIG. 7  taken in reference plane  10 - 10  of  FIG. 9 ; 
         FIG. 11  is a cross-sectional view of the drilling fluid nozzle assembly of  FIG. 7  taken in reference plane  11 - 11  of  FIG. 9 ; 
         FIG. 12  is a partial cross-sectional view of the drill bit of  FIG. 2  illustrating one nozzle assembly seated in the bit body and extending from the bit face; 
         FIG. 13  is perspective view of an embodiment of a nozzle in accordance with the principles described herein; 
         FIG. 14  is an end view of the nozzle of  FIG. 13 ; 
         FIG. 15  is a cross-sectional view of the nozzle of  FIG. 13  taken in reference plane  15 - 15  of  FIG. 12 ; 
         FIG. 16  is a perspective view of an embodiment of a nozzle in accordance with the principles described herein; 
         FIG. 17  is an end view of the nozzle of  FIG. 16 ; 
         FIG. 18  is a cross-sectional view of the nozzle of  FIG. 16  taken in reference plane  18 - 18  of  FIG. 17 ; and 
         FIG. 19  is a cross-sectional view of the nozzle of  FIG. 16  taken in reference plane  19 - 19  of  FIG. 17 . 
     
    
    
     DETAILED DESCRIPTION OF SOME OF THE PREFERRED EMBODIMENTS 
     The following discussion is directed to various embodiments of the invention. Although one or more of these embodiments may be preferred, the embodiments disclosed should not be interpreted, or otherwise used, as limiting the scope of the disclosure, including the claims. In addition, one skilled in the art will understand that the following description has broad application, and the discussion of any embodiment is meant only to be exemplary of that embodiment, and not intended to intimate 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. 
     Without regard to the type of bit, the cost of drilling a borehole for recovery of hydrocarbons may be very high, and is proportional to the length of time it takes to drill to the desired depth and location. The time required to drill the well, in turn, is greatly affected by the number of times the drill bit must be changed before reaching the targeted formation. This is the case because each time the bit is changed, the entire string of drill pipe, which may be miles long, must be retrieved from the borehole, section by section. Once the drill string has been retrieved and the new bit installed, the bit must be lowered to the bottom of the borehole on the drill string, which again must be constructed section by section. This process, known as a “trip” of the drill string, requires considerable time, effort and expense. Accordingly, it is desirable to employ drill bits which will drill faster and longer. 
     The length of time that a drill bit may be employed before it must be changed depends upon a variety of factors. These factors include the bit&#39;s rate of penetration (“ROP”), as well as its durability or ability to maintain a high or acceptable ROP. One factor that significantly affects bit ROP and durability is the bit hydraulics—the design and layout of the nozzles in the bit face that direct the flow and direction drilling fluid as it exits the bit body. For example, when formation cuttings adhere to the bit between the cutting elements, they can undesirably limit the penetration of the individual cutting elements into the formation, thereby reducing the amount of formation material removed by the cutter elements and associated reduction in rate of penetration (ROP). In addition, formation cuttings packed on the bit may restrict or limit the flow of drilling fluid to the cutter elements, which may promote premature bit wear. In general, having sufficient fluid directed toward the cutter elements can help to clean and cool the cutter elements, allowing them to penetrate to a greater depth and maintain the rate of penetration for the bit. Thus, cuttings must be removed efficiently during drilling to maintain reasonable penetration rates. 
     Referring now to  FIG. 1 , a schematic view of an embodiment of a drilling system  10  in accordance with the principles described herein is shown. Drilling system  10  includes a derrick  11  having a floor  12  supporting a rotary table  14  and a drilling assembly  90  for drilling a borehole  26  from derrick  11 . Rotary table  14  is rotated by a prime mover such as an electric motor (not shown) at a desired rotational speed and controlled by a motor controller (not shown). In other embodiments, the rotary table (e.g., rotary table  14 ) may be augmented or replaced by a top drive suspended in the derrick (e.g., derrick  11 ) and connected to the drillstring (e.g., drillstring  20 ). 
     Drilling assembly  90  includes a drillstring  20  and a drill bit  100  coupled to the lower end of drillstring  20 . Drillstring  20  is made of a plurality of pipe joints  22  connected end-to-end, and extends downward from the rotary table  14  through a pressure control device  15 , such as a blowout preventer (BOP), into the borehole  26 . The pressure control device  15  is commonly hydraulically powered and may contain sensors for detecting certain operating parameters and controlling the actuation of the pressure control device  15 . Drill bit  100  is rotated with weight-on-bit (WOB) applied to drill the borehole  26  through the earthen formation. Drillstring  20  is coupled to a drawworks  30  via a kelly joint  21 , swivel  28 , and line  29  through a pulley. During drilling operations, drawworks  30  is operated to control the WOB, which impacts the rate-of-penetration of drill bit  100  through the formation. In this embodiment, drill bit  100  can be rotated from the surface by drillstring  20  via rotary table  14  and/or a top drive, rotated by downhole mud motor  55  disposed along drillstring  20  proximal bit  100 , or combinations thereof (e.g., rotated by both rotary table  14  via drillstring  20  and mud motor  55 , rotated by a top drive and the mud motor  55 , etc.). For example, rotation via downhole motor  55  may be employed to supplement the rotational power of rotary table  14 , if required, and/or to effect changes in the drilling process. In either case, the rate-of-penetration (ROP) of the drill bit  100  into the borehole  26  for a given formation and a drilling assembly largely depends upon the WOB and the rotational speed of bit  100 . 
     During drilling operations a suitable drilling fluid  31  is pumped under pressure from a mud tank  32  through the drillstring  20  by a mud pump  34 . Drilling fluid  31  passes from the mud pump  34  into the drillstring  20  via a desurger  36 , fluid line  38 , and the kelly joint  21 . The drilling fluid  31  pumped down drillstring  20  flows through mud motor  55  and is discharged at the borehole bottom through nozzles in face of drill bit  100 , circulates to the surface through an annular space  27  radially positioned between drillstring  20  and the sidewall of borehole  26 , and then returns to mud tank  32  via a solids control system  36  and a return line  35 . Solids control system  36  may include any suitable solids control equipment known in the art including, without limitation, shale shakers, centrifuges, and automated chemical additive systems. Control system  36  may include sensors and automated controls for monitoring and controlling, respectively, various operating parameters such as centrifuge rpm. It should be appreciated that much of the surface equipment for handling the drilling fluid is application specific and may vary on a case-by-case basis. 
     Referring now to  FIGS. 2-4 , drill bit  100  is a fixed cutter bit, sometimes referred to as a drag bit, and is designed for drilling through formations of rock to form a borehole. Bit  100  has a central or longitudinal axis  105 , a first or uphole end  100   a , and a second or downhole end  100   b . Bit  100  rotates about axis  105  in the cutting direction represented by arrow  106 . In addition, bit  100  includes a bit body  110  extending axially from downhole end  100   b , a threaded connection or pin  120  extending axially from uphole end  100   a , and a shank  130  extending axially between pin  120  and body  110 . Pin  120  couples bit  100  to a drill string (not shown), which is employed to rotate the bit in order to drill the borehole. Bit body  110 , shank  130 , and pin  120  are coaxially aligned with axis  105 , and thus, each has a central axis coincident with axis  105 . 
     The portion of bit body  110  that faces the formation at downhole end  100   b  includes a bit face  111  provided with a cutting structure  140 . Cutting structure  140  includes a plurality of blades which extend from bit face  111 . As best shown in  FIGS. 2 and 4 , in this embodiment, cutting structure  140  includes three angularly spaced-apart primary blades  141 , and three angularly spaced apart secondary blades  142 . Further, in this embodiment, the plurality of blades (e.g., primary blades  141 , and secondary blades  142 ) are uniformly angularly spaced on bit face  111  about bit axis  105 . In particular, the three primary blades  141  are uniformly angularly spaced about 120° apart, the three secondary blades  142  are uniformly angularly spaced about 120° apart, and each primary blade  141  is angularly spaced about 60° from each circumferentially adjacent secondary blade  142 . In other embodiments, one or more of the blades may be spaced non-uniformly about bit face  111 . Still further, in this embodiment, the primary blades  141  and secondary blades  142  are circumferentially arranged in an alternating fashion. In other words, one secondary blade  142  is disposed between each pair of circumferentially-adjacent primary blades  141 . Although bit  100  is shown as having three primary blades  141  and three secondary blades  142 , in general, bit  100  may comprise any suitable number of primary and secondary blades. As one example only, bit  100  may comprise two primary blades and four secondary blades. 
     In this embodiment, primary blades  141  and secondary blades  142  are integrally formed as part of, and extend from, bit body  110  and bit face  111 . Primary blades  141  and secondary blades  142  extend generally radially along bit face  111  and then axially along a portion of the periphery of bit  100 . In particular, primary blades  141  extend radially from proximal central axis  105  toward the periphery of bit body  110 . Primary blades  141  and secondary blades  142  are separated by drilling fluid flow courses  143 . Each blade  141 ,  142  has a leading edge or side  141   a ,  142   a , respectively, and a trailing edge or side  141   b ,  142   b , respectively, relative to the direction of rotation  106  of bit  100 . 
     Referring still to  FIGS. 2-4 , each blade  141 ,  142  includes a cutter-supporting surface  144  for mounting a plurality of cutter elements  145 . In particular, cutter elements  145  are arranged adjacent one another in a radially extending row proximal the leading edge of each primary blade  141  and each secondary blade  142 . In this embodiment, each primary blade  141  also includes a plurality of cutter elements  145  are arranged adjacent one another in a radially extending second row that trails the first row on the same primary blade  142  relative to the direction of bit rotation  106 . 
     Each cutter element  145  has a cutting face  146  and comprises an elongated and generally cylindrical support member or substrate which is received and secured in a pocket formed in the surface of the blade to which it is fixed. In general, each cutter element may have any suitable size and geometry. In this embodiment, each cutter element  145  has substantially the same size and geometry. Cutting face  146  of each cutter element  145  comprises a disk or tablet-shaped, hard cutting layer of polycrystalline diamond or other superabrasive material is bonded to the exposed end of the support member. In the embodiments described herein, each cutter element  145  is mounted such that its cutting face  146  is generally forward-facing. As used herein, “forward-facing” is used to describe the orientation of a surface that is substantially perpendicular to, or at an acute angle relative to, the cutting direction of the bit (e.g., cutting direction  106  of bit  100 ). For instance, a forward-facing cutting face (e.g., cutting face  146 ) may be oriented perpendicular to the direction of rotation  106  of bit  100 , may include a backrake angle, and/or may include a siderake angle. However, the cutting faces are preferably oriented perpendicular to the direction of rotation  106  of bit  100  plus or minus a 45° backrake angle and plus or minus a 45° siderake angle. In addition, each cutting face  146  includes a cutting edge adapted to positively engage, penetrate, and remove formation material with a shearing action, as opposed to the grinding action utilized by impregnated bits to remove formation material. Such cutting edge may be chamfered or beveled as desired. In this embodiment, cutting faces  146  are substantially planar, but may be convex or concave in other embodiments. 
     Referring still to  FIGS. 2-4 , bit body  110  further includes gage pads  147  of substantially equal axial length measured generally parallel to bit axis  105 . Gage pads  147  are circumferentially-spaced about the radially outer surface of bit body  110 . Specifically, one gage pad  147  intersects and extends from each blade  141 ,  142 . In this embodiment, gage pads  147  are integrally formed as part of the bit body  110 . In general, gage pads  147  can help maintain the size of the borehole by a rubbing action when cutter elements  145  wear slightly under gage. Gage pads  147  also help stabilize bit  100  against vibration. 
     Referring now to  FIG. 6 , an exemplary profile of bit body  110  is shown as it would appear with blades  141 ,  142  and cutter elements  145  rotated into a single rotated profile. In rotated profile view, blades  141 ,  142  of bit body  110  form a combined or composite blade profile  148  generally defined by cutter-supporting surfaces  144  of blades  141 ,  142 . Composite blade profile  148  and bit face  111  may generally be divided into three regions conventionally labeled cone region  149   a , shoulder region  149   b , and gage region  149   c . Cone region  149   a  comprises the radially innermost region of bit body  110  and composite blade profile  148  extending from bit axis  105  to shoulder region  149   b . In this embodiment, cone region  149   a  is generally concave. Adjacent cone region  149   a  is generally convex shoulder region  149   b . The transition between cone region  149   a  and shoulder region  149   b , typically referred to as the nose  149   d , occurs at the axially outermost portion of composite blade profile  148  where a tangent line to the blade profile  148  has a slope of zero. Moving radially outward, adjacent shoulder region  149   b  is the gage region  149   c  which extends substantially parallel to bit axis  105  at the outer radial periphery of composite blade profile  148 . As shown in composite blade profile  148 , gage pads  147  define the gage region  149   c  and the outer radius R 110  of bit body  110 . Outer radius R 110  extends to and therefore defines the full gage diameter of bit body  110 . 
     Referring briefly to  FIG. 4 , moving radially outward from bit axis  105 , bit face  111  includes cone region  149   a , shoulder region  149   b , and gage region  149   c  as previously described. Primary blades  141  extend radially along bit face  111  from within cone region  149   a  proximal bit axis  105  toward gage region  149   c  and outer radius R 110 . Secondary blades  142  extend radially along bit face  111  from proximal nose  149   d  toward gage region  149   c  and outer radius R 110 . Thus, in this embodiment, each primary blade  141  and each secondary blade  142  extends substantially to gage region  149   c  and outer radius R 110 . In this embodiment, secondary blades  142  do not extend into cone region  149   a , and thus, secondary blades  142  occupy no space on bit face  111  within cone region  149   a . Although a specific embodiment of bit body  110  has been shown in described, one skilled in the art will appreciate that numerous variations in the size, orientation, and locations of the blades (e.g., primary blades  141 , secondary blades,  142 , etc.), and cutter elements (e.g., cutter elements  145 ) are possible. 
     Referring now to  FIG. 5 , bit  100  includes an internal plenum  104  extending axially from uphole end  100   a  through pin  120  and shank  130  into bit body  110 . Plenum  104  permits drilling fluid to flow from the drill string into bit  100 . Body  110  is also provided with a plurality of flow passages  107  extending from plenum  104  to downhole end  100   b . As best shown in  FIGS. 4 and 5 , a plurality of circumferentially-spaced radially inner nozzles  108  and a plurality of circumferentially-spaced radially outer nozzle assemblies  200  are seated in the lower ends of flow passages  107 ; one nozzle  108  or nozzle assembly  200  is disposed at the downhole end of each flow passage  107 . Together, passages  107 , nozzles  108 , and nozzle assemblies  200  serve to distribute drilling fluid around cutting structure  140  to flush away formation cuttings and to remove heat from cutting structure  140 , and more particularly cutting elements  145 , during drilling. 
     As previously described, bit  100  includes a plurality of circumferentially-spaced inner nozzles  108  and a plurality of circumferentially-spaced outer nozzle assemblies  200 . In general, nozzles  108  and nozzle assemblies  200  can be positioned at any suitable location and at any suitable orientation. As best shown in  FIGS. 4 and 5 , in this embodiment, nozzles  108  are positioned proximal bit axis  105  radially inside nozzle assemblies  200 . In particular, each nozzle  108  is positioned in a flow course  143  within the cone region  149   a , circumferentially positioned between a circumferentially-adjacent pair of primary blades  141 , and radially positioned between the radially inner end of the corresponding secondary blade  142  and bit axis  105 . Whereas each nozzle assembly  200  is positioned in a flow course  143  within the shoulder region  149   b  (proximal the nose  149   d ), circumferentially positioned between one secondary blade  142  and a circumferentially adjacent primary blade  141  that leads the secondary blade  142 , and positioned at about the same radial position as the radially inner end of the corresponding secondary blade  142 . In addition, in this embodiment, nozzle assemblies  200  are positioned and oriented to direct drilling fluid toward the cutter elements  145  in the shoulder region  149   b  disposed along the leading sides  142   a  of the immediately trailing secondary blades  142 . In other embodiments, the nozzle assemblies  200  can be positioned and oriented to direct drilling fluid toward other cutter elements  145  such as, for example, cutter elements  145  in the shoulder region  149   b  disposed along the leading sides  141   a  of the primary blades  141 . However, embodiments of nozzle assemblies  200  offer the potential to advantageously enhance the distribution of drilling fluid therefrom and the shear stress applied to the cutting faces  146  of cutter elements  145  as compared to most conventional nozzles. Since the cutter elements disposed along the shoulder region (e.g., cutter elements  145  disposed along shoulder region  149   b ) typically experience the most thermal stress (as compared to cutter elements disposed along the cone and gage regions), nozzle assemblies  200  may provide particularly beneficial results if positioned and oriented to direct drilling fluid toward such cutter elements disposed along the shoulder region of the bit. 
     Referring now to  FIGS. 7-11 , one nozzle assembly  200  is shown. In this embodiment, each nozzle assembly  200  is the same, and thus, only one nozzle assembly  200  will be described, it being understood the other nozzle assemblies  200  are identical. Nozzle assembly  200  has a central axis  205 , a first or uphole end  200   a , and a second or downhole end  200   b  opposite end  200   a . In addition, nozzle assembly  200  includes an outer sleeve  210  and an inner nozzle  230  disposed within and extending through sleeve  210 . Sleeve  210  and nozzle  230  are coaxially aligned, each having a central or longitudinal axis coincident with axis  205 . 
     Outer sleeve  210  has a first or uphole end  210   a  proximal end  200   a , a second or downhole end  210   b  distal end  200   a , a radially outer surface  211  extending axially between ends  210   a ,  210   b , and a radially inner surface  216  extending axially between ends  210   a ,  210   b . In this embodiment, each end  210   a ,  210   b  comprises an annular planar surface disposed in a plane oriented perpendicular to axis  205 . Outer surface  211  includes external threads  212  extending axially from first end  210   a  and a cylindrical surface  213  extending axially from threads  212  to second end  210   b . As will be described in more detail below, threads  212  removably secure nozzle assembly  200  to bit body  110 . As best shown in  FIG. 10 , inner surface  216  is a cylindrical surface disposed at an inner radius R 216  measured radially from axis  205 . In addition, inner surface  216  defines a passage or throughbore  217  extending axially through sleeve  210  from first end  210   a  to second end  210   b . Nozzle  230  extends through passage  217 . 
     Referring still to  FIGS. 7-11 , nozzle  230  has a first or uphole end  230   a  coincident with and defining end  200   a  of assembly  200 , a second or downhole end  230   b  coincident with and defining end  200   b  of assembly  200 , a radially outer surface  231  extending axially between ends  230   a ,  230   b , and a radially inner surface  236  extending axially between ends  230   a ,  230   b . In this embodiment, each end  230   a ,  230   b  comprises an annular planar surface disposed in a plane oriented perpendicular to axis  205 . As best shown in  FIGS. 10 and 11 , outer surface  231  includes a cylindrical surface  231   a  extending axially from first end  230   a , a cylindrical surface  231   b  extending axially from second end  230   b , and an annular planar shoulder  231   c  extending radially between cylindrical surfaces  231   a ,  231   b . In this embodiment, an annular bevel or chamfer is provided between cylindrical surface  231   a  and first end  230   a , and an annular bevel or chamfer is provided between cylindrical surface  231   b  and second end  230   b . Cylindrical surface  231   a  is disposed at an outer radius R 231a  measured radially from axis  205 , and cylindrical surface  231   b  is disposed at an outer radius R 231b  measured radially from axis  205 . Radius R 231a  is greater than radius R 231b , and thus, shoulder  231   c  extends radially inward from surface  231   a  to surface  231   b.    
     Referring specifically to  FIGS. 10 and 11 , inner surface  236  defines a throughbore or passage  237  extending axially through nozzle  230  from first end  230   a  to second end  230   b . During drilling operations, drilling fluid enters passage  237  at end  230   a  and exits nozzle  230  at end  230   b . Accordingly, passage  237  includes or defines a drilling fluid inlet  237   a  at first end  230   a  and a drilling fluid outlet  237   b  at second end  230   b.    
     A choke  239  is provided along passage  237 . Choke  239  has a first or uphole end  239   a  and a second or downhole end  239   b . In this embodiment, choke  239  is axially positioned (relative to axis  205 ) at or proximal outlet  237   b  and second end  230   b . However, as will be described in more detail below, in other embodiments, the axial position of the choke (e.g., choke  239 ) along the nozzle passage (e.g., passage  237 ) can vary. 
     As best shown in  FIG. 10 , in this embodiment, choke  239  is formed or defined by inner surface  236 . In particular, inner surface  236  is disposed at an inner radius R 236  measured radially from axis  205 . Moving axially from first end  230   a  to second end  230   b  of nozzle  230 , radius R 236  decreases along inlet  237   a , is constant between inlet  237   a  and choke  239  (i.e., inner surface  236  is a cylindrical surface between inlet  237   a  and choke  239 ), and decreases along choke  239  (i.e., decreases between uphole end  239   a  and downhole end  239   b ). Consequently, in this embodiment, the cross-sectional area of passage  237  taken in a plane oriented perpendicular to axis  205  generally decreases moving axially along inlet  237   a , is constant between inlet  237   a  and choke  239 , and decreases along choke  239 . Thus, the radius R 237  and cross-sectional area of passage  237  taken in a plane oriented perpendicular to axis  205  is a minimum at the downstream end  239   b  of choke  239 . The decreasing radius R 236  and cross-sectional area at inlet  237   a  accelerates drilling fluid as it enters nozzle  230 , and the decreasing radius R 236  and cross-sectional area at choke  239  chokes the flow of drilling fluid. In this embodiment, inner surface  236  includes a frustoconical surface  239   c  proximal end  230   b  that defines choke  239 . Surface  239   a  is disposed at an acute angle α measured downward from axis  205 . In embodiments described herein, angle α is preferably between 0° and 30°, and more preferably between 0° and 20°. In this embodiment, angle α is 15°. 
     Referring still to  FIGS. 10 and 11 , sleeve  210  is disposed about nozzle  230  with end  210   a  of sleeve  210  axially abutting shoulder  231   c  of nozzle  230  and cylindrical inner surface  216  of sleeve  210  slidingly engaging mating cylindrical surface  231   b  of nozzle  230 . Thus, inner radius R 216  is substantially the same or slightly greater than outer radius R 231b . In addition, with end  210   a  engaging shoulder  231   c , nozzle  230  extends axially (relative to axis  205 ) from sleeve  210 . More specifically, nozzle  230  extends from sleeve  210  a length L 210b-230b  measured axially (relative to axis  205 ) from end  210   b  to end  230   b . In general, the length L 210b-230b  can vary from bit to bit depending on a variety of factors, however, for most applications, the length L 210b-230b  is preferably between 0.2 in. and 2.0 in., and more preferably between 0.5 in. and 1.0 in. 
     Referring again to  FIGS. 7-10 , in embodiments described herein, nozzle  230  also includes a side outlet or port  240  extending axially from end  230   b  and extending radially through nozzle  230  from inner surface  236  to outer surface  231 . Side port  240  is contiguous with and extends axially from outlet  237   b  at end  230   b . Thus, side port  240  is in fluid communication with passage  237  and outlet  237   b . As best shown in  FIG. 8 , side port  240  has a central or longitudinal axis  245  in side view, a first or uphole end  240   a , and a second or downhole end  240   b  at end  230   b . In this embodiment, uphole end  240   a  is axially positioned between end  210   b  of sleeve  210  and end  230   b  of nozzle  230 , and more particularly, uphole end  240   a  is axially positioned between second end  210   b  of sleeve  210  and choke  239 . In other words, side port  240  extends axially from end  230   b  beyond choke  239 , but does not extend to sleeve  210 . In particular, as best shown in  FIG. 10 , uphole end  240   a  of side port  240  is spaced an axial length L 210b-240a  measured axially (relative to axes  205 ,  245 ) in side view from downhole end  210   b  of sleeve  210  to uphold end  240   a  of side port  240 . In general, the length L 210b-240a  can vary from bit to bit depending on a variety of factors, however, for most applications, the length L 210b-240a  is preferably at least 0.1 in., and more preferably at least 0.3 in. Drilling fluid flowing through passage  237  exits nozzle  230  simultaneously through outlet  237   b  and side port  240 . Side port  240  is preferably spaced from sleeve  210  by length L 210b-240a  to reduce and/or eliminate erosion of sleeve  210  and bit body  110  by the drilling fluid exiting side port  240 . 
     Choke  239  directs and facilitates the flow of at least some of the drilling fluid in passage  237  radially outward through side port  240 . In particular, in embodiments described herein, the axial positon of choke  239  along passage  237  preferably at least partially overlaps with side port  240  such that the restriction of drilling fluid flow induced by choke  239  forces a portion of drilling fluid flowing through passage  237  to flow radially outward and exit through side port  240 . In other words, side outlet  240  intersects and extends axially across at least a portion of the choke  239  such that at least a portion of choke  239  is positioned along side outlet  240 . In this embodiment, the entire choke  239  is axially positioned between ends  240   a ,  240   b  of side outlet  240  (i.e., both ends  239   a ,  239   b  are axially positioned between ends  240   a ,  240   b ). However, in other embodiments, only one end of the choke is axially positioned between the ends of the side outlet. For example, in one embodiment, uphole end  239   a  of choke  239  is axially spaced from side outlet  240  (e.g., above both ends  240   a ,  240   b  of side outlet  240 ) and downhole end  239   b  of choke is axially positioned along side outlet  240  (i.e., between ends  240   a ,  240   b  of side outlet  240 ). Referring now to  FIGS. 7 and 8 , in this embodiment, side port  240  is generally U-shaped. In particular, side port  240  is defined by a pair of circumferentially-spaced parallel side edges or walls  241  and a smoothly curved concave end edge or wall  242  extending between walls  241 . Side walls  241  extend radially through nozzle  230  from outer surface  231  to inner surface  236 , and extend axially from ends  230   b ,  240   b . End wall  242  extend radially through nozzle  230  from outer surface  231  to inner surface  236  and defines uphole end  240   a . Although side port  240  has a U-shaped geometry with parallel side walls  241  in this embodiment, in other embodiments, the side port (e.g., side port  240 ) can have other geometries such as V-shaped, U-shaped with non-parallel side walls, etc. As best shown in  FIG. 9 , side port  240  extends circumferentially through an angle β measured about axis  205  between side walls  241  at downhole ends  230   b ,  240   b . In embodiments described herein, angle β is preferably less than or equal to 180°, and more preferably about 90°. In this embodiment, angle β is 90°. 
     As best shown in  FIGS. 5 and 12 , a counterbore or receptacle  109  is provided in bit face  111  at the downhole end of each flow passage  107 . Each receptacle  109  includes an annular planar shoulder  109   a  and internal threads  109   b . Shoulder  109   a  is disposed at the intersection of the receptacle  109  and corresponding passage  107 . Receptacles  109  are sized to mate with nozzle assemblies  200 . In particular, each nozzle assembly  200  is secured to bit body  110  by positioning nozzle  230  within sleeve  210 , urging sleeve  210  against shoulder  231   c , and inserting ends  210   a ,  230   a  into receptacle  109 . Next, sleeve  210  is threaded into receptacle  109  via engagement of mating threads  212 ,  109   b  until uphole ends  200   a ,  230   a  axially abuts and is seated against shoulder  109   a . Sleeve  210  may be tightened to squeeze nozzle  230  against shoulder  109   a . In this embodiment, a plurality of circumferentially-spaced notches  218  are provided at end  210   b  for positively engaging sleeve  210  with a tool for threading sleeve  210  into receptacle  109 . Although sleeve  210  is threadably coupled to bit body  110  in this embodiment, in other embodiments, the sleeve (e.g., sleeve  210 ) can be coupled to the bit body (e.g., bit body  110 ) by other suitable means such as welding, a snap ring, etc. 
     As previously described, during drilling operations, drilling fluid flows through passages  107  to nozzle assemblies  200 , and then into nozzle  230  via inlet  237   a , through passage  237 , and out of nozzle  230  via outlets  237   b ,  240 . The restriction fluid flow through nozzle  230  at outlet  237  caused by choke  239  forces a portion of drilling fluid through side outlet  240 . Since side outlet  240  and outlet  237   b  are contiguous, the geometry of the drilling fluid exiting nozzle  230  is generally fan-shaped as opposed to cylindrical as is typical of most conventional nozzle. Accordingly, drilling fluid exiting nozzle  230  can cover a greater surface area of bit  100  as compared to a similarly sized and positioned conventional nozzle. In addition, drilling fluid exiting outlet  237   b  can be directed to the bottom of the borehole while drilling fluid exiting side outlet  240  can be directed to specific cutter elements  245 . In this embodiment, nozzle assemblies  200  are positioned and oriented in bit body  210  to direct drilling fluid exiting side outlets  240  toward cutter elements  245  disposed along shoulder region  149   b , which typically experience the greatest thermal stresses. 
     In the embodiment of nozzle assembly  200  described above and shown in  FIGS. 7-11 , one side outlet  240  is provided in nozzle  230 . However, in other embodiments, more than one side outlet or port is provided. For example, referring now to  FIGS. 13-15 , another embodiment of a nozzle  330  that can be used in the place of nozzle  230  previously described is shown. Nozzle  330  is substantially the same as nozzle  230  previously described with the exception that nozzle  330  includes a plurality of side outlets or ports  240 . Each port  240  is as previously described with respect to nozzle  230 . 
     In this embodiment, two circumferentially-spaced ports  240  are provided. More specifically, as best shown in  FIG. 14 , ports  240  are angularly spaced apart (relative to the central axis of nozzle  330 ) an angle θ measured between the central axes  245  of ports  240 . In general, the minimum angle θ between any pair of circumferentially adjacent side ports  240  can be any suitable angle less than or equal to 180°. In this embodiment, angle θ is 180°. 
     Nozzle  330  is secured to a bit body (e.g., bit body  110 ) using sleeve  210  in the manner previously described with respect to nozzle assembly  200 . In general, nozzle  330  can be positioned and oriented such that side ports  240  direct drilling fluid toward the desired surfaces of the bit face. 
     In the embodiment of nozzle assembly  200  described above and shown in  FIGS. 7-11 , a choke  239  is provided along passage  237  to urge at least a portion of the drilling fluid therein to flow radially outward through side outlet  240 . However, in other embodiments, features or structures other than chokes can be provided to achieve similar functionality. For example, referring now to  FIGS. 16-19 , another embodiment of a nozzle  430  that can be used in the place of nozzle  230  previously described is shown. Nozzle  430  is substantially the same as nozzle  230  previously described with the exception that nozzle  430  includes a flow diverter instead of a choke to direct at least a portion of the drilling fluid therein to flow radially outward through a side outlet. 
     Referring still to  FIGS. 16-19 , nozzle  430  has a central or longitudinal axis  435 , a first or uphole end  430   a , a second or downhole end  430   b , a radially outer surface  431  extending axially between ends  430   a ,  430   b , and a radially inner surface  436  extending axially between ends  430   a ,  430   b . Outer surface  431  is the same as outer surface  231  of nozzle  230  previously described. Inner surface  436  defines a through passage  437  extending through nozzle  430  from first end  430   a  to second end  430   b . During drilling operations, drilling fluid enters passage  437  at end  430   a  and exits nozzle  430  at end  430   b . Accordingly, similar to passage  237  previously described, passage  437  defines a drilling fluid inlet  437   a  at end  430   a  and a drilling fluid outlet  437   b  at end  430   b.    
     A side outlet or port  440  extends axially from end  430   b  and extends radially through nozzle  430  from outer surface  431  to inner surface  436 . Side port  440  is contiguous with and extends axially from end  430   b  and outlet  437   b . Thus, side port  440  is in fluid communication with passage  437  and outlet  437   b . Side outlet  440  has an uphole end  440   a  distal end  430   b  and a downhole end  440   b  at end  430   b . Side outlet  440  is substantially the same as side outlet  240  previously described with the exception that side outlet  440  is V-shaped instead of U-shaped. 
     Unlike passage  237 , in this embodiment, a choke is not provided along passage  437  for urging at least a portion of drilling fluid toward side outlet  440 , and further, passage  437  curves as it extends between ends  430   a ,  430   b . As best shown in  FIG. 18 , in a cross-section of nozzle  430  taken in a reference plane  18 - 18  that contains central axis  435  and bisects side port  440  in end view ( FIG. 17 ), passage  437  has a curved generally C-shaped central or longitudinal axis  439 ; axes  435 ,  439  are not coincident or parallel. Consequently, in this view, passage  437  includes a first section or portion  437   c  extending from inlet  437   a  and a second section or portion  437   d  extending from outlet  437   b  to first section  437   c . First section  437   c  generally curves in a direction away side outlet  440 , whereas second section  437   d  generally curves in a direction toward side outlet  440 . Thus, tangents to axis  439  in first section  437   c  are oriented at an acute angle β measured upward from axis  435 , whereas tangents to axis  439  in second section  437   d  are oriented at an acute angle σ measured downward from axis  435 . Passage  437  transitions from the first section  437   c  to second section  437   d  at an axial position disposed between ends  430   a ,  430   b  of nozzle  430 , and more specifically, between uphole end  430   a  and side outlet  440 . Since second section  437   d  curves toward side outlet  440  as it extends toward downhole end  430   b , drilling fluid flowing through passage  437  from inlet  437   a  toward outlet  437   b  is simultaneously directed to both outlets  437   b ,  440 —the drilling fluid flowing through section  437   d  has a velocity vector V that is tangent to axis  439 , and thus, includes a radial velocity component V r  directed toward side outlet  440  and an axial velocity component V a  directed toward outlet  437   b . It should also be appreciated that in the cross-section of nozzle  430  taken in a reference plane  18 - 18  ( FIG. 18 ), passage  437  has a width W 437  measured perpendicular to axis  435  that is generally uniform between inlet  437   a  and outlet  437   b.    
     Referring now to  FIG. 19 , in a cross-section of nozzle  430  taken in a reference plane  19 - 19  ( FIG. 17 ) that contains central axis  435  and is perpendicular to the reference plane  18 - 18  that contains central axis  435  and bisects side outlet  440 , central axis  439  of passage  437  is linear or straight and passage  437  has an hour-glass shape. More specifically, in this view, passage  437  has a width W 437 ′ measured perpendicular to axis  435  that decreases moving along first section  437   c  from end  430   a  to second section  437   d , and then increases moving along second section  437   d  from first section  437   c  to end  430   b . As previously described, the transition from section  437   c  to section  437   d  is axially positioned between side outlet  440  and uphole end  430   a . Consequently, the decreasing width W 437 ′ moving along first section  437   c  is uphole of side outlet  440  and does not function to direct drilling fluid toward side outlet  440  in a manner similar to choke  239  previously described, which axially overlaps with side outlet  240 . 
     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 invention. For example, the relative dimensions of various parts, the materials from which the various parts are made, and other parameters can be varied. 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.