Patent Publication Number: US-8113300-B2

Title: Impact excavation system and method using a drill bit with junk slots

Description:
CROSS-REFERENCE TO RELATED APPLICATIONS 
     This application claims priority from and the benefit of U.S. application Ser. No. 10/897,196, filed Jul. 22, 2004, which is a continuation-in-part of U.S. application Ser. No. 10/825,338, filed Apr. 15, 2004 now U.S. Pat. No. 7,503,407, which is a non-provisional of U.S. Application No. 60/463,903 filed Apr. 16, 2003, the full disclosure of each of the foregoing is hereby incorporated by reference herein. 
     STATEMENT REGARDING FEDERALLY SPONSORED RESEARCH OR DEVELOPMENT 
     Not Applicable. 
     BACKGROUND 
     The process of excavating a wellbore or cutting a formation to construct a tunnel and other subterranean earthen excavations is a very interdependent process that preferably integrates and considers many variables to ensure a usable bore is constructed. As is commonly known in the art, many variables have an interactive and cumulative effect of increasing drilling costs. These variables may include formation hardness, abrasiveness, pore pressures, and formation elastic properties. In drilling wellbores, formation hardness and a corresponding degree of drilling difficulty may increase exponentially as a function of increasing depth. A high percentage of the costs to drill a well are derived from interdependent operations that are time sensitive, i.e., the longer it takes to penetrate the formation being drilled, the more it costs. One of the most important factors affecting the cost of drilling a wellbore is the rate at which the formation can be penetrated by the drill bit, which typically decreases with harder and tougher formation materials and formation depth. 
     There are generally two categories of modern drill bits that have evolved from over a hundred years of development and untold amounts of dollars spent on the research, testing and iterative development. These are the commonly known as the fixed cutter drill bit and the roller cone drill bit. Within these two primary categories, there are a wide variety of variations, with each variation designed to drill a formation having a general range of formation properties. These two categories of drill bits generally constitute the bulk of the drill bits employed to drill oil and gas wells around the world. 
     Each type of drill bit is commonly used where its drilling economics are superior to the other. Roller cone drill bits can drill the entire hardness spectrum of rock formations. Thus, roller cone drill bits are generally run when encountering harder rocks where long bit life and reasonable penetration rates are important factors on the drilling economics. Fixed cutter drill bits, on the other hand, are used to drill a wide variety of formations ranging from unconsolidated and weak rocks to medium hard rocks. 
     In the case of creating a borehole with a roller cone type drill bit, several actions effecting rate of penetration (ROP) and bit efficiency may be occurring. The roller cone bit teeth may be cutting, milling, pulverizing, scraping, shearing, sliding over, indenting, and fracturing the formation the bit is encountering. The desired result is that formation cuttings or chips are generated and circulated to the surface by the drilling fluid. Other factors may also affect ROP, including formation structural or rock properties, pore pressure, temperature, and drilling fluid density. When a typical roller cone rock bit tooth presses upon a very hard, dense, deep formation, the tooth point may only penetrate into the rock a very small distance, while also at least partially, plastically “working” the rock surface. 
     One attempt to increase the effective rate of penetration (ROP) involved high-pressure circulation of a drilling fluid as a foundation for potentially increasing ROP. It is common knowledge that hydraulic power available at the rig site vastly outweighs the power available to be employed mechanically at the drill bit. For example, modern drilling rigs capable of drilling a deep well typically have in excess of 3000 hydraulic horsepower available and can have in excess of 6000 hydraulic horsepower available while less than one-tenth of that hydraulic horsepower may be available at the drill bit. Mechanically, there may be less than 100 horsepower available at the bit/rock interface with which to mechanically drill the formation. 
     An additional attempt to increase ROP involved incorporating entrained abrasives in conjunction with high pressure drilling fluid (“mud”). This resulted in an abrasive laden, high velocity jet assisted drilling process. Work done by Gulf Research and Development disclosed the use of abrasive laden jet streams to cut concentric grooves in the bottom of the hole leaving concentric ridges that are then broken by the mechanical contact of the drill bit. Use of entrained abrasives in conjunction with high drilling fluid pressures caused accelerated erosion of surface equipment and an inability to control drilling mud density, among other issues. Generally, the use of entrained abrasives was considered practically and economically unfeasible. This work was summarized in the last published article titled “Development of High Pressure Abrasive-Jet Drilling,” authored by John C. Fair, Gulf Research and Development. It was published in the Journal of Petroleum Technology in the May 1981 issue, pages 1379 to 1388. 
     Another effort to utilize the hydraulic horsepower available at the bit incorporated the use of ultra-high pressure jet assisted drilling. A group known as FlowDril Corporation was formed to develop an ultra-high-pressure liquid jet drilling system in an attempt to increase the rate of penetration. The work was based upon U.S. Pat. No. 4,624,327 and is documented in the published article titled “Laboratory and Field Testing of an Ultra-High Pressure, Jet-Assisted Drilling System” authored by J. J. Kolle, Quest Integrated Inc., and R. Otta and D. L. Stang, FlowDril Corporation; published by SPE/IADC Drilling Conference publications paper number 22000. The cited publication disclosed that the complications of pumping and delivering ultra-high-pressure fluid from surface pumping equipment to the drill bit proved both operationally and economically unfeasible. 
     Another effort at increasing rates of penetration by taking advantage of hydraulic horsepower available at the bit is disclosed in U.S. Pat. No. 5,862,871. This development employed the use of a specialized nozzle to excite normally pressured drilling mud at the drill bit. The purpose of this nozzle system was to develop local pressure fluctuations and a high speed, dual jet form of hydraulic jet streams to more effectively scavenge and clean both the drill bit and the formation being drilled. It is believed that these hydraulic jets were able to penetrate the fracture plane generated by the mechanical action of the drill bit in a much more effective manner than conventional jets were able to do. ROP increases from 50% to 400% were field demonstrated and documented in the field reports titled “DualJet Nozzle Field Test Report-Security DBS/Swift Energy Company,” and “DualJet Nozzle Equipped M-1LRG Drill Bit Run”. The ability of the dual jet (“DualJet”) nozzle system to enhance the effectiveness of the drill bit action to increase the ROP required that the drill bits first initiate formation indentations, fractures, or both. These features could then be exploited by the hydraulic action of the DualJet nozzle system. 
     Due at least partially to the effects of overburden pressure, formations at deeper depths may be inherently tougher to drill due to changes in formation pressures and rock properties, including hardness and abrasiveness. Associated in-situ forces, rock properties, and increased drilling fluid density effects may set up a threshold point at which the drill bit drilling mechanics decrease the drilling efficiency. 
     Another factor adversely effecting ROP in formation drilling, especially in plastic type rock drilling, such as shale or permeable formations, is a build-up of hydraulically isolated crushed rock material, that can become either mass of reconstituted drill cuttings or a “dynamic filtercake”, on the surface being drilled, depending on the formation permeability In the case of low permeability formations, this occurrence is predominantly a result of repeated impacting and re-compacting of previously drilled particulate material on the bottom of the hole by the bit teeth, thereby forming a false bottom. The substantially continuous process of drilling, re-compacting, removing, re-depositing and re-compacting, and drilling new material may significantly adversely effect drill bit efficiency and ROP. The re-compacted material is at least partially removed by mechanical displacement due to the cone skew of the roller cone type drill bits and partially removed by hydraulics, again emphasizing the importance of good hydraulic action and hydraulic horsepower at the bit. For hard rock bits, build-up removal by cone skew is typically reduced to near zero, which may make build-up removal substantially a function of hydraulics. In permeable formations the continuous deposition and removal of the fine cuttings forms a dynamic filtercake that can reduce the spurt loss and therefore the pore pressure in the working area of the bit. Because the pore pressure is reduced and mechanical load is increased from the pressure drop across the dynamic filtercake, drilling efficiency can be reduced. 
     Disclosed herein is a system for excavating a borehole through a subterranean formation. In one embodiment the system comprises a supply of pressurized fluid mixed with impactors. The impactors may have an average mean diameter of about 0.10 inches. The system of this embodiment includes a drill string in a borehole in communication with the pressurized mixture with a drill bit on its lower end. Nozzles are included on the bit that communicate with the pressurized fluid and impactors mixture from the drill string and are oriented to direct the mixture into excavating contact with the borehole. The drill bit includes a first junk slot formed on a lateral side, the first junk slot is configured so that impactors that rebound from the borehole bottom into and through the junk slot. Optionally, the drill bit can have a second junk slot and wherein at least one nozzle is oriented so that impactors exiting that nozzle contact the borehole bottom surface and rebound into the first junk slot and wherein at least one nozzle is oriented so that impactors exiting that nozzle contact the borehole bottom surface and rebound into the second junk slot. The system may further include a pump with an outlet having the pressurized fluid exiting the outlet, and a supply line connected between the pump outlet and the drill string. An impactor supply may be included in the system that discharges impactors into the supply line. The impactors can be substantially spherical, substantially non-abrasive, and substantially rigid. A substantial portion of the impactors exiting the nozzles have a minimum average kinetic energy so that contacting the formation with the impactors compresses the formation to fracture and structurally alter the formation. Cutting fragments broken from the formation by the impactors&#39; contact can flow through the first junk slot and/or the second junk slot, with the slurry and impactors that rebound from the formation surface. At least one nozzle may be oriented to discharge from the bit bottom, so that rotating the bit excavates a region of the borehole bottom adjacent the borehole outer circumference and wherein at least one nozzle is oriented to discharge from the bit bottom so that rotating the bit excavates a region of the borehole bottom adjacent the borehole axis thereby forms a rock ring on the borehole bottom. Included with the bit of this embodiment are arms projecting from the bit and cutters on the arms, so that rotatingly contacting the rock ring with the arms fractures the rock ring. 
     Also included herein is an alternative borehole excavating system. This embodiment includes a pump discharging pressurized circulating fluid, a supply line with an inlet connected to the pump discharge and an outlet in fluid communication with a drill string disposed in a borehole, a supply of impactors with diameters ranging up to about 0.10 inches, an impactor injection defined by the impactors flowing into the supply line so that a mixture of circulating fluid and impactors flows in the supply line towards the drill string downstream of the impactor injection, a drill bit in the borehole on the drill string end, nozzles on the drill bit aimed at the borehole bottom and in fluid communication with the drill string to thereby receive the mixture of circulating fluid and impactors and direct the mixture into excavating contact with the borehole bottom, and junk slots on the drill bit lateral side, so that the impactors rebounding from the borehole bottom pass through the junk slots. 
     Disclosed herein is a method of excavating a borehole through a subterranean formation. The method includes providing an annular drill string in the borehole, the drill string having a drill bit, a junk slot on a lateral side of the drill bit, and nozzles on the drill bit lower end that are in fluid communication with the drill string annulus. This method further includes forming a mixture of pressurized fluid and impactors having diameters ranging up to about 0.10 inches, directing the mixture to the drill string annulus so that the mixture flows to the drill bit and exits the nozzles, and orienting the drill bit in the borehole so that the impactors in the mixture contact the formation and rebound upwards from the formation into the junk slot. A rock ring is formable with the drill bit by discharging the mixture from the nozzles in concentric circular patterns. The rock ring can be fractured by compressive contact with the drill bit. Contacting the formation with the impactors compresses the formation to fracture and structurally alter the formation to thereby excavate the borehole. 
    
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
       For a more detailed description of the embodiments, reference will now be made to the following accompanying drawings: 
         FIG. 1  is an isometric view of an excavation system as used in a preferred embodiment; 
         FIG. 2  illustrates an impactor impacted with a formation; 
         FIG. 3  illustrates an impactor embedded into the formation at an angle to a normalized surface plane of the target formation; and 
         FIG. 4  illustrates an impactor impacting a formation with a plurality of fractures induced by the impact. 
         FIG. 5  is a side partial section view of a drill string with drill bit excavating a borehole. 
         FIG. 6  is an overhead view of a rock ring formed on the borehole bottom. 
         FIGS. 7-8  illustrate embodiments of the drill bit of  FIG. 5  in upward looking perspective views. 
         FIGS. 9-11  illustrate embodiments of the drill bit of  FIG. 5  in side perspective views. 
         FIGS. 12-13  illustrate embodiments of the drill bit of  FIG. 5  in overhead perspective views. 
         FIG. 14  illustrates a perspective partial sectional view of a drill bit using impactors to excavate a borehole. 
         FIG. 15  provides example drill bit nozzle orientations. 
         FIGS. 16 and 17  are side sectional views respectively depicting forming and fracturing a rock ring. 
     
    
    
     DETAILED DESCRIPTION OF THE EMBODIMENTS 
     In the drawings and description that follows, like parts are marked throughout the specification and drawings with the same reference numerals, respectively. The drawing figures are not necessarily to scale. Certain features of the invention may be shown exaggerated in scale or in somewhat schematic form and some details of conventional elements may not be shown in the interest of clarity and conciseness. The present invention is susceptible to embodiments of different forms. Specific embodiments are described in detail and are shown in the drawings, with the understanding that the present disclosure is to be considered an exemplification of the principles of the invention, and is not intended to limit the invention to that illustrated and described herein. It is to be fully recognized that the different teachings of the embodiments discussed below may be employed separately or in any suitable combination to produce desired results. The various characteristics mentioned above; as well as other features and characteristics described in more detail below, will be readily apparent to those skilled in the art upon reading the following detailed description of the embodiments, and by referring to the accompanying drawings. 
       FIGS. 1 and 2  illustrate an embodiment of an excavation system  1  comprising the use of solid material impactors  100  to engage and excavate a subterranean formation  52  to create a wellbore  70 . The excavation system  1  may comprise a pipe string  55  comprised of collars  58 , pipe  56 , and a kelly  50 . An upper end of the kelly  50  may interconnect with a lower end of a swivel quill  26 . An upper end of the swivel quill  26  may be rotatably interconnected with a swivel  28 . The swivel  28  may include a top drive assembly (not shown) to rotate the pipe string  55 . Alternatively, the excavation system  1  may further comprise a drill bit  60  to cut the formation  52  in cooperation with the solid material impactors  100 . The drill bit  60  may be attached to one end of the pipe string  55  and may engage a bottom surface  66  of the wellbore  70 . The drill bit  60  may be a roller cone bit, a fixed cutter bit, an impact bit, a spade bit, a mill, an impregnated bit, a natural diamond bit, or other suitable implement for cutting rock or earthen formation. Referring to  FIG. 1 , the pipe string  55  may include a feed end  210  located substantially near the excavation rig  5  and a nozzle end  215  including a nozzle  64  supported thereon. The nozzle end  215  may be a bit end  215  and may include the drill bit  60  supported thereon. The excavation system  1  is not limited to excavating a wellbore  70 . The excavation system and method may also be applicable to excavating a tunnel, a pipe chase, a mining operation, or other excavation operation wherein earthen material or formation may be removed. 
     To excavate the wellbore  70 , the swivel  28 , the swivel quill  26 , the kelly  50 , the pipe string  55 , and a portion of the drill bit  60 , if used, may each include an interior passage that allows circulation fluid to circulate through each of the aforementioned components. The circulation fluid may be withdrawn from a tank  6 , pumped by a pump  2 , through a through medium pressure capacity line  8 , through a medium pressure capacity flexible hose  42 , through a gooseneck  36 , through the swivel  28 , through the swivel quill  26 , through the kelly  50 , through the pipe string  55 , and through the bit  60 . 
     The excavation system  1  further comprises at least one nozzle  64  on the end  215  of the pipe string  55  for accelerating at least one solid material impactor  100  as they exit the pipe string  100 . The nozzle  64  is designed to accommodate the impactors  100 , such as an especially hardened nozzle, a shaped nozzle, or an “impactor” nozzle, which may be particularly adapted to a particular application. The nozzle  64  may be a type that is known and commonly available. The nozzle  64  may further be selected to accommodate the impactors  100  in a selected size range or of a selected material composition. Nozzle size, type, material, and quantity may be a function of the formation being cut, fluid properties, impactor properties, and/or desired hydraulic energy expenditure at the nozzle  64 . For example, the nozzle  64  may be a nozzle such as one described in U.S. patent application Ser. No. 10/825,338, filed Apr. 15, 2004 and entitled “Drill Bit”, hereby incorporated herein by reference for all purposes. If a drill bit  60  is used, the nozzle or nozzles  64  may be located in the drill bit  60 . 
     The nozzle  64  may alternatively be of a dual-discharge nozzle, such as the dual jet nozzle described in U.S. Pat. No. 5,862,871, hereby incorporated herein by reference for all purposes. Such dual discharge nozzles may generate: (1) a radially outer circulation fluid jet substantially encircling a jet axis, and/or (2) an axial circulation fluid jet substantially aligned with and coaxial with the jet axis, with the dual discharge nozzle directing a majority by weight of the plurality of solid material impactors into the axial circulation fluid jet. A dual discharge nozzle  64  may separate a first portion of the circulation fluid flowing through the nozzle  64  into a first circulation fluid stream having a first circulation fluid exit nozzle velocity, and a second portion of the circulation fluid flowing through the nozzle  64  into a second circulation fluid stream having a second circulation fluid exit nozzle velocity lower than the first circulation fluid exit nozzle velocity. The plurality of solid material impactors  100  may be directed into the first circulation fluid stream such that a velocity of the plurality of solid material impactors  100  while exiting the nozzle  64  is substantially greater than a velocity of the circulation fluid while passing through a nominal diameter flow path in the end  215  of the pipe string  55 , to accelerate the solid material impactors  100 . 
     Each of the individual impactors  100  is structurally independent from the other impactors. For brevity, the plurality of solid material impactors  100  may be interchangeably referred to as simply the impactors  100 . The plurality of solid material impactors  100  may be substantially rounded and have either a substantially non-uniform outer diameter or a substantially uniform outer diameter. The solid material impactors  100  may be substantially spherically shaped, non-hollow, formed of rigid metallic material, and having high compressive strength and crush resistance, such as steel shot, ceramics, depleted uranium, and multiple component materials. Although the solid material impactors  100  may be substantially a non-hollow sphere, alternative embodiments may provide for other types of solid material impactors, which may include impactors  100  with a hollow interior. The impactors may be substantially rigid and may possess relatively high compressive strength and resistance to crushing or deformation as compared to physical properties or rock properties of a particular formation or group of formations being penetrated by the wellbore  70 . 
     The impactors may be of a substantially uniform mass, grading, or size. The solid material impactors  100  may have any suitable density for use in the excavation system  1 . For example, the solid material impactors  100  may have an average density of at least 470 pounds per cubic foot. 
     The excavation system  1  further comprises at least one nozzle  64  on the end  215  of the pipe string  55  for accelerating at least one solid material impactor  100  as they exit the pipe string  100 . The nozzle  64  is designed to accommodate the impactors  100 , such as an especially hardened nozzle, a shaped nozzle, or an “impactor” nozzle, which may be particularly adapted to a particular application. The nozzle  64  may be a type that is known and commonly available. The nozzle  64  may further be selected to accommodate the impactors  100  in a selected size range or of a selected material composition. Nozzle size, type, material, and quantity may be a function of the formation being cut, fluid properties, impactor properties, and/or desired hydraulic energy expenditure at the nozzle  64 . For example, the nozzle  64  may be a nozzle such as one described in U.S. Pat. No. 7,258,176 issued Aug. 21, 2007 from U.S. patent application Ser. No. 10/825,338, filed Apr. 15, 2004 and entitled “Drill Bit”, hereby incorporated herein by reference for all purposes. If a drill bit  60  is used, the nozzle or nozzles  64  may be located in the drill bit  60 . 
     The impactors  100  may be selectively introduced into a fluid circulation system, such as illustrated in  FIG. 1 , near an excavation rig  5 , circulated with the circulation fluid (or “mud”), and accelerated through at least one nozzle  64 . “At the excavation rig” or “near an excavation rig” may also include substantially remote separation, such as a separation process that may be at least partially carried out on the sea floor. 
     Introducing the impactors  100  into the circulation fluid may be accomplished by any of several known techniques. For example, the impactors  100  may be provided in an impactor storage tank  94  near the rig  5  or in a storage bin  82 . A screw elevator  14  may then transfer a portion of the impactors at a selected rate from the storage tank  94 , into a slurrification tank  98 . A pump  10 , such as a progressive cavity pump may transfer a selected portion of the circulation fluid from a mud tank  6 , into the slurrification tank  98  to be mixed with the impactors  100  in the tank  98  to form an impactor concentrated slurry. An impactor introducer  96  may be included to pump or introduce a plurality of solid material impactors  100  into the circulation fluid before circulating a plurality of impactors  100  and the circulation fluid to the nozzle  64 . The impactor introducer  96  may be a progressive cavity pump capable of pumping the impactor concentrated slurry at a selected rate and pressure through a slurry line  88 , through a slurry hose  38 , through an impactor slurry injector head  34 , and through an injector port  30  located on the gooseneck  36 , which may be located atop the swivel  28 . The swivel  36 , including the through bore for conducting circulation fluid therein, may be substantially supported on the feed end  210  of the pipe string  55  for conducting circulation fluid from the gooseneck  36  into the feed end  210  of the pipe string  55 . The feed end  210  of the pipe string  55  may also include the kelly  50  to connect the pipe  56  with the swivel quill  26  and/or the swivel  28 . The circulation fluid may also be provided with rheological properties sufficient to adequately transport and/or suspend the plurality of solid material impactors  100  within the circulation fluid. 
     The solid material impactors  100  may also be introduced into the circulation fluid by withdrawing the plurality of solid material impactors  100  from a low pressure impactor source  98  into a high velocity stream of circulation fluid, such as by venturi effect. For example, when introducing impactors  100  into the circulation fluid, the rate of circulation fluid pumped by the mud pump  2  may be reduced to a rate lower than the mud pump  2  is capable of efficiently pumping. In such event, a lower volume mud pump  4  may pump the circulation fluid through a medium pressure capacity line  24  and through the medium pressure capacity flexible hose  40 . 
     The circulation fluid may be circulated from the fluid pump  2  and/or  4 , such as a positive displacement type fluid pump, through one or more fluid conduits  8 ,  24 ,  40 ,  42 , into the feed end  210  of the pipe string  55 . The circulation fluid may then be circulated through the pipe string  55  and through the nozzle  64 . The circulation fluid may be pumped at a selected circulation rate and/or a selected pump pressure to achieve a desired impactor and/or fluid energy at the nozzle  64 . 
     The pump  4  may also serve as a supply pump to drive the introduction of the impactors  100  entrained within an impactor slurry, into the high pressure circulation fluid stream pumped by mud pumps  2  and  4 . Pump  4  may pump a percentage of the total rate of fluid being pumped by both pumps  2  and  4 , such that the circulation fluid pumped by pump  4  may create a venturi effect and/or vortex within the injector head  34  that inducts the impactor slurry being conducted through the line  42 , through the injector head  34 , and then into the high pressure circulation fluid stream. 
     From the swivel  28 , the slurry of circulation fluid and impactors may circulate through the interior passage in the pipe string  55  and through the nozzle  64 . As described above, the nozzle  64  may alternatively be at least partially located in the drill bit  60 . Each nozzle  64  may include a reduced inner diameter as compared to an inner diameter of the interior passage in the pipe string  55  immediately above the nozzle  64 . Thereby, each nozzle  64  may accelerate the velocity of the slurry as the slurry passes through the nozzle  64 . The nozzle  64  may also direct the slurry into engagement with a selected portion of the bottom surface  66  of wellbore  70 . The nozzle  64  may also be rotated relative to the formation  52  depending on the excavation parameters. To rotate the nozzle  64 , the entire pipe string  55  may be rotated or only the nozzle  64  on the end of the pipe string  55  may be rotated while the pipe string  55  is not rotated. Rotating the nozzle  64  may also include oscillating the nozzle  64  rotationally back and forth as well as vertically, and may further include rotating the nozzle  64  in discrete increments. The nozzle  64  may also be maintained rotationally substantially stationary. 
     The circulation fluid may be substantially continuously circulated during excavation operations to circulate at least some of the plurality of solid material impactors  100  and the formation cuttings away from the nozzle  64 . The impactors  100  and fluid circulated away from the nozzle  64  may be circulated substantially back to the excavation rig  5 , or circulated to a substantially intermediate position between the excavation rig  5  and the nozzle  64 . 
     If a drill bit  60  is used, the drill bit  60  may be rotated relative to the formation  52  and engaged therewith by an axial force (WOB) acting at least partially along the wellbore axis  75  near the drill bit  60 . The bit  60  may also comprise a plurality of bit cones  62 , which also may rotate relative to the bit  60  to cause bit teeth secured to a respective cone to engage the formation  52 , which may generate formation cuttings substantially by crushing, cutting, or pulverizing a portion of the formation  52 . The bit  60  may also be comprised of a fixed cutting structure that may be substantially continuously engaged with the formation  52  and create cuttings primarily by shearing and/or axial force concentration to fail the formation, or create cuttings from the formation  52 . To rotate the bit  60 , the entire pipe string  55  may be rotated or only the bit  60  on the end of the pipe string  55  may be rotated while the pipe string  55  is not rotated. Rotating the drill bit  60  may also include oscillating the drill bit  60  rotationally back and forth as well as vertically, and may further include rotating the drill bit  60  in discrete increments. 
     Also alternatively, the excavation system  1  may comprise a pump, such as a centrifugal pump, having a resilient lining that is compatible for pumping a solid-material laden slurry. The pump may pressurize the slurry to a pressure greater than the selected mud pump pressure to pump the plurality of solid material impactors  100  into the circulation fluid. The impactors  100  may be introduced through an impactor injection port, such as port  30 . Other alternative embodiments for the system  1  may include an impactor injector for introducing the plurality of solid material impactors  100  into the circulation fluid. 
     As the slurry is pumped through the pipe string  55  and out the nozzles  64 , the impactors  100  may engage the formation with sufficient energy to enhance the rate of formation removal or penetration (ROP). The removed portions of the formation may be circulated from within the wellbore  70  near the nozzle  64 , and carried suspended in the fluid with at least a portion of the impactors  100 , through a wellbore annulus between the OD of the pipe string  55  and the ID of the wellbore  70 . 
     At the excavation rig  5 , the returning slurry of circulation fluid, formation fluids (if any), cuttings, and impactors  100  may be diverted at a nipple  76 , which may be positioned on a BOP stack  74 . The returning slurry may flow from the nipple  76 , into a return flow line  15 , which maybe comprised of tubes  48 ,  45 ,  16 ,  12  and flanges  46 ,  47 . The return line  15  may include an impactor reclamation tube assembly  44 , as illustrated in  FIG. 1 , which may preliminarily separate a majority of the returning impactors  100  from the remaining components of the returning slurry to salvage the circulation fluid for recirculation into the present wellbore  70  or another wellbore. At least a portion of the impactors  100  may be separated from a portion of the cuttings by a series of screening devices, such as the vibrating classifiers  84 , to salvage a reusable portion of the impactors  100  for reuse to re-engage the formation  52 . A majority of the cuttings and a majority of non-reusable impactors  100  may also be discarded. 
     The reclamation tube assembly  44  may operate by rotating tube  45  relative to tube  16 . An electric motor assembly  22  may rotate tube  44 . The reclamation tube assembly  44  comprises an enlarged tubular  45  section to reduce the return flow slurry velocity and allow the slurry to drop below a terminal velocity of the impactors  100 , such that the impactors  100  can no longer be suspended in the circulation fluid and may gravitate to a bottom portion of the tube  45 . This separation function may be enhanced by placement of magnets near and along a lower side of the tube  45 . The impactors  100  and some of the larger or heavier cuttings may be discharged through discharge port  20 . The separated and discharged impactors  100  and solids discharged through discharge port  20  may be gravitationally diverted into a vibrating classifier  84  or may be pumped into the classifier  84 . A pump (not shown) capable of handling impactors and solids, such as a progressive cavity pump may be situated in communication, with the flow line discharge port  20  to conduct the separated impactors  100  selectively into the vibrating separator  84  or elsewhere in the circulation fluid circulation system. 
     The vibrating classifier  84  may comprise a three-screen section classifier of which screen section  18  may remove the coarsest grade material. The removed coarsest grade material may be selectively directed by outlet  78  to one of storage bin  82  or pumped back into the flow line  15  downstream of discharge port  20 . A second screen section  92  may remove a re-usable grade of impactors  100 , which in turn may be directed by outlet  90  to the impactor storage tank  94 . A third screen section  86  may remove the finest grade material from the circulation fluid. The removed finest grade material may be selectively directed by outlet  80  to storage bin  82 , or pumped back into the flow line  15  at a point downstream of discharge port  20 . Circulation fluid collected in a lower portion of the classified  84  may be returned to a mud tank  6  for re-use. 
     The circulation fluid may be recovered for recirculation in a wellbore or the circulation fluid may be a fluid that is substantially not recovered. The circulation fluid may be a liquid, gas, foam, mist, or other substantially continuous or multiphase fluid. For recovery, the circulation fluid and other components entrained within the circulation fluid may be directed across a shale shaker (not shown) or into a mud tank  6 , whereby the circulation fluid may be further processed for re-circulation into a wellbore. 
     The excavation system  1  creates a mass-velocity relationship in a plurality of the solid material impactors  100 , such that an impactor  100  may have sufficient energy to structurally alter the formation  52  in a zone of a point of impact. The mass-velocity relationship may be satisfied as sufficient when a substantial portion by weight of the solid material impactors  100  may by virtue of their mass and velocity at the exit of the nozzle  64 , create a structural alteration as claimed or disclosed herein. Impactor velocity to achieve a desired effect upon a given formation may vary as a function of formation compressive strength, hardness, or other rock properties, and as a function of impactor size and circulation fluid rheological properties. A substantial portion means at least five percent by weight of the plurality of solid material impactors that are introduced into the circulation fluid. 
     The impactors  100  for a given velocity and mass of a substantial portion by weight of the impactors  100  are subject to the following mass-velocity relationship. The resulting kinetic energy of at least one impactor  100  exiting a nozzle  64  is at least 0.075 Ft.Lbs or has a minimum momentum of 0.0003 Lbf.Sec. 
     Kinetic energy is quantified by the relationship of an object&#39;s mass and its velocity. The quantity of kinetic energy associated with an object is calculated by multiplying its mass times its velocity squared. To reach a minimum value of kinetic energy in the mass-velocity relationship as defined, small particles such as those found in abrasives and grits, must have a significantly high velocity due to the small mass of the particle. A large particle, however, needs only moderate velocity to reach an equivalent kinetic energy of the small particle because its mass may be several orders of magnitude larger. 
     The velocity of a substantial portion by weight of the plurality of solid material impactors  100  immediately exiting a nozzle  64  may be as slow as 100 feet per second and as fast as 1000 feet per second, immediately upon exiting the nozzle  64 . 
     The velocity of a majority by weight of the impactors  100  may be substantially the same, or only slightly reduced, at the point of impact of an impactor  100  at the formation surface  66  as compared to when leaving the nozzle  64 . Thus, it may be appreciated by those skilled in the art that due to the close proximity of a nozzle  64  to the formation being impacted, the velocity of a majority of impactors  100  exiting a nozzle  64  may be substantially the same as a velocity of an impactor  100  at a point of impact with the formation  52 . Therefore, in many practical applications, the above velocity values may be determined or measured at substantially any point along the path between near an exit end of a nozzle  64  and the point of impact, without material deviation from the scope of this invention. 
     In addition to the impactors  100  satisfying the mass-velocity relationship described above, a substantial portion by weight of the solid material impactors  100  have an average mean diameter of equal to or less than approximately 0.100 inches. 
     To excavate a formation  52 , the excavation implement, such as a drill bit  60  or impactor  100 , must overcome minimum, in-situ stress levels or toughness of the formation  52 . These minimum stress levels are known to typically range from a few thousand pounds per square inch, to in excess of 65,000 pounds per square inch. To fracture, cut, or plastically deform a portion of formation  52 , force exerted on that portion of the formation  52  typically should exceed the minimum, in-situ stress threshold of the formation  52 . When an impactor  100  first initiates contact with a formation, the unit stress exerted upon the initial contact point may be much higher than 10,000 pounds per square inch, and may be well in excess of one million pounds per square inch. The stress applied to the formation  52  during contact is governed by the force the impactor  100  contacts the formation with and the area of contact of the impactor with the formation. The stress is the force divided by the area of contact. The force is governed by Impulse Momentum theory whereby the time at which the contact occurs determines the magnitude of the force applied to the area of contact. In cases where the particle is contacting a relatively hard surface at an elevated velocity, the force of the particle when in contact with the surface is not constant, but is better described as a spike. However, the force need not be limited to any specific amplitude or duration. The magnitude of the spike load can be very large and occur in just a small fraction of the total impact time. If the area of contact is small the unit stress can reach values many times in excess of the in situ failure stress of the rock, thus guaranteeing fracture initiation and propagation and structurally altering the formation  52 . 
     A substantial portion by weight of the solid material impactors  100  may apply at least 5000 pounds per square inch of unit stress to a formation  52  to create the structurally altered zone  124  in the formation. The structurally altered zone  124  is not limited to any specific shape or size, including depth or width. Further, a substantial portion by weight of the impactors  100  may apply in excess of 20,000 pounds per square inch of unit stress to the formation  52  to create the structurally altered zone  124  in the formation. The mass-velocity relationship of a substantial portion by weight of the plurality of solid material impactors  100  may also provide at least 30,000 pounds per square inch of unit stress. 
     A substantial portion by weight of the solid material impactors  100  may have any appropriate velocity to satisfy the mass-velocity relationship. For example, a substantial portion by weight of the solid material impactors may have a velocity of at least 100 feet per second when exiting the nozzle  64 . A substantial portion by weight of the solid material impactors  100  may also have a velocity of at least 100 feet per second and as great as 1200 feet per second when exiting the nozzle  64 . A substantial portion by weight of the solid material impactors  100  may also have a velocity of at least 100 feet per second and as great as 750 feet per second when exiting the nozzle  64 . A substantial portion by weight of the solid material impactors  100  may also have a velocity of at least 350 feet per second and as great as 500 feet per second when exiting the nozzle  64 . 
     Impactors  100  may be selected based upon physical factors such as size, projected velocity, impactor strength, formation  52  properties and desired impactor concentration in the circulation fluid. Such factors may also include; (a) an expenditure of a selected range of hydraulic horsepower across the one or more nozzles, (b) a selected range of circulation fluid velocities exiting the one or more nozzles or impacting the formation, and (c) a selected range of solid material impactor velocities exiting the one or more nozzles or impacting the formation, (d) one or more rock properties of the formation being excavated, or (e), any combination thereof. 
     If an impactor  100  is of a specific shape such as that of a dart, a tapered conic, a rhombic, an octahedral, or similar oblong shape, a reduced impact area to impactor mass ratio may be achieved. The shape of a substantial portion by weight of the impactors  100  may be altered, so long as the mass-velocity relationship remains sufficient to create a claimed structural alteration in the formation and an impactor  100  does not have any one length or diameter dimension greater than approximately 0.100 inches. Thereby, a velocity required to achieve a specific structural alteration may be reduced as compared to achieving a similar structural alteration by impactor shapes having a higher impact area to mass ratio. Shaped impactors  100  may be formed to substantially align themselves along a flow path, which may reduce variations in the angle of incidence between the impactor  100  and the formation  52 . Such impactor shapes may also reduce impactor contact with the flow structures such those in the pipe string  55  and the excavation rig  5  and may thereby minimize abrasive erosion of flow conduits. 
     Referring to  FIGS. 1-4 , a substantial portion by weight of the impactors  100  may engage the formation  52  with sufficient energy to enhance creation of a wellbore  70  through the formation  52  by any or a combination of different impact mechanisms. First, an impactor  100  may directly remove a larger portion of the formation  52  than may be removed by abrasive-type particles. In another mechanism, an impactor  100  may penetrate into the formation  52  without removing formation material from the formation  52 . A plurality of such formation penetrations, such as near and along an outer perimeter of the wellbore  70  may relieve a portion of the stresses on a portion of formation being excavated, which may thereby enhance the excavation action of other impactors  100  or the drill bit  60 . Third, an impactor  100  may alter one or more physical properties of the formation  52 . Such physical alterations may include creation of micro-fractures and increased brittleness in a portion of the formation  52 , which may thereby enhance effectiveness the impactors  100  in excavating the formation  52 . The constant scouring of the bottom of the borehole also prevents the build up of dynamic filtercake, which can significantly increase the apparent toughness of the formation  52 . 
       FIG. 2  illustrates an impactor  100  that has been impaled into a formation  52 , such as a lower surface  66  in a wellbore  70 . For illustration purposes, the surface  66  is illustrated as substantially planar and transverse to the direction of impactor travel  130 . The impactors  100  circulated through a nozzle  64  may engage the formation  52  with sufficient energy to effect one or more properties of the formation  52 . 
     A portion of the formation  52  ahead of the impactor  100  substantially in the direction of impactor travel  130  may be altered such as by micro-fracturing and/or thermal alteration due to the impact energy. In such occurrence, the structurally altered zone  124  may include an altered zone depth  132 . An example of a structurally altered zone  124  is a compressive zone  102 , which may be a zone in the formation  52  compressed by the impactor  100 . The compressive zone  102  may have a length  134 , but is not limited to any specific shape or size. The compressive zone  102  may be thermally altered due to impact energy. 
     An additional example of a structurally altered zone  124  near a point of impaction may be a zone of micro-fractures  106 . The structurally altered zone  124  may be broken or otherwise altered due to the impactor  100  and/or a drill bit  60 , such as by crushing, fracturing, or micro-fracturing  106 . 
       FIG. 2  also illustrates an impactor  100  implanted into a formation  52  and having created an excavation  120  wherein material has been ejected from or crushed beneath the impactor  100 . Thereby an excavation may be created, which as illustrated in  FIG. 3  may generally conform to the shape of the impactor  100 .  FIGS. 3 and 4  illustrate excavations  120  where the size of the excavation  120  may be larger than the size of the impactor  100 . In  FIG. 2 , the impactor  100  is shown as impacted into the formation  52  yielding an excavation depth  109 . 
     An additional theory for impaction mechanics in cutting a formation  52  may postulate that certain formations  52  may be highly fractured or broken up by impactor energy.  FIG. 4  illustrates an interaction between an impactor  100  and a formation  52 . A plurality of fractures  116  and micro-fractures  106  may be created in the formation  52  by impact energy. 
     An impactor  100  may penetrate a small distance into the formation  52  and cause the displaced or structurally altered formation  52  to “splay out” or be reduced to small enough particles for the particles to be removed or washed away by hydraulic action. Hydraulic particle removal may depend at least partially upon available hydraulic horsepower and at least partially upon particle wet-ability and viscosity. Such formation deformation may be a basis for fatigue failure of a portion of the formation by “impactor contact,” as the plurality of solid material impactors  100  may displace formation material back and forth. 
     Each nozzle  64  may be selected to provide a desired circulation fluid circulation rate, hydraulic horsepower substantially at the nozzle  64 , and/or impactor energy or velocity when exiting the nozzle  64 . Each nozzle  64  may be selected as a function of at least one of (a) an expenditure of a selected range of hydraulic horsepower across the one or more nozzles  64 , (b) a selected range of circulation fluid velocities exiting the one or more nozzles  64 , and (c) a selected range of solid material impactor  100  velocities exiting the one or more nozzles  64 . 
     To optimize ROP, it may be desirable to determine, such as by monitoring, observing, calculating, knowing, or assuming one or more excavation parameters such that adjustments may be made in one or more controllable variables as a function of the determined or monitored excavation parameter. The one or more excavation parameters may be selected from a group comprising: (a) a rate of penetration into the formation  52 , (b) a depth of penetration into the formation  52 , (c) a formation excavation factor, and (d) the number of solid material impactors  100  introduced into the circulation fluid per unit of time. Monitoring or observing may include monitoring or observing one or more excavation parameters of a group of excavation parameters comprising: (a) rate of nozzle rotation, (b) rate of penetration into the formation  52 , (c) depth of penetration into the formation  52 , (d) formation excavation factor, (e) axial force applied to the drill bit  60 , (f) rotational force applied to the bit  60 , (g) the selected circulation rate, (h) the selected pump pressure, and/or (i) wellbore fluid dynamics, including pore pressure. 
     One or more controllable variables or parameters, may be altered, including at least one of (a) rate of impactor  100  introduction into the circulation fluid, (b) impactor  100  size, (c) impactor  100  velocity, (d) drill bit nozzle  64  selection, (e) the selected circulation rate of the circulation fluid, (f) the selected pump pressure, and (g) any of the monitored excavation parameters. 
     To alter the rate of impactors  100  engaging the formation  52 , the rate of impactor  100  introduction into the circulation fluid may be altered. The circulation fluid circulation rate may also be altered independent from the rate of impactor  100  introduction. Thereby, the concentration of impactors  100  in the circulation fluid may be adjusted separate from the fluid circulation rate. Introducing a plurality of solid material impactors  100  into the circulation fluid may be a function of impactor  100  size, circulation fluid rate, nozzle rotational speed, wellbore  70  size, and a selected impactor  100  engagement rate with the formation  52 . The impactors  100  may also be introduced into the circulation fluid intermittently during the excavation operation. The rate of impactor  100  introduction relative to the rate of circulation fluid circulation may also be adjusted or interrupted as desired. 
     The plurality of solid material impactors  100  may be introduced into the circulation fluid at a selected introduction rate and/or concentration to circulate the plurality of solid material impactors  100  with the circulation fluid through the nozzle  64 . The selected circulation rate and/or pump pressure, and nozzle selection may be sufficient to expend a desired portion of energy or hydraulic horsepower in each of the circulation fluid and the impactors  100 . 
     An example of an operative excavation system  1  may comprise a bit  60  with an 8½″ bit diameter. The solid material impactors  100  may be introduced into the circulation fluid at a rate of 12 gallons per minute. The circulation fluid containing the solid material impactors may be circulated through the bit  60  at a rate of 462 gallons per minute. A substantial portion by weight of the solid material impactors may have an average mean diameter of 0.100″. The following parameters will result in approximately a 27 feet per hour penetration rate into Sierra White Granite. In this example, the excavation system  1  may produce 1413 solid material impactors  100  per cubic inch with approximately 3.9 million impacts per minute against the formation  52 . On average, 0.00007822 cubic inches of the formation  52  are removed per impactor  100  impact. The resulting exit velocity of a substantial portion of the impactors  100  from each of the nozzles  64  would average 495.5 feet per second. The kinetic energy of a substantial portion by weight of the solid material impacts  100  would be approximately 1.14 Ft Lbs., thus satisfying the mass-velocity relationship described above. 
     Another example of an operative excavation system  1  may comprise a bit  60  with an 8½″ bit diameter. The solid material impactors  100  may be introduced into the circulation fluid at a rate of 12 gallons per minute. The circulation fluid containing the solid material impactors may be circulated through the nozzle  64  at a rate of 462 gallons per minute. A substantial portion by weight of the solid material impactors may have an average mean diameter of 0.075″. The following parameters will result in approximately a 35 feet per hour penetration rate into Sierra White Granite. In this example, the excavation system  1  may produce 3350 solid material impactors  100  per cubic inch with approximately 9.3 million impacts per minute against the formation  52 . On average, 0.0000428 cubic inches of the formation  52  are removed per impactor  100  impact. The resulting exit velocity of a substantial portion of the impactors  100  from each of the nozzles  64  would average 495.5 feet per second. The kinetic energy of a substantial portion by weight of the solid material impacts  100  would be approximately 0.240 Ft Lbs., thus satisfying the mass-velocity relationship described above. 
     In addition to impacting the formation with the impactors  100 , the bit  60  may be rotated while circulating the circulation fluid and engaging the plurality of solid material impactors  100  substantially continuously or selectively intermittently. The nozzle  64  may also be oriented to cause the solid material impactors  100  to engage the formation  52  with a radially outer portion of the bottom hole surface  66 . Thereby, as the drill bit  60  is rotated, the impactors  100 , in the bottom hole surface  66  ahead of the bit  60 , may create one or more circumferential kerfs. The drill bit  60  may thereby generate formation cuttings more efficiently due to reduced stress in the surface  66  being excavated, due to the one or more substantially circumferential kerfs in the surface  66 . 
     The excavation system  1  may also include inputting pulses of energy in the fluid system sufficient to impart a portion of the input energy in an impactor  100 . The impactor  100  may thereby engage the formation  52  with sufficient energy to achieve a structurally altered zone  124 . Pulsing of the pressure of the circulation fluid in the pipe string  55 , near the nozzle  64  also may enhance the ability of the circulation fluid to generate cuttings subsequent to impactor  100  engagement with the formation  52 . 
       FIG. 5  shows a first embodiment of a drill bit  322  at the bottom of a well bore  324  and attached to a drill string  320 . The drill bit  322  acts upon a bottom surface  327  of the well bore  324 . The drill string  320  has a central passage  332  that supplies drilling fluids  340  to the drill bit  322 . The drill bit  322  uses the drilling fluids  340  aid solid material impactors when acting upon the bottom surface  327  of the well bore  324 . The solid material impactors reduce bit balling and bottom balling by contacting the bottom surface  327  of the well bore  324  with the solid material impactors. The solid material impactors may be used for any type of contacting of the bottom surface  327  of the well bore  324 , whether it be abrasion-type drilling, impact-type drilling, or any other drilling using solid material impactors. The drilling fluids  340  that have been used by the drill bit  322  on the bottom surface  327  of the well bore  324  exit the well bore  324  through a well bore annulus  324  between the drill string  320  and the inner wall  326  of the well bore  324 . Particles of the bottom surface  327  removed by the drill bit  322  exit the well bore  324  with the drill fluid  340  through the well bore annulus  324 . The drill bit  322  creates a rock ring  342  at the bottom surface  327  of the well bore  324 . 
     Referring now to  FIG. 6 , a top view of the rock ring  342  formed by the drill bit  322  is illustrated. An interior cavity  344  is worn away by an interior portion of the drill bit  322  and the exterior cavity  346  and inner wall  326  of the well bore  324  are worn away by an exterior portion of the drill bit  322 . The rock ring  342  possesses hoop strength, which holds the rock ring  342  together and resists breakage. The hoop strength of the rock ring  342  is typically much less than the strength of the bottom surface  327  or the inner wall  326  of the well bore  324 , thereby making the drilling of the bottom surface  327  less demanding on the drill bit  322 . By applying a compressive load and a side load, shown with arrows  341 , on the rock ring  342 , the drill bit  322  causes the rock ring  342  to fracture. The drilling fluid  340  then washes the residual pieces of the rock ring  342  back up to the surface through the well bore annulus  324 . 
     Remaining with  FIG. 6 , mechanical cutters, utilized on many of the surfaces of the drill bit  322 , may be any type of protrusion or surface used to abrade the rock formation by contact of the mechanical cutters with the rock formation. The mechanical cutters may be Polycrystalline Diamond Coated (PDC), or any other suitable type mechanical cutter such as tungsten carbide cutters. The mechanical cutters may be formed in a variety of shapes, for example, hemispherically shaped, cone shaped, etc. Several sizes of mechanical cutters are also available, depending on the size of drill bit used and the hardness of the rock formation being cut. 
     Referring now to  FIG. 7 , an end elevational view of the drill bit  322  of  FIG. 5  is illustrated. The drill bit  322  comprises two side nozzles  200 A,  200 B and a center nozzle  202 . The side and center nozzles  200 A,  200 B,  202  discharge drilling fluid and solid material impactors (not shown) into the rock formation, or other surface being excavated. The solid material impactors may comprise steel shot ranging in diameter from about 0.010 to about 0.500 of an inch. However, various diameters and materials such as ceramics, etc. may be utilized in combination with the drill bit  322 . The solid material impactors contact the bottom surface  327  of the well bore  324  and are circulated through the annulus  324  to the surface. The solid material impactors may also make up any suitable percentage of the drill fluid for drilling through a particular formation. 
     Still referring to  FIG. 7 , the center nozzle  202  is located in a center portion  203  of the drill bit  322 . The center nozzle  202  may be angled to the longitudinal axis of the drill bit  322  to create an interior cavity  344  and also cause the rebounding solid material impactors to flow into the major junk slot  204 A. The side nozzle  200 A located on a side arm  214 A of the drill bit  322  may also be oriented to allow the solid material impactors to contact the bottom surface  327  of the well bore  324  and then rebound into the major junk slot  204 A. The second side nozzle  200 B is located on a second side arm  214 B. The second side nozzle  200 B may be oriented to allow the solid material impactors to contact the bottom surface  327  of the well bore  324  and then rebound into a minor junk slot  204 B. The orientation of the side nozzles  200 A,  200 B may be used to facilitate the drilling of the large exterior cavity  346 . The side nozzles  200 A,  200 B may be oriented to cut different portions of the bottom surface  327 . For example, the side nozzle  200 B may be angled to cut the outer portion of the exterior cavity  346  and the side nozzle  200 A may be angled to cut the inner portion of the exterior cavity  346 . The major and minor junk slots  204 A,  204 B allow the solid material impactors, cuttings, and drilling fluid  340  to flow up through the well bore annulus  324  back to the surface. The major and minor junk slots  204 A,  204 B are oriented to allow the solid material impactors and cuttings to freely flow from the bottom surface  327  to the annulus  324 . 
     As described earlier, the drill bit  322  may also comprise mechanical cutters and gauge cutters. Various mechanical cutters are shown along the surface of the drill bit  322 . Hemispherical PDC cutters are interspersed along the bottom face and the side walls  210  of the drill bit  322 . These hemispherical cutters along the bottom face break down the large portions of the rock ring  342  and also abrade the bottom surface  327  of the well bore  324 . Another type of mechanical cutter along the side arms  214 A,  214 B are gauge cutters  230 . The gauge cutters  230  form the final diameter of the well bore  324 . The gauge cutters  230  trim a small portion of the well bore  324  not removed by other means. Gauge bearing surfaces  206  are interspersed throughout the side walls  210  of the drill bit  322 . The gauge bearing surfaces  206  ride in the well bore  324  already trimmed by the gauge cutters  230 . The gauge bearing surfaces  206  may also stabilize the drill bit  322  within the well bore  324  and aid in preventing vibration. 
     Still referring to  FIG. 7 , the center portion  203  comprises a breaker surface, located near the center nozzle  202 , comprising mechanical cutters  208  for loading the rock ring  342 . The mechanical cutters  208  abrade and deliver load to the lower stress rock ring  342 . The mechanical cutters  208  may comprise PDC cutters, or any other suitable mechanical cutters. The breaker surface is a conical surface that creates the compressive and side loads for fracturing the rock ring  342 . The breaker surface and the mechanical cutters  208  apply force against the inner boundary of the rock ring  342  and fracture the rock ring  342 . Once fractured, the pieces of the rock ring  342  are circulated to the surface through the major and minor junk slots  204 A,  204 B. 
     Referring now to  FIG. 8 , an enlarged end elevational view of the drill bit  322  is shown. As shown more clearly in  FIG. 8 , the gauge bearing surfaces  206  and mechanical cutters  208  are interspersed on the outer side walls  210  of the drill bit  322 . The mechanical cutters  208  along the side walls  210  may also aid in the process of creating drill bit  322  stability and also may perform the function of the gauge bearing surfaces  206  if they fail. The mechanical cutters  208  are oriented in various directions to reduce the wear of the gauge bearing surface  206  and also maintain the correct well bore  324  diameter. As noted with the mechanical cutters  208  of the breaker surface, the solid material impactors fracture the bottom surface  327  of the well bore  324  and, as such, the mechanical cutters  208  remove remaining ridges of rock and assist in the cutting of the bottom hole. However, the drill bit  322  need not necessarily comprise the mechanical cutters  208  on the side wall  210  of the drill bit  322 . 
     Referring now to  FIG. 9 , a side elevational view of the drill bit  322  is illustrated.  FIG. 9  shows the gauge cutters  230  included along the side arms  214 A,  214 B of the drill bit  322 . The gauge cutters  230  are oriented so that a cutting face of the gauge cutter  230  contacts the inner wall  326  of the well bore  324 . The gauge cutters  230  may contact the inner wall  326  of the well bore at any suitable backrake, for example a backrake of 15° to 45°. Typically, the outer edge of the cutting face scrapes along the inner wall  326  to refine the diameter of the well bore  324 . 
     Still referring to  FIG. 9 , one side nozzle  200 A is disposed on an interior portion of the side arm  214 A and the second side nozzle  20013  is disposed on an exterior portion of the opposite side arm  214 B. Although the side nozzles  200 A,  200 B are shown located on separate side arms  214 A,  21413  of the drill bit  322 , the side nozzles  200 A,  200 B may also be disposed on the same side arm  214 A or  214 B. Also, there may only be one side nozzle,  200 A or  200 B. Also, there may only be one side arm,  214 A or  214 B. 
     Each side arm  214 A,  214 B fits in the exterior cavity  346  formed by the side nozzles  200 A,  200 B and the mechanical cutters  208  on the face  212  of each side arm  214 A,  214 B. The solid material impactors  100  from one side nozzle  200 A rebound from the rock formation and combine with the drilling fluid and cuttings  325  flow to the major junk slot  204 A and up to the annulus  324 . The flow of the solid material impactors, shown by arrows  205 , from the center nozzle  202  also rebound from the rock formation up through the major junk slot  204 A. 
     Referring now to  FIGS. 10 and 11 , the minor junk slot  204 B, breaker surface, and the second side nozzle  200 B are shown in greater detail. The breaker surface is conically shaped, tapering to the center nozzle  202 . The second side nozzle  200 B is oriented at an angle to allow the outer portion of the exterior cavity  346  to be contacted with solid material impactors. The solid material impactors then rebound up through the minor junk slot  204 B, shown by arrows  205 , along with any cuttings  325  and drilling fluid  340  associated therewith. 
     Referring now to  FIGS. 12 and 13 , top elevational views of the drill bit  322  are shown. Each nozzle  200 A,  200 B,  202  receives drilling fluid  340  and solid material impactors from a common plenum feeding separate cavities  250 ,  251 , and  252 . The center cavity  250  feeds drilling fluid  340  and solid material impactors to the center nozzle  202  for contact with the rock formation. The side cavities  251 ,  252  are formed in the interior of the side anus  214 A,  214 B of the drill bit  322 , respectively. The side cavities  251 ,  252  provide drilling fluid  340  and solid material impactors to the side nozzles  200 A,  200 B for contact with the rock formation. By utilizing separate cavities  250 ,  251 ,  252  for each nozzle  202 ,  200 A,  200 B, the percentages of solid material impactors in the drilling fluid  340  and the hydraulic pressure delivered through the nozzles  200 A,  200 B,  202  can be specifically tailored for each nozzle  200 A,  200 B,  202 . Solid material impactor distribution can also be adjusted by changing the nozzle diameters of the side and center nozzles  200 A,  200 B, and  202 . However, in alternate embodiments, other arrangements of the cavities  250 ,  251 ,  252 , or the utilization of a single cavity, are possible. 
     Referring now to  FIG. 14 , the drill bit  322  in engagement with the rock formation  270  is shown. As previously discussed, the solid material impactors  272  flow from the nozzles  200 A,  200 B,  202  and make contact with the rock formation  270  to create the rock ring  342  between the side arms  214 A,  214 B of the drill bit  322  and the center nozzle  202  of the drill bit  322 . The solid material impactors  272  from the center nozzle  202  create the interior cavity  344  while the side nozzles  200 A,  200 B create the exterior cavity  346  to form the outer boundary of the rock ring  342 . The gauge cutters  230  refine the more crude well bore  324  cut by the solid material impactors  272  into a well bore  324  with a more smooth inner wall  326  of the correct diameter. 
     Still referring to  FIG. 15 , the solid material impactors  272  flow from the first side nozzle  200 A between the outer surface of the rock ring  342  and the interior wall  216  in order to move up through the major junk slot  204 A to the surface. The second side nozzle  200 B (not shown) emits solid material impactors  272  that rebound toward the outer surface of the rock ring  342  and to the minor junk slot  204 B (not shown). The solid material impactors  272  from the side nozzles  200 A,  200 B may contact the outer surface of the rock ring  342  causing abrasion to further weaken the stability of the rock ring  342 . Recesses  274  around the breaker surface of the drill bit  322  may provide a void to allow the broken portions of the rock ring  342  to flow from the bottom surface  327  of the well bore  324  to the major or minor junk slot  204 A,  204 B. 
     Referring now to  FIG. 15 , example orientations of the nozzles  200 A,  200 B,  202  are illustrated. The center nozzle  202  is disposed left of the center line of the drill bit  322  and angled on the order of around 20° left of vertical. Alternatively, both of the side nozzles  200 A,  200 B may be disposed on the same side arm  214  of the drill bit  322  as shown in  FIG. 15 . In this embodiment, the first side nozzle  200 A, oriented to cut the inner portion of the exterior cavity  346 , is angled on the order of around 10° left of vertical. The second side nozzle  200 B is oriented at an angle on the order of around 14° right of vertical. This particular orientation of the nozzles allows for a large interior cavity  344  to be created by the center nozzle  202 . The side nozzles  200 A,  200 B create a large enough exterior cavity  346  in order to allow the side arms  214 A,  214 B to fit in the exterior cavity  346  without incurring a substantial amount of resistance from uncut portions of the rock formation  270 . By varying the orientation of the center nozzle  202 , the interior cavity  344  may be substantially larger or smaller than the interior cavity  344  illustrated in  FIG. 14 . The side nozzles  200 A,  200 B may be varied in orientation in order to create a larger exterior cavity  346 , thereby decreasing the size of the rock ring  342  and increasing the amount of mechanical cutting required to drill through the bottom surface  327  of the well bore  324 . Alternatively, the side nozzles  200 A,  200 B may be oriented to decrease the amount of the inner wall  326  contacted by the solid material impactors  272 . By orienting the side nozzles  200 A,  200 B at, for example, a vertical orientation, only a center portion of the exterior cavity  346  would be cut by the solid material impactors and the mechanical cutters would then be required to cut a large portion of the inner wall  326  of the well bore  324 . 
     Referring now to  FIGS. 16 and 17 , side cross-sectional views of the bottom surface  327  of the well bore  324  drilled by the drill bit  322  are shown. With the center nozzle angled on the order of around 20° left of vertical and the side nozzles  200 A,  200 B angled on the order of around 10° left of vertical and around 14° right of vertical, respectively, the rock ring  342  is formed. By increasing the angle of the side nozzle  200 A,  200 B orientation, an alternate rock ring  342  shape and bottom surface  327  is cut as shown in  FIG. 17 . The interior cavity  344  and rock ring  342  are much shallower as compared with the rock ring  342  in  FIG. 16 . By differing the shape of the bottom surface  327  and rock ring  342 , more stress is placed on the gauge bearing surfaces  206 , mechanical cutters  208 , and gauge cutters  230 . 
     Although the drill bit  322  is described comprising orientations of nozzles and mechanical cutters, any orientation of either nozzles, mechanical cutters, or both may be utilized. The drill bit  322  need not comprise a center portion  203 . The drill bit  322  also need not even create the rock ring  342 . For example, the drill bit may only comprise a single nozzle and a single junk slot. Furthermore, although the description of the drill bit  322  describes types and orientations of mechanical cutters, the mechanical cutters may be formed of a variety of substances, and formed in a variety of shapes. 
     Each combination of formation type, bore hole size, bore hole depth, available weight on bit, bit rotational speed, pump rate, hydrostatic balance, circulation fluid rheology, bit type, and tooth/cutter dimensions may create many combinations of optimum impactor presence or concentration, and impactor energy requirements. The methods and systems of this invention facilitate adjusting impactor size, mass, introduction rate, circulation fluid rate and/or pump pressure, and other adjustable or controllable variables to determine and maintain an optimum combination of variables. The methods and systems of this invention also may be coupled with select bit nozzles, downhole tools, and fluid circulating and processing equipment to effect many variations in which to optimize rate of penetration. 
     While specific embodiments have been shown and described, modifications can be made by one skilled in the art without departing from the spirit or teaching of this invention. The embodiments as described are exemplary only and are not limiting. Many variations and modifications are possible and are within the scope of the invention. Accordingly, the scope of protection is not limited to the embodiments described, but is only limited by the claims that follow, the scope of which shall include all equivalents of the subject matter of the claims.