Patent Publication Number: US-2023133889-A1

Title: Particle impact drill bits and associated methods

Description:
CROSS-REFERENCE TO RELATED APPLICATIONS 
     This application claims benefit of U.S. provisional patent application Ser. No. 63/273,553 filed Oct. 29, 2021, and entitled “Particle Impact Drill Bits and Associated Methods,” which is hereby incorporated herein by reference in its entirety for all purposes. 
    
    
     STATEMENT REGARDING FEDERALLY SPONSORED RESEARCH OR DEVELOPMENT 
     Not applicable. 
     BACKGROUND 
     In drilling a borehole into an earthen formation, such as for the recovery of hydrocarbons or minerals from a subsurface formation, it is typical practice to connect a drill bit onto the lower end of a drillstring formed from a plurality of pipe joints connected together end-to-end, and then rotate the drillstring so that the drill bit progresses downward into the earth to create a borehole along a predetermined trajectory. In vertical drilling operations, the drillstring and drill bit are typically rotated from the surface with a top dive or rotary table. Drilling fluid or “mud” is typically pumped under pressure down the drillstring, out the face of the drill bit into the borehole, and then up the annulus between the drillstring and the borehole sidewall to the surface. The drilling fluid, which may be water-based or oil-based, is typically viscous to enhance its ability to carry borehole cuttings to the surface. 
     SUMMARY 
     An embodiment of a particle impact drill bit for a well system comprises a central axis, a longitudinal first end, a longitudinal second end opposite the first end, and a feed passage extending into the drill bit from the first end, a pilot section located at the second end, the pilot section comprising one or more converging nozzles in fluid communication with the feed passage, and a reamer section located between the first end and the second end and comprising one or more reamer blades extending radially outwards from the central axis of the drill bit, and wherein the reamer section defines a maximum width of the drill bit. In some embodiments, the drill bit comprises a monolithically formed body which includes both the pilot section and the reamer section. In some embodiments, the drill bit comprises a connector located at the second end of the drill bit. In certain embodiments, at least one of the converging nozzles has a maximum length that is greater than a maximum width of the converging nozzle. In certain embodiments, at least one of the converging nozzles has a tapered central passage comprising a taper length which is greater than a maximum width of the converging nozzle. In some embodiments, the pilot section comprises a first body formed from a first material and the reamer section comprises a second body formed from a second material, and wherein the first material has a greater hardness than the second material. In some embodiments, the reamer section comprises a first reamer section and the one or more reamer blades comprises one or more first reamer blades, and wherein the drill bit further comprises a second reamer section located between the first reamer section and the second reamer section and comprising one or more second reamer blades extending radially outwards from the central axis of the drill bit. In some embodiments, the one or more nozzles of the pilot section comprise one or more first nozzles and the second reamer section comprises one or more second converging nozzles in fluid communication with the feed passage and axially spaced from the one or more first converging nozzles. In certain embodiments, at least one of the one or more first converging nozzles is oriented at an obtuse angle relative to at least one of the one or more second converging nozzles. In certain embodiments, the drill bit comprises a first lateral side and a second lateral side opposite the first lateral side, and wherein the one or more reamer blades of the reamer section are positioned only on the first lateral side of the drill bit. In some embodiments, the one or more nozzles of the pilot section comprise one or more first nozzles and the reamer section comprises one or more second converging nozzles in fluid communication with the feed passage and axially spaced from the one or more first converging nozzles. In some embodiments, the reamer section comprises a first reamer section and the one or more reamer blades comprises one or more first reamer blades, and wherein the drill bit further comprises a second reamer section located between the first reamer section and the second reamer section and comprising one or more second reamer blades extending radially outwards from the central axis of the drill bit. 
     An embodiment of a well system comprising a drilling rig, a drill string extending from the drilling rig into a borehole extending through a subterranean earthen formation, a surface pump configured to pump a drilling fluid through the drill string, wherein the drilling fluid comprises a plurality of solid impactors, and a particle impact drill bit coupled to an end of the drill string, wherein the drill bit comprises a pilot section comprising one or more converging nozzles each configured to emit a jet of the drilling fluid, and a reamer section comprising one or more reamer blades extending radially outwards from a central axis of the drill bit. In some embodiments, the pilot section of the drill bit comprises a first body formed from a first material and the reamer section comprises a second body formed from a second material, and wherein the first material has a greater hardness than the second material. In some embodiments, at least one of the converging nozzles of the drill bit has a tapered central passage comprising a taper length which is greater than a maximum width of the converging nozzle. In certain embodiments, the pilot section comprises a first body formed from a first material and the reamer section comprises a second body formed from a second material, and wherein the first material has a greater hardness than the second material. In certain embodiments, the reamer section of the drill bit comprises a first reamer section and the one or more reamer blades comprises one or more first reamer blades, and wherein the drill bit further comprises a second reamer section located between the first reamer section and the second reamer section and comprising one or more second reamer blades extending radially outwards from the central axis of the drill bit. In some embodiments, the one or more nozzles of the pilot section of the drill bit comprise one or more first nozzles and the second reamer section comprises one or more second converging nozzles axially spaced from the one or more first converging nozzles. In some embodiments, the one or more nozzles of the pilot section comprise one or more first nozzles and the reamer section comprises one or more second converging nozzles axially spaced from the one or more first converging nozzles. 
     An embodiment of a method for forming a borehole extending through a subterranean earthen formation comprises (a) pumping a drilling fluid comprising a plurality of solid impactors into a particle impact drill bit located within the borehole, (b) ejecting the drilling fluid as a jet from a converging nozzle of a pilot section of the drill bit whereby the jet impacts a terminal end of the borehole, and (c) expanding the borehole by a reamer section of the drill bit whereby the pilot section of the drill bit is spaced from the terminal end of the borehole as the jet impacts the terminal end of the borehole. In some embodiments, the method comprises (d) ejecting the drilling fluid as a jet from a converging nozzle of the reamer section of the drill bit whereby the jet impacts a sidewall of the borehole. In some embodiments, the reamer section comprises a first reamer section of the drill bit, and the method comprises (d) expanding the borehole by a second reamer section of the drill bit that is axially spaced from the first reamer section and which defines a maximum outer diameter of the drill bit. In certain embodiments, the method comprises (e) ejecting the drilling fluid as a jet from a converging nozzle of the second reamer section of the drill bit whereby the jet impacts a sidewall of the borehole. 
     An embodiment of a particle impact drill bit for a well system comprises a central axis, a longitudinal first end, a longitudinal second end opposite the first end, and a feed passage extending into the drill bit from the first end, one or more first converging nozzles in fluid communication with the feed passage, and one or more second converging nozzles in fluid communication with the feed passage and axially spaced from the one or more first converging nozzles, wherein at least one of the one or more first converging nozzles is oriented at an obtuse angle relative to at least one of the one or more second converging nozzles. 
    
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
       For a detailed description of exemplary embodiments of the disclosure, reference will now be made to the accompanying drawings in which: 
         FIG.  1    is a schematic partial cross-sectional view of a drilling system including an embodiment of a particle impact drill bit; 
         FIG.  2    is an enlarged schematic view of the particle impact drill bit of  FIG.  1   ; 
         FIG.  3    is a perspective view of another embodiment of a particle impact drill bit; 
         FIG.  4    is a bottom view of the particle impact drill bit of  FIG.  3   ; 
         FIG.  5    is a side-cross sectional view of the particle impact drill bit of  FIG.  3   ; 
         FIG.  6    is a side view of an embodiment of a fluid passage of the impact drill bit of  FIG.  3   ; 
         FIG.  7    is a side view of an embodiment of a nozzle assembly of the particle impact drill bit of  FIG.  3   ; 
         FIG.  8    is a side cross-sectional view of the nozzle assembly of  FIG.  7   ; 
         FIG.  9    is a side view of an embodiment of a nozzle; 
         FIG.  10    is a side cross-sectional view of the nozzle of  FIG.  9   ; 
         FIG.  11    is a perspective view of another embodiment of a particle impact drill bit; 
         FIG.  12    is a side view of the particle impact drill bit of  FIG.  11   ; 
         FIG.  13    is a bottom view of the particle impact drill bit of  FIG.  11   ; 
         FIG.  14    is a side-cross sectional view of the particle impact drill bit of  FIG.  11   ; 
         FIG.  15    is a partial perspective view of the particle impact drill bit of  FIG.  11   ; 
         FIG.  16    is a side cross-sectional view of another embodiment of a particle impact drill bit; 
         FIG.  17    is a partial perspective view of the particle impact drill bit of  FIG.  16   ; 
         FIG.  18    is a side cross-sectional view of another embodiment of a particle impact drill bit; 
         FIG.  19    is a partial perspective view of the particle impact drill bit of  FIG.  18   ; and 
         FIG.  20    is a flowchart of an embodiment of a method for forming a borehole extending through a subterranean earthen formation is shown. 
     
    
    
     DETAILED DESCRIPTION 
     The following discussion is directed to various exemplary 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 exemplary 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 the claims is 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. 
     As described above, well systems may be utilized for forming boreholes in earthen formations via a drill bit of the well system which cuts into the earthen formation to extend the borehole through the formation. Drill bits may include one or more cutting elements for mechanically cutting into the earthen formation. Alternatively, some drill bits, sometimes referred to as “particle flow” or “particle impact” drill bits fluidically rather than mechanically cut into the earthen formation by producing a jet of solid impactors directed against the earthen formation to thereby fracture and/or distress the earthen formation. The impactors may comprise hardened pellets or shot which are ejected from the particle impact drill bit at a high velocity against the earthen formation. 
     While particle impact drill bits may address some issues associated with conventional drill bits (e.g., wear of the cutting elements of the conventional drill bit), other challenges are presented by particle impact drill bits. For example, particle impact drill bits may produce an uneven a borehole having an uneven sidewall such that torsional and lateral stability typically provided to the drill bit by the sidewall is lost. Additionally, given that no weight-on-bit (WOB) is required in operating particle impact drill bits it may be difficult to determine from the surface where the drill bit is located relative to a terminal end or bottom of the borehole resulting in potentially damaging impacts between the particle impact drill bit and the terminal end of the borehole. Further, the particle impact drill bit may become worn or damaged by the ricocheting of the impactors when, for example, the particle impact drill bit is positioned directly adjacent the terminal end of the borehole. 
     Accordingly, embodiments of particle impact drill bits are described herein which provide a borehole having a relatively consistent and even sidewall such that WOB may be applied to the drill bit in a manner that allows the WOB and associated reactive torque applied to the drill bit to be monitored from the surface. Embodiments of particle impact drill bits disclosed herein also allow the drill bit to be spaced from the terminal end of the borehole when in operation to thereby minimize wear and damage to the drill bit from the ricocheting of the impactors against the drill bit. Particularly, embodiments of particle impact drill bits disclosed herein include a reamer or reamer section incorporated into the drill bit to stabilize the drill bit during operation. The reamer section of the particle impact drill bit may expand an inner diameter by of the borehole by mechanically cutting into the portion of the borehole fractured and/or distressed by the jets of particle impactors, thereby providing the borehole with a relatively consistent and even sidewall. Additionally, the reamer section may form a shoulder along the sidewall such that WOB may be applied to the particle impact drill bit through the reamer section, the sidewall of the borehole applying reactive force and torque to the reamer section of the drill bit. 
     Referring to  FIG.  1   , an embodiment of a well or drilling system  10  is shown. Well system  10  is generally configured for drilling a borehole  16  in a subterranean earthen formation  5 . In the embodiment of  FIG.  1   , well system  10  includes a drilling rig  20  disposed at the surface, a drillstring  21  extending downhole from rig  20 , a bottomhole assembly (BHA)  30  coupled to the lower end of drillstring  21 , and a drill bit  100  attached to the lower end of BHA  30 . A surface or mud pump  23  is positioned at the surface and is configured to pump drilling fluid or mud  25  through drillstring  21 . In this exemplary embodiment, drilling fluid  25  comprises a slurry including a plurality if solid impactors  27  supplied by an impactor injector  29  of well system  10  located at the surface. As will be described further herein, drill bit  100  comprises a particle impact drill bit  100  configured to form borehole  16  through bombarding or impacting the formation  5  with the impactors contained in drilling fluid  25 . The impactors  27  of drilling fluid  25  may comprise a metallic material such as, for example, hardened steel shot or pellets. However, in other embodiments, the impactors  27  of drilling fluid  25  may comprise other types of solid pellets having a relatively high hardness. 
     Additionally, rig  20  includes a rotary system  24  for imparting torque to an upper end of drillstring  21  to thereby rotate drillstring  21  in borehole  16 . In this embodiment, rotary system  24  comprises a rotary table located at a rig floor of rig  20 ; however, in other embodiments, rotary system  24  may comprise other systems for imparting rotary motion to drillstring  21 , such as a rotary table or top drive. In this exemplary embodiment, a downhole motor  32  is provided in BHA  30  for facilitating the drilling of deviated portions of borehole  16 . Moving downward along BHA  30 , downhole motor  32  includes a hydraulic drive or power section  34 , a driveshaft assembly  36 , and a bearing assembly  38 . In some embodiments, the portion of BHA  30  disposed between drillstring  21  and downhole motor  32  can include other components, such as drill collars, measurement-while-drilling (MWD) tools, reamers, stabilizers and the like. Additionally, in some embodiments, BHA  30  may not include downhole motor  32 . 
     Power section  34  of downhole motor  32  converts the fluid pressure of the drilling fluid  25  pumped downward through drillstring  21  into rotational torque for driving the rotation of drill bit  100 . Particularly, power section  34  comprises a stator coupled to the drillstring  21  and a rotor rotatably positioned within the stator. Driveshaft assembly  36  comprises a driveshaft housing coupled to the stator of power section  34  and a driveshaft rotatably positioned within the driveshaft housing and coupled to the rotor of power section  34 . Additionally, bearing assembly  38  comprises a bearing housing  40  coupled to the driveshaft housing and a bearing mandrel  42  rotatably disposed in the bearing housing  40 , where the bearing mandrel  42  is coupled between the drill bit  100  and the driveshaft of driveshaft assembly  36 . In this configuration, driveshaft assembly  36  and bearing assembly  38  transfer the torque generated in power section  34  to drill bit  100 . Particularly, torque applied to the rotor of power section  34  by the drilling fluid  25  pumped down through the drillstring  21  is transmitted to the drill bit  100  via the driveshaft of driveshaft assembly  36  and bearing mandrel  42  connected therebetween. 
     With force or weight applied to the drill bit  100  by the drillstring  21  and BHA  30 , also referred to as WOB, the rotating drill bit  100  engages the earthen formation  5  and proceeds to form borehole  16  along a predetermined path toward a target zone. The drilling fluid  25  pumped down the drillstring  21  and through BHA  30  from surface pump  23  passes out of the face of drill bit  100  and back up the annulus  18  formed between drillstring  21  and the sidewall  19  of borehole  16 . The drilling fluid  25  cools the drill bit  100 , and flushes the cuttings away from the face of drill bit  100  and carries the cuttings to the surface. In other embodiments, drill bit  100  may engage the earthen formation  5  to form borehole  16  without being rotated either by the downhole motor  32  or via rotation of the drillstring  21  from the surface. 
     Referring to  FIG.  2   , an enlarged schematic view of the drill bit  100  within borehole  16  is shown. As described above, in this exemplary embodiment, drill bit  100  comprises a particle impact drill bit  100  configured to direct one or more jets  90  of drilling fluid  25  against a terminal end  17  of borehole  16  whereby the impactors  27  contained within jets  90  bombard, fracture and erode the portion of the earthen formation  5  defining the terminal end  17  of borehole  16 . In other words, drill bit  100  is configured to fluidically fracture (via the impactors  27 ) rather than mechanically cut into the terminal end  17  of borehole  16 . 
     Drill bit  100  has a central or longitudinal axis  105 , a longitudinal first end  101 , and a longitudinal second end  103  opposite the first end  101 . The drill bit  100  may include a connector (not shown in  FIG.  2   ) located at second end  103  for connecting drill bit  100  with a terminal end of the bearing mandrel  42  of bearing assembly  38 . In this exemplary embodiment, drill bit  100  comprises a pilot section  102  located at the first end  101  and a reamer section  120  positioned between the pilot section  102  and the second end  103 . Pilot section  102  generally includes a nose  104  and a plurality of nozzles  106  positioned on and/or within nose  104  and which are configured to produce jets  90 . Particularly, nozzles  106  receive the impactor  27  containing drilling fluid  25  pumped through the drillstring  21  and increase a flow velocity of the drilling fluid  25  as the drilling fluid  25  flows through the nozzles  106 . The increase in velocity imparted to the drilling fluid  25  by nozzles  106  increases the impact energy between the impactors  27  and the earthen formation  5 , thereby permitting the impactors  27  to fracture and/or destress the earthen formation  5  defining the terminal end  17  of borehole  16 . Each nozzle  106  is configured to produce a corresponding jet  90  of drilling fluid  25  along a predefined jet axis  95 . In some embodiments, the jet  90  of drilling fluid  25  may travel at a velocity between approximately 300 feet per second (ft/sec) and 700 ft/sec to provide approximately between eight million impacts of the impactors  27  per minute and twenty million impacts per minute; however, in other embodiments, the fluid velocity of jets  90  and the number of impacts per minute of impactors  27  may vary. 
     The jet axis  95  of one or more of the jets  90  of drilling fluid  25  may be at a non-zero angle relative to the central axis  105  of drill bit  100 . In some embodiments, the nozzles  106  are arranged and oriented along nose  104  to produce a cross-over pattern of jets  90  of drilling fluid  25  extending from the drill bit  100 . In this arrangement, one or more jets  90  of drilling fluid  25  extend radially outwards from central axis  105  while one or more other jets  90  of drilling fluid  2  extend radially towards central axis  105  to thereby intersect or overlap with other jets  90 . In this manner, a broad area of the terminal end  17  of borehole  16  may be impacted by the impactors  27  conveyed along the jets  90  extending from drill bit  100 . However, it may be understood that the number, arrangement along nose  104 , and orientation of nozzles  106  may vary to produce a variety of spray patterns of jets  90  depending on the given application. 
     In this exemplary embodiment, reamer section  120  of drill bit  100  generally comprises a reamer including a plurality of circumferentially spaced reamer blades  122  which extend radially outwards from the central axis  105  of drill bit  100 . Each reamer blade  122  of reamer section  120  comprises one or more engagement or cutting members  124  positioned along an outer surface  123  of the reamer blade  122  and configured to mechanically engage or contact a sidewall  19  of the borehole  16 . In this exemplary embodiment, cutting members  124  are distinct from the reamer blade  122  itself and comprise a Polycrystalline Diamond Compact (PDC) material. However, in other embodiments, the material comprising each cutting member  124  may vary. In still other embodiments, cutting members  124  may be formed integrally and monolithically with the reamer blade  122 . In other embodiments, reamer section  120  may comprise a roller or roller cone reamer in which reamer blades  122  would comprise rollers (e.g., cone shaped rollers) upon which cutting members would be positioned. Thus, in some embodiments, reamer blades  122  may comprise members which are separate from a body of reamer section  120  and may pivot or rotate relative to the body of reamer section  120  during operation. Additionally, in this exemplary embodiment, reamer section  120  is concentric with respect to pilot section  102 ; however, in other embodiments, reamer section  120  may be bi-centric or eccentric. 
     Pilot section  102  of drill bit  100  is configured to fluidically fracture the earthen formation  5  defining the terminal end  17  of borehole  16  via the plurality of jets  90  of drilling fluid  25  while reamer section  120  of drill bit  100  is configured to mechanically expand and complete the borehole  16  to a desired diameter via the reamer blades  122  as the drill bit  100  penetrates into the earthen formation  5 . Accordingly, pilot section  102  of drill bit  100  has a maximum outer diameter  110  which is less than a maximum outer diameter  126  of reamer section  120  (defined by the reamer blades  122  of reamer section  120 ). In this manner, the maximum outer diameter  126  of reamer section  120  defines an overall maximum diameter of the drill bit  100 . In some embodiments, a ratio of the maximum outer diameter  126  of reamer section  120  to the maximum outer diameter  110  of pilot section  102  may range approximately between 1.1:1 to 2.0:1.; however, in other embodiments the ratio of the maximum outer diameter  126  of reamer section  120  to the maximum outer diameter  110  of pilot section  102  may vary. 
     Given the difference in maximum outer diameter between pilot section  102  and reamer section  120 , as drill bit  100  penetrates into earthen formation  5  to form borehole  16 , borehole  16  is initially formed by the pilot section  102  of drill bit  100  at an initial diameter  31 . As the drill bit  100  continues to penetrate into earthen formation  5 , the initial diameter of the newly formed section of borehole  16  is expanded to a second diameter  33  which is greater than the initial diameter  31 . In some embodiments, a ratio of the initial diameter  31  to the expanded diameter  33  of borehole  16  may range approximately between 1.1:1 to 1.5:1. In some embodiments, the ratio of the initial diameter  31  to the expanded diameter  33  of borehole  16  may be less than 1.1:1. Additionally, it may be understood that in other embodiments the ratio of the initial diameter  31  to the expanded diameter  33  may vary. 
     The difference in diameter between the initial diameter  31  and expanded diameter  33  of borehole  16  forms an annular shoulder  35  along the sidewall  19  of borehole  16  which is engaged by the reamer section  120  of drill bit  100 . Particularly, during operation of well system  10 , WOB may be applied to drill bit  100  by the drillstring  21  and BHA  30  via the contact that occurs between the reamer section  120  of drill bit  100  and the shoulder  35  of borehole  16 . This WOB applied to drill bit  100  may be monitored at the surface by personnel of well system  10  to assist in controlling the operation and performance of drill bit  100 . Similarly, contact between the reamer section  120  and the sidewall  19  of borehole  16  allows for reactive torque applied to drill bit  100  by the sidewall  19  to also be monitored at the surface by personnel of well system  10  to further assist in controlling the operation and performance of drill bit  100 . 
     In addition, contact between the shoulder  35  of borehole  16  and the reamer section  120  of drill bit  100  suspends drill bit  100  within borehole  16  whereby a longitudinal distance  37  extends between the first end  101  of drill bit  100  and the terminal end  17  of borehole  16 . In other words, contact between the shoulder  35  of borehole  16  and the reamer section  120  of drill bit  100  prevents the first end  101  of drill bit  100  from contacting the terminal end  17  of the borehole  16 . The longitudinal distance  37  separating the drill bit  100  from the terminal end  17  of borehole  16  may reduce or mitigate damage occurring to drill bit  100  from the ricocheting of impactors  27  as the impactors  27  collide against the terminal end  17  of borehole  16 . Particularly, spacing the first end  101  of the drill bit  100  by the longitudinal distance  37  from the terminal end  17  of borehole  16  may shield the reamer section  120  from ricocheting of the impactors  27  and thus confine exposure to ricocheting impactors  27  to the pilot section  102 . In some embodiments, the pilot section  102  may thus be formed from a hardened, impact resistant material to weather ricocheting of the impactors  27  while the reamer section  120  may be made from a different, lower cost material. 
     In some embodiments, the longitudinal distance  37  may be controlled or at least influenced by varying a longitudinal length  107  of the pilot section  102  relative to an overall longitudinal length  109  of the drill bit  100 . Particularly, the longitudinal distance  37  may be increased by reducing the longitudinal length  107  of the pilot section  102  relative to the overall length  209  of the drill bit  100 . In some embodiments, the longitudinal distance may be three inches or greater; however, it may be understood that the longitudinal distance  37  may vary significantly depending on the given application. 
     Referring to  FIGS.  3 - 6   , another embodiment of a particle impact drill bit  200  is shown. Drill bit  200  may be utilized in well system  10  in lieu of the drill bit  100  shown in  FIG.  2   . Alternatively, drill bit  200  may be utilized in well systems other than the well system  10  shown in  FIG.  1   . Drill bit  200  has a central or longitudinal axis  205 , a longitudinal first end  201 , and a longitudinal second end  203  opposite the first end  201 . Drill bit  200  includes a connector  204  located at the second end  203  of drill bit  200  for connecting drill bit  200  with a bearing mandrel or other tubular member of a well system. In this exemplary embodiment, connector  204  comprises an external threaded connector, however, it may be understood that the configuration of connector  204  may vary. 
     In this exemplary embodiment, drill bit  200  includes an integral or monolithic body  207  comprising a pilot section  210  located at the first end  201  and a reamer section  260  positioned between the pilot section  210  and the second end  203 . Connector  204  is separate and distinct from body  207  in this exemplary embodiment; however, in other embodiments, connector  204  may also be formed integrally and monolithically with body  207 . In this exemplary embodiment, the body  207  of drill bit  200  comprises a matrix material such as, for example, a matrix carbide material. In other embodiments, body  207  may comprise a cast material such as, for example, a cast carbide material. In still other embodiments, the materials comprising body  207  and the method for forming body  207  may vary. In some embodiments, pilot section  210  may comprise a solid carbide, Satellite, or other material created through an additive manufacturing process. For example, pilot section  210  may be manufactured using a directed energy deposition (DED) or other form of laser metal deposition under additive manufacturing. In some embodiments, pilot section  210  may be manufactured using a laser metal deposition process using metal wire, power, and/or ceramics to form pilot section  210 . In some embodiments, the one or more nozzles of pilot section  210  may be formed integrally and monolithically with the body forming pilot section  210 . For example, the nozzles may be printed into the body forming pilot section  210  in embodiments where pilot section  210  is constructed using an additive manufacturing process. 
     Although in this exemplary embodiment both reamer section  260  and pilot section  210  are part of the same body  207 , in other embodiments, reamer section  260  and pilot section  210  may comprise separate components which are joined to form drill bit  200 . Particularly, given that reamer section  260  is shielded from at least some of the ricocheting impactors  27  as described above with respect to drill bit  100 , in some embodiments, pilot section  210  may comprise a material which has a greater hardness and/or resistance to wear than the material comprising reamer section  260 . In this manner, the cost of the materials comprising drill bit  200  may be minimized. For example, drill bit  200  may comprise a first body formed from a first material and comprising the pilot section  210 , and a second body formed from a second material and comprising the reamer section  260 , wherein the first material has a greater hardness and wear resistance than the second material. 
     In this exemplary embodiment, the pilot section  210  of drill bit  200  comprises an externally curved nose  212  and a plurality of receptacles  216  extending through the nose  212  of pilot section  210 . In this exemplary embodiment, nose  212  is defined by convex outer surface  214  having a bullet or teardrop shape. The convex outer surface  214  of nose  212  may assist in directing the recirculation of drilling fluid  25  upwards through borehole  16  after the drilling fluid  25  has been ejected from drill bit  200 . 
     Each receptacle  216  of pilot section  210  receives a nozzle assembly  220  therein for accelerating a flow of drilling fluid  25  therethrough such that a high-velocity jet of drilling fluid  25  (containing impactors  27 ) is ejected from the nozzle assembly  220  against the terminal end  17  of borehole  16  to thereby fracture or destress the earthen formation  5  defining terminal end  17 . In this exemplary embodiment, pilot section  210  comprises a plurality of the receptacles  216  and corresponding nozzle assemblies  220  arranged in a cross-over pattern; however, it may be understood that the number and/or arrangement of nozzle assemblies  220  may vary. Nozzle assemblies  220  are separate from the body  207  of drill bit  200  and thus may be formed from materials that vary in composition and/or method of manufacture than the material(s) comprising body  207 , as will be described further herein. 
     Referring briefly to  FIGS.  7 ,  8   , each nozzle assembly  220  comprises a first or upstream sleeve  222  and a second or downstream sleeve  240 . Particularly, upstream sleeve  222  includes a longitudinal first end  223 , a longitudinal second end  225  opposite first end  223 , a central bore or passage  224  defined by a generally cylindrical inner surface  226  extending between ends  223 ,  225 , and a generally cylindrical outer surface  228  also extending between ends  223 ,  225 . The central passage  224  of upstream sleeve  222  has a tapered section  230  having a longitudinally extending taper length  231 . The fluid velocity of the drilling fluid  25  flowing through nozzle assembly  220  increases as it passes through the tapered section  230  due to the continuously decreasing diameter of tapered section  230 . 
     The taper length  231  of tapered section  230  is maximized in this embodiment to concomitantly minimize the shear stress applied to the inner surface  226  of tapered section  230  by the drilling fluid  25  as it accelerates through the tapered section  230 . The minimizing of shear stress applied to the inner surface  226  of tapered section by the drilling fluid  25  may minimize erosion of the tapered section  230  and thereby maximize the operational lifespan of the nozzle assembly  220 . In this exemplary embodiment, the taper length  231  is greater than an overall or maximum width  233  of the nozzle assembly  220 . The maximum width  233  of nozzle assembly  220  also being less than a maximum length  235  of the nozzle assembly  220 . The taper length  231  may vary depending on the application, and particularly, on the initial velocity of the drilling fluid  25  as it enters nozzle assembly  220  so that a desired exit velocity of the drilling fluid  25  may be achieved. 
     The downstream sleeve  240  of nozzle assembly  220  includes a longitudinal first end  241 , a longitudinal second end  243  opposite first end  241 , a central bore or passage  242  defined by a generally cylindrical inner surface  244  extending between ends  241 ,  243 , and a generally cylindrical outer surface  246  also extending between ends  241 ,  243 . In this embodiment, a connector  248  is formed on the outer surface  246  of downstream sleeve  240 . Connector  248  may releasably connect to a corresponding connector of one of the receptacles  216  of pilot section  210  to thereby releasably couple the downstream sleeve  240  with the body  207  of drill bit  200  such that nozzle assembly  220  is not ejected from the receptacle  216  by the flow of drilling fluid  25 . In this exemplary embodiment, connector  248  comprises a threaded connector  248 ; however, it may be understood that the form of connector  248  may vary. The releasable connection formed between nozzle assembly  220  and the body  207  of drill bit  200  permits the nozzle assemblies  220  to be periodically replaced once the nozzle assembly has become worn without needing to also replace the body  207  of drill bit  200 , minimizing the operational costs of drill bit  200 . In some embodiments, the upstream sleeve  222  may simply be inserted into the receptacle  216  of body  207  following the coupling of the downstream sleeve  240  with the receptacle  216 . While the upstream sleeve  222  may be free to move relative to the downstream sleeve  240  in this arrangement, the flow of drilling fluid  25  during operation presses the upstream sleeve  222  against the downstream sleeve  240 , preventing upstream sleeve  222  from escaping the receptacle  216 . In other embodiments, upstream sleeve  222  may be mechanically coupled to the downstream sleeve  240 . As will be discussed further herein, one or both of the first end  223  of the upstream sleeve  222  and the second end  243  of downstream sleeve  240  may project outwardly from the receptacle  216  of body  207  in which the nozzle assembly  220  is received. 
     In addition to nozzle assembly  220  being configured to have a taper length  231  in excess of the maximum width  233  thereof, nozzle assembly  220  is also configured to have a relatively small maximum width  233  relative to the maximum length  235  of the nozzle assembly  220 . In some embodiments, a ratio of the maximum length  235  of nozzle assembly  220  to the maximum width  233  of the nozzle assembly  220  may range approximately between 2:1 to 10:1; however, it may be understood that the ratio of the maximum length  235  to the maximum width  233  of nozzle assembly  220  may vary. Minimizing the maximum width  233  of nozzle assembly  220  allows for flexibility in positioning a plurality of nozzle assemblies  220  in the pilot section  210  at varying impingement angles to thereby desirably spread the energy of the jetted impactors  27  across the terminal end  17  of borehole  16 . Additionally, the elongated nozzle assembly  220  minimizes changes in the direction of the flow of drilling fluid  25 , in-turn minimizing the wear of nozzle assembly  220  during operation. 
     Given that nozzle assembly  220  is not integrally formed with body  207  of drill bit  200  it may be formed from materials which vary from those comprising body  207 . In some embodiments, nozzle assembly  220  comprises a material having a greater hardness and/or resistance to wear than the material comprising body  207 . For example, nozzle assembly  220  may comprise a solid carbide material. In other embodiments, nozzle assembly  220  may comprise a tungsten-carbide material. Additionally, the material comprising upstream sleeve  222  may vary from the material comprising downstream sleeve  240 . For example, given that upstream sleeve  222  comprises the tapered section  230  which may result in increased shear stress being applied to upstream sleeve  222 , upstream sleeve  222  may comprise a material having a greater hardness and/or resistance to wear than the material comprising downstream sleeve  240 . 
     While in this exemplary embodiment nozzle assembly  220  comprises separate sleeves  222 ,  240  which assembled with the body  207  of drill bit  200 , in other embodiments, nozzle assembly  220  may include a single sleeve. Thus, nozzle assembly  220  may also be referred to herein as nozzle  220 . As an example, referring briefly to  FIGS.  9 ,  10   , another embodiment of a nozzle  250  is shown. Nozzle  250  includes a longitudinal first end  251 , a longitudinal second end  253  opposite first end  251 , a central bore or passage  252  defined by a generally cylindrical inner surface  254  extending between ends  251 ,  253 , and a generally cylindrical outer surface  256  also extending between ends  251 ,  253 . Additionally, nozzle  250  comprises a single, integrally or monolithically formed body  255  extending between ends  251 ,  253 . 
     In this exemplary embodiment, the central passage  252  of nozzle  250  has a tapered section  258 . Similar to nozzle assembly  220  described above, the tapered section  258  of nozzle  250  has a taper length which is greater than a maximum width of the nozzle  250 . Additionally, the fluid velocity of the drilling fluid  25  flowing through nozzle  250  increases as it passes through the tapered section  258  due to the continuously decreasing diameter of tapered section  258 . Further, a connector  261  is formed on the outer surface  256  of nozzle  250 . Connector  261  may releasably connect to a corresponding connector of one of the receptacles  216  of pilot section  210  to thereby releasably couple the nozzle  250  with the body  207  of drill bit  200 . 
     Referring again to  FIGS.  3 - 6   , the reamer section  260  of drill bit  200  includes a plurality of circumferentially spaced reamer blades  262  which extend radially outwards from the central axis  205  of drill bit  200 . Similar to drill bit  100  shown in  FIG.  2   , each reamer blade  262  of reamer section  260  comprises a plurality of engagement or cutting members (indicated generally by arrows  264 ) positioned along an outer surface  263  of the reamer blade  262  and which are configured to mechanically engage or contact a sidewall  19  of the borehole  16 . In this exemplary embodiment, cutting members  264  comprise PDC inserts distinct from body  207  of drill bit  200 . However, in other embodiments, the configuration of cutting members  264  and reamer blades  262  may vary. Additionally, as with drill bit  100 , the reamer blades  262  of reamer section  260  define a maximum width or diameter of the drill bit  200  which is greater than a maximum width or diameter of the pilot section  210  of drill bit  200 . 
     As shown particularly in  FIGS.  5 ,  6   , drill bit  200  comprises a feed bore or passage  270  which extends into drill bit  200  from first end  201  to a terminal end  272  located within the body  207  of drill bit  200 . Body  207  of drill bit  200  is hidden in  FIG.  6    to conveniently illustrate the relationship between feed passage  270  and the nozzle assemblies  220  housed within the receptacles  216  of body  207 . In this exemplary embodiment, feed passage  270  includes a cylindrical section or passage  274  extending from the first end  201  and an expansion passage or section  276  extending from the cylindrical passage  274  to the terminal end  272  of feed passage  270 . Cylindrical passage  274  is defined by a cylindrical inner surface  275  while the expansion passage  276  is defined by a frustoconical inner surface  277 . Additionally, a flow area of the cylindrical passage  274  remains relatively constant moving along the longitudinal length of cylindrical passage  274 . Conversely, a flow area of expansion passage  276  increases moving towards the terminal end  272  of feed passage  270 . Expansion passage  276  has an oval-shaped flow area in this exemplary embodiment; however, the shape of the flow area of expansion passage  276  may vary in other embodiments. 
     The gradual expansion of the flow area through expansion passage  276  approaching the terminal end  272  of feed passage  270  provides a smooth transition for the drilling fluid  25  as the drilling fluid  25  flows through feed passage  270  and into the nozzle assemblies  220  of pilot section  210 . The smooth transition provided by expansion passage  276  in-turn minimizes disturbances to the flow of drilling fluid  25  such that a laminar flow of drilling fluid  25  is provided through feed passage  270 . The laminar flow of drilling fluid  25  may minimize wear to the inner surfaces  275 ,  277  of feed passage  270  and thereby prolong the operational life of the body  207  of drill bit  200 . 
     In this exemplary embodiment, each of the plurality of nozzle assemblies  220  projected through the terminal end  272  and into feed passage  270 . Particularly, the upstream sleeve  222  of each nozzle assembly  220  projects into feed passage  270  rather than being recessed into the receptacle  216  in which the upstream sleeve  222  is received. In this configuration, any turbulence in the flow of drilling fluid  25  as the drilling fluid  25  reaches the terminal end  272  of feed passage  270  is focused onto the upstream sleeves  222  of nozzle assemblies  220  rather than onto the body  207  of drill bit  200 . 
     As described above, nozzle assemblies  220 , and particularly the upstream sleeves  222  thereof, may be formed of a material having a greater hardness and/or resistance to wear than the material comprising body  207 . Thus, by focusing the turbulence and shear stresses associated therewith against the relatively durable nozzle assemblies  220 , the overall wear subjected to drill bit  200  (including both body  207  and nozzle assemblies  220 ) may be minimized, increasing the operational life of drill bit  200 . Additionally, the nozzle assemblies  220  may be conveniently replaced when worn. 
     Referring to  FIGS.  11 - 15   , another embodiment of a particle impact drill bit  300  is shown. Drill bit  300  may be utilized in well system  10  in lieu of the drill bit  100  shown in  FIG.  2   . Drill bit  300  has features in common with drill bit  200  shown in  FIGS.  3 - 6   , and shared features are labeled similarly. Drill bit  300  has a central or longitudinal axis  305 , a longitudinal first end  301 , and a longitudinal second end  303  opposite the first end  301 . Drill bit  300  includes the connector  204  located at the second end  303  of drill bit  300  for connecting drill bit  300  with a bearing mandrel or other tubular member of a well system. 
     In this exemplary embodiment, drill bit  300  includes an integral or monolithic body  307  comprising a pilot section  310  located at the first end  301 , a first or downhole reamer section  320  positioned between the pilot section  310  and the second end  303 , and a second or uphole reamer section  360  positioned between downhole reamer section  320  and second end  303 . Downhole reamer section  320  may also be referred to herein as lower reamer section  320  while uphole reamer section  360  may also be referred to herein as upper reamer section  360 . In other embodiments, the pilot section  310 , downhole reamer section  320 , and/or uphole reamer section  360  may be formed from separate and distinct bodies which are later assembled or joined together to form drill bit  300 . The pilot section  310  of drill bit  300  is similar in configuration as pilot section  210  of drill bit  200  and thus will not be discussed here in detail. Particularly, similar to pilot section  210  of drill bit  200 , pilot section  310  comprises a plurality of the nozzle assemblies  220  each of which are configured to produce a first or lower jet (indicated by arrow  312  in  FIG.  14   ) of drilling fluid  25  (including impactors  27 ) to distress a terminal end  392  of a borehole  390  formed in a subterranean earthen formation  393 . 
     The downhole reamer section  320  of drill bit  300  includes a plurality of circumferentially spaced first or downhole reamer blades  322  which extend radially outwards from the central axis  305  of drill bit  300 . Similar to drill bit  200  shown in  FIGS.  3 - 6   , each downhole reamer blade  322  of reamer section  320  comprises a plurality of engagement or cutting members (indicated generally by arrows  324 ) positioned along an outer surface  323  of the downhole reamer blade  322  and which are configured to mechanically engage or contact a sidewall  391  of a borehole  390  (shown schematically in  FIG.  14   ) formed by drill bit  300 . In this exemplary embodiment, cutting members  324  comprise PDC inserts distinct from body  307  of drill bit  300 . However, in other embodiments, the configuration of cutting members  324  and downhole reamer blades  322  may vary. Additionally, in this exemplary embodiment, one or more of the downhole reamer blades  322  comprises a receptacle  326  extending at a non-zero, non-orthogonal angle relative to the central axis  305 . 
     In this exemplary embodiment, in addition to downhole reamer blades  322 , downhole reamer section  320  includes one or more circumferentially spaced nozzle assemblies  330  received in the receptacle  326  of a corresponding downhole reamer blade  322 . Nozzle assemblies  330  are similar in configuration to nozzle assemblies  220  shown in  FIGS.  5 ,  6    (in some embodiments nozzle assemblies  220  themselves may be received in receptacles  326  in lieu of nozzle assemblies  330 ) and comprise a tapered/converging first or upstream sleeve  332  and a second or downstream sleeve  336  which secures the nozzle assembly  330  into the given receptacle  326  via a connector  338  formed on an outer surface thereof. Additionally, as with nozzle assemblies  220  of pilot section  310 , nozzle assemblies  330  project or extend into a central feed passage  335  of drill bit  300  which is in fluid communication with both nozzle assemblies  330  of downhole reamer section  320  and the nozzle assemblies  220  of pilot section  310 . Similar to feed passage  270  of drill bit  200 , feed passage  335  of drill bit  300  includes an expansion passage or section  337  with a gradually expanding flow area moving in a downstream direction. 
     In this exemplary embodiment, nozzle assembly  330  accelerates the velocity of drilling fluid  25  as the drilling fluid  25  flows therethrough whereby a second or upper jet (indicated by arrow  340  in  FIG.  14   ) is directed against the sidewall  391  of the borehole  390 . Thus, instead of being directed against the terminal end  392  of borehole  390  as with lower jets  312  produced by pilot section  310 , upper jets  340  produced by downhole reamer section  320  are directed against the sidewall  391  of borehole  390 . Particularly, upper jets  340  are directed against and contact the portion of sidewall  391  extending uphole from an annular first or downhole shoulder  394  formed by downhole reamer section  320  as drill bit  300  penetrates into earthen formation  393 . Thus, upper jets  340  fracture and/or distress the portion of sidewall  391  that has already been expanded by downhole reamer section  320 . To state in other words, as drill bit  300  penetrates into earthen formation  393 , initially the terminal end  392  of borehole  390  is fractured and/or distressed by lower jets  312  of pilot section  310 . The initial hole formed by pilot section  310  is then stabilized and expanded by downhole reamer section  320 . The portion of the newly created section of borehole  390  is then fractured and/or distressed by upper jets  340 . 
     To fracture and/or distress the portion of borehole  390  expanded by downhole reamer section  320 , the jets  340  produced by downhole reamer section  320  (as well as the nozzle assemblies  330  which produce upper jets  340 ) are oriented in an uphole direction facing away from the terminal end  392  of borehole  390 , in contrast to the lower jets  312  (along with the nozzle assemblies  220  which produce lower jets  312 ) which are oriented in a downhole direction facing the terminal end  392  of borehole  390 . To state in other words, in this exemplary embodiment, upper jets  340 /nozzle assemblies  330  of downhole reamer section  320  are oriented at an obtuse angle relative to lower jets  312 /nozzle assemblies  220  of pilot section  310 . 
     The uphole reamer section  360  of drill bit  300  includes a plurality of circumferentially spaced second or uphole reamer blades  362  which extend radially outwards from the central axis  305  of drill bit  300 . In this exemplary embodiment, a longitudinal length (e.g., a length extending substantially parallel central axis  305 ) of at least some of the uphole reamer blades  362  may vary. Uphole reamer blades  362  are axially spaced from the lower downhole reamer blades  322  of lower reamer section  320 . Similar to drill bit  200  shown in  FIGS.  3 - 6   , each uphole reamer blade  362  of reamer section  360  comprises a plurality of engagement or cutting members (indicated generally by arrows  364 ) positioned along an outer surface  363  of the uphole reamer blade  362  and which are configured to mechanically engage or contact a sidewall  391  of a borehole  390  (shown schematically in  FIG.  14   ) formed by drill bit  300 . In this exemplary embodiment, cutting members  364  comprise PDC inserts distinct from body  307  of drill bit  300 . However, in other embodiments, the configuration of cutting members  364  and uphole reamer blades  362  may vary. 
     In this exemplary embodiment, the uphole reamer blades  362  of uphole reamer section  360  define a maximum width or diameter  309  of the drill bit  300  which is greater than both a maximum width or diameter of pilot section  310  and a maximum width or diameter of downhole reamer section  320 . Thus, as drill bit  300  penetrates further into earthen formation  393 , the relatively larger reamer blades  364  of uphole reamer section  360  mechanically cut into the portion of sidewall  391  fractured and/or distressed by upper jets  340  to expand the diameter of borehole  390  and thereby form an annular second or uphole shoulder  396  that is axially spaced from the downhole shoulder  394  formed by downhole reamer section  320 . 
     In this exemplary embodiment, uphole reamer blades  362  are not positioned entirely about the central axis  305  of drill bit  300  and instead are located only along a single half of the circumference of uphole reamer section  360 . To state in other words, in this exemplary embodiment, uphole reamer blades  362  are positioned only along a first lateral side (indicated by arrow  361  in  FIG.  13   ) of uphole reamer section  360  while an opposing second lateral side (indicated by arrow  365  in  FIG.  13   ) of uphole reamer section does not include any uphole reamer blades  362 . In this exemplary embodiment, each lateral side  361 ,  365  of uphole reamer section  360  extends substantially and contiguously 180° about the central axis  305  of drill bit  300 ; however, in other embodiments, the circumferential length of lateral sides  361 ,  365  may vary. For example, in other embodiments, first lateral side  361  may extend only 90° about the central axis  305  while second lateral side  365  extends 270° about central axis  305 . In this exemplary embodiment, uphole reamer section  360  comprises a plurality of wear members or buttons (indicated generally by arrow  368 ) which are positioned along the second lateral side  365 . Wear buttons  368  comprise a hardened, wear resistant material which stabilize drill bit  300  and protect the body  307  of drill bit  300  from wear when the drill bit  300  is lowered from the surface and through the borehole  390  towards the terminal end  392  thereof. 
     By positioning uphole reamer blades  362  only along one lateral side  361  of uphole reamer section  360 , drill bit  300  forms or comprises a “bi-center” drill bit  300  in which the maximum width or diameter of drill bit  300  varies depending upon whether drill bit  300  is in rotation about central axis  305 . Particularly, drill bit  300  comprises a first maximum outer diameter  309  when drill bit  300  does not rotate about central axis  305  and a second maximum diameter  309  when drill bit  300  rotated about central axis  305  that is larger than the first maximum outer diameter  309 , where the difference between the first and second maximum diameters  309  is dependent on the radially extending (relative central axis  305 ) size of uphole reamer blades  362 . 
     As an example, when drill bit  300  is run-in or lowered from the surface through borehole  390  (e.g., following the casing of an already drilled section of borehole  390 , etc.), drill bit  300  may be slid through borehole  390  such that drill bit  300  is held relatively stationary about central axis  305  to thereby minimize the maximum outer diameter  309  of drill bit  300 . Once drill bit  300  reaches a drilling position in borehole  390  proximal terminal end  392  to resume drilling of borehole  390 , drill bit  300  may be rotated about central axis  305  (e.g., from the surface or via a downhole mud motor) as drilling fluid  25  is pumped through drill bit  300  causing drill bit  300  to drill into the terminal end  392  of borehole  390  and thereby extend borehole  390 . 
     As drill bit  300  rotates about central axis  305 , uphole reamer blades  362  mechanically cut into the sidewall  391  of borehole  390  thereby expanding a diameter of the borehole  390  to a size corresponding or equivalent to the second and larger maximum outer diameter  309  of drill bit  300 . By minimizing the maximum outer diameter  309  of drill bit  300  as drill bit  300  is run-into the borehole  390 , the taper or reduction in diameter of borehole  390  that occurs moving from the surface towards terminal end  392  may be minimized given that at the reduced first maximum outer diameter  309  the drill bit  300  can successfully fit through each section of the borehole  390  as it travels towards the drilling position proximal terminal end  392 . In at least some applications, it may be advantageous to minimize or eliminate (e.g., the borehole  390  may have a constant inner diameter along its longitudinal length) the taper of borehole  390  along its longitudinal length to thereby, for example, maximize the flow area within the most downhole portion of borehole  390  proximal terminal end  392 . 
     Referring to  FIGS.  16 ,  17   , another embodiment of a particle impact drill bit  400  is shown. Drill bit  400  may be utilized in well system  10  in lieu of the drill bit  100  shown in  FIG.  2   . Additionally, drill bit  400  has features in common with drill bit  300  shown in  FIGS.  11 - 15   , and shared features are labeled similarly. Drill bit  400  has a central or longitudinal axis  405 , a longitudinal first end  401 , and a longitudinal second end  403  opposite the first end  401 . Additionally, drill bit  400  includes an integral or monolithic body  407  comprising pilot section  310  located at the first end  401 , a first or downhole reamer section  410  positioned between the pilot section  310  and the second end  403 , and uphole reamer section  360  positioned between downhole reamer section  410  and second end  403 . Downhole reamer section  410  may also be referred to herein as lower reamer section  410 . In other embodiments, the pilot section  310 , downhole reamer section  410 , and/or uphole reamer section  360  may be formed from separate and distinct bodies which are later assembled or joined together to form drill bit  400 . 
     Downhole reamer section  410  of drill bit  400  includes the plurality of circumferentially spaced downhole reamer blades  322 . Additionally, in this exemplary embodiment, downhole reamer section  410  includes one or more circumferentially spaced receptacles  412  extending at a non-zero, non-orthogonal angle relative to the central axis  405 . Unlike downhole reamer section  320  of drill bit  300 , the one or more receptacles  412  are positioned circumferentially between reamer blades  322 . The one or more receptacles  412  receive a corresponding nozzle  414  secured therein and configured to produce a second or upper jet (indicated by arrow  416  in  FIG.  16   ) of drilling fluid  25  (containing impactors  27 ) directed against the sidewall  391  of borehole  390 . Nozzle  414  is axially spaced from the plurality of nozzle assemblies  220  of pilot section  310 . Jet  416  and nozzle  414  are each oriented in an uphole direction that is in an obtuse angle relative to the direction of jets  312  produced by the pilot section  310  of drill bit  400 . Additionally, in this exemplary embodiment, nozzles  414  comprise a singular, tapered or converging nozzle rather than an assembly. Additionally, each nozzle  414  comprises a connector which couples to a connector formed on an inner surface of the corresponding receptacle  412 . 
     Referring to  FIGS.  18 ,  19   , another embodiment of a particle impact drill bit  450  is shown. Drill bit  450  may be utilized in well system  10  in lieu of the drill bit  100  shown in  FIG.  2   . Additionally, drill bit  450  has features in common with drill bit  300  shown in  FIGS.  11 - 15   , and shared features are labeled similarly. Drill bit  450  has a central or longitudinal axis  455 , a longitudinal first end  451 , and a longitudinal second end  453  opposite the first end  451 . Additionally, drill bit  450  includes an integral or monolithic body  457  comprising pilot section  310  located at the first end  451 , a downhole reamer section  320  positioned between the pilot section  310  and the second end  453 , and a second or uphole reamer section  460  positioned between downhole reamer section  320  and second end  453 . Uphole reamer section  460  may also be referred to herein as upper reamer section  460 . In other embodiments, the pilot section  310 , downhole reamer section  320 , and/or uphole reamer section  460  may be formed from separate and distinct bodies which are later assembled or joined together to form drill bit  450 . 
     Uphole reamer section  460  includes the plurality of reamer blades  362  positioned along the first lateral side  361  thereof. In this exemplary embodiment, uphole reamer section  460  additionally includes one or more receptacles  462  and one or more tapered/converging nozzles  464  configured to produce a second or upper jet (indicated by arrow  466  in  FIG.  18   ) of drilling fluid  25  (containing impactors  27 ) directed against the sidewall  391  of borehole  390 . Nozzle  464  is axially spaced from the nozzle assemblies  220  of pilot section  310 . Additionally, jet  466  and nozzle  464  are each oriented in a downhole direction that is parallel with, or at an acute angle from, the jets  312  produced by pilot section  310 . In this configuration, jets  466  concurrently fracture and/or distress the portion of sidewall  391  mechanically engaged by the reamer blades  362  of uphole reamer section  360 . 
     While in this exemplary embodiment drill bit  450  includes both nozzle assemblies  330  of downhole reamer section  320  and the nozzles  464  of uphole reamer section  460 , in other embodiments, drill bit  450  may only include nozzles  464  (or another nozzle or nozzle assembly) and thus may exclude nozzle assemblies  330 . In such an embodiment, only pilot section  310  and uphole reamer section  460  would include nozzles/nozzle assemblies for fracturing and/or distressing portions of the borehole  390  engaged by drill bit  450 . 
     Referring to  FIG.  20   , an embodiment of a method  500  for forming a borehole extending through a subterranean earthen formation is shown. Beginning at block  502 , method  500  includes pumping a drilling fluid comprising a plurality of solid impactors into a particle impact drill bit located within the borehole. In some embodiments, block  502  comprises pumping the drilling fluid  25  of the well system  10  shown in  FIG.  1    to the drill bit  100  shown in  FIGS.  1 ,  2   . In certain embodiments, block  502  comprises pumping drilling fluid comprising a plurality of solid impactors (e.g., impactors  27  shown in  FIG.  1   ) to one of the drill bits  200 ,  300 ,  400 , and  450  shown in  FIGS.  3 - 19   . 
     At block  504 , method  500  comprises ejecting the drilling fluid as a jet from a converging nozzle of a pilot section of the drill bit whereby the jet impacts a terminal end of the borehole. In some embodiments, block  504  comprises ejecting the drilling fluid  25  as jets  90  from the nozzles  106  of the pilot section  102  of drill bit  100  shown in  FIG.  2    whereby the jets  90  impact the terminal end  17  of the borehole  16 . In certain embodiments, block  504  comprises ejecting a drilling fluid comprising a plurality of solid impactors as jets from the nozzle assemblies  220  of the pilot section  210  of drill bit  200  shown in  FIGS.  3 - 6    whereby the jets impact the terminal end of a borehole. In certain embodiments, block  504  comprises ejecting a drilling fluid comprising a plurality of solid impactors as jets from the nozzle assemblies  220  of the pilot section  310  of drill bits  300 ,  450 , or from the nozzle assemblies  220  of pilot section  310  of drill bit  400 . 
     At block  506 , method  500  comprises expanding the borehole by a reamer section of the drill bit whereby the pilot section of the drill bit is spaced from the terminal end of the borehole as the jet impacts the terminal end of the borehole. In some embodiments, block  506  comprises expanding the borehole  16  shown in  FIGS.  1 ,  2    by the reamer section  120  shown in  FIG.  2    of the drill bit  100  whereby the pilot section  102  of the drill bit  100  is spaced by the longitudinal distance  37  from the terminal end  17  of the borehole  16  as the jets  90  impact the terminal end  17 . In certain embodiments, block  506  comprises expanding the borehole by the reamer section  260  of the drill bit  200  shown in  FIGS.  3 - 6    whereby the pilot section  210  of the drill bit  200  is spaced from the terminal end of the borehole as the jets ejected from the pilot section  210  impact the terminal end of the borehole. In some embodiments, block  506  comprises expanding the borehole by both reamer sections  320 ,  360  of drill bit  300 , the reamer sections  410 ,  360  of drill bit  400 , and the reamer sections  320 ,  460  of drill bit  450 . 
     While exemplary 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. 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.