FIXED-CUTTER DRILL BIT ASSEMBLY AND METHOD

Abstract: A drill bit assembly (70) comprising a plurality of cutter units (72), with each cutter unit comprising a circumferentially forward, relatively blunt positioning cutter (78), followed by a fixed cutter (82) having a relatively sharp cutting edge (96), with the cutting edge (96) of the following cutter (82) being positioned a predetermined distance(s) below an operating position of the positioning cutter (78) is controlled by the positionning cutter (78) locating the drill bit assembly (70) against the hole end wall from which material is being cut. Also, additional fixed cutters (83) can be provided in circumferential alignment in said cutting units (72), and liquid jet cutters (80) can be used in combination with said cutting units (72).

Description: FIXED-CUTTER DRILL BIT ASSEMBLY AND METHOD Background of the Invention A. Field of the Invention This invention relates to drilling apparatus and methods, and more particularly to such drilling apparatus and methods used for drilling or coring deep holes in subsurface earth formations, such as drilling holes in rock in connection with the fossil fuel industry. B. Background Art Drill bits incorporating fixed cutting surfaces (drag bits) are widely used in the fossil fuel industries for drilling soft to medium strength rock. The bit is rotated and pushed against the rock by the drill stem, causing the cutting surfaces (cutters) on the bit to dig into the rock and scrape rock fragments (cuttings) from the work face. A fluid (water, air, foam or drilling "mud") is pumped through the drill stem, and then out and around the drill bit to flush cuttings away from the work face so that the cutters can continually contact fresh rock. The fluid also acts to cool the cutters and bit body, removing heat generated by friction from scraping the rock and heat emitted from the rock formation. Cutters used for drag bits are constructed of extremely hard materials such as tungsten carbide, natural diamonds and man-made polycrystalline diamond (PDC & TSD) . These cutters are wear resistant but expensive to manufacture. Drag bits mounting these cutters can advance rapidly through rocks with low to medium strength and abrasiveness and survive adequately to achieve economic life. However, many rock formations frequently encountered are strong and abrasive and cause rapid wear or breakage of the best drag bit cutters. As rock strength increases, higher axial loads are required on the drill bit to force the cutters to penetrate into the work face. This increases the rate of frictional heating and accelerates heat induced fracture and degradation of the cutter edges. Abrasive rock particles also accelerate frictional heating and abrasive wear on the cutters. The wear flats grow, requiring even higher axial forces to push the cutter into the rock. The result is a "snowball" effect of increasing frictional heating and wear. Soon the wear flats become so large that the maximum axial force available is insufficient to force the cutters far enough into the rock to enable an economic advance rate for the drag bit. A second cause of cutter failure is rapid load variations on the cutter edges due to the elastic failure mode of some strong or brittle rock types. Many softer rocks fail in a plastic mode with relatively constant forces on the cutter edges, which scrape away uniform furrows of rock particles similar to a plow shearing through moist topsoil. Brittle rocks fail in irregular fragments, causing rapid build-up and release of forces on the cutter edges. If the cut depth is too deep, the force surges can be large enough to fracture the cutters. The rapid intermittent cyclic loading also causes fatigue of the cutter edges and can excite vibration of the drill bit or initiate eccentric bit rotation, further accelerating cutter wear and failure. A third cause of cutter failure is inconsistent rock hardness. This often occurs in thinly bedded sedimentary rocks or rocks interspersed with nodules or crystals of harder material. The depth of cut that will cause forces sufficiently high to break a cutter is much less for hard brittle rock than for soft rock. The axial force on the drill bit causes the cutters to bite further into soft rock than into hard. If a hard spot is suddenly encountered, the cut depth at that instant may be too great, causing cutters to fracture. Prior attempts to reduce cutter wear and failure have included: a. improving cutter materials to increase wear resistance; b. modifying individual cutter shape and geometry to reduce forces on the cutter; c. modifying bit body geometry to improve cutter chip flushing and cooling; d. adding extra cutters near the bit perimeters (gauge) where wear is most severe; e. improving bit body materials to strengthen cutter attachment; f. modifying bit body design to minimize the possibility of eccentric rotation; and g. mounting posts (studs) behind the cutters to reduce impact loading. These changes have greatly improved drag bits, allowing them to be used economically in rocks with medium strength and abrasiveness instead of only in soft rocks as was the case previously. However, they still cannot economically drill hard abrasive rock. To the best knowledge of the applicant, at present drag bits account for less than one third of total bit usage. Accordingly these rock formations are typically drilled with roller cone bits that use rotating conical wheels holding teeth that crush and gouge the rock. Roller cone bits are more durable in hard rock but advance more slowly than drag bits, increasing the time, and hence the time dependent portion of costs, to complete the drilling project. It has also been known in the drilling industry to use ultra high pressure liquid jets (as high as 35,000 PSI or higher, sometimes in conjunction with small abrasive particles entrained therein) in conjunction with roller cone bits to assist the drilling process. The discharge nozzles are located adjacent to the operating surface of the bit to discharge the liquid jets into the end wall surface of the drill hole and weaken the rock material. To maximize the effect of the ultra high pressure jets, it is desirable that these be placed as closely as possible to the rock formations on which the liquid jet impinges. However, with the jet discharge orifices being placed more closely to the rock surface that is being cut, there is a greater chance of damage to the nozzles. This could occur, for example, by the jet nozzle contacting a protrusion or irregularity in the rock, or by a fragment of rock. Another problem is "splash back", in that material (e.g. rock fragments) may be caused to rebound from the end wall surface and strike the jet nozzle assembly and damage the same. A search of the patent literature has disclosed patents, these being the following: U.S. 5,004,056 (Goikhman et al) discloses a percussion-rotary drilling tool where there are drilling elements 5 and 6, mounted in a casing 8 at the drilling location. The outer rock crushing elements 9 are provided with spring loaded locating elements 16, formed with a retaining element 17 having a spring 18. Patentability seems to be predicated primarily on this feature. As the rock crushing elements 5 and 6 wear out and thus decrease in height, the reaction of the bottom surface of the borehole on the support elements 22 which in turn is mounted to the casing 2 causes the casing 2 to move upwards. It is stated in column 6, line 49 that during upward movement of the casing 2, the rock crushing elements are displaced toward the periphery of the tools which ensures a constant diameter of the tool, and in effect a constant diameter of the borehole 15. There is a group of four related patents, naming John Fuller as the inventor or a co- inventor, these being the following: U.S. 4,718,505; U.S. 4,823,892; U.S. 4,889,017 and 4,991,670. Insofar as these patents relevant to the concepts of the present invention, all of these have essentially the same basic disclosure. For convenience, reference will be made to the latest patent to issue. This discusses the problem of deep drilling where the drill passes through a comparatively soft formation and strikes a significantly harder formation or possibly hits some hard occlusions within the soft formation. The cutting elements in the drill bit may be subjected to very rapid wear. One prior art solution was to provide adjacent the rearward side of the cutting element a body of material impregnated with natural diamond. In this instance where the cutting element experiences rapid wear or fracture, the diamond impregnated support on which the element is mounted takes over the abrading action of the cutting element and permits continued use of the drill bit. It is stated that one disadvantage of this is that the diamond impregnated support generates a great deal of heat and the resultant high temperature tends to cause rapid deterioration. This patent shows an arrangement where there are a plurality of cutting elements 15 and spaced a short distance rearwardly of these cutting elements 15 are "abrading elements 16". For example, as shown in Figure 3, each cutting element 15 has front thin hard facing layer 17 of polycrystalline diamond bonded to a thickening backing layer. Each abrasion element 16 comprises a cylindrical stud and it is coated with particles 21 of natural or synthetic diamond or other super hard material. U.S. 4,790,394 (Dickinson et al) relates generally to the use of high velocity cutting jets to bore a hole. There are various arrangements, and one is to provide a whirling mass of pressurized fluid in a chamber and discharge it through a nozzle in the form of a high velocity cutting jet having a shape of a thin conical shell. U.S. 4,558,753 (Barr) relates to cutting elements for a drill, and these cutting elements have different back rake angles. One function of this invention is to have two sets of cutting members, one set having its cutting faces closer to the end operating face of the bit body than the cutting faces of the other set. The back rake angles of the cutting faces of the innermost set are more negative than the rake angles of the outer cutting faces. As the bit operates, the cutters with the less negative rake angles will contain and cut the more soft formation, this being accomplished rather rapidly. However, at such time as it enters into a hard rock formation, the outermost set of cutters (i.e. the more forward set) will quickly chip or break away so that the remaining cutters having a more negative rake angles can continue the drilling. U.S. 4,543,427 (Wang et al) discloses a drilling apparatus which provides an abrasive containing fluid jet. There are mechanical cutting means which break off the material between the grooves which are formed by the high pressure jets, so as to form a completed borehole. U.S. 4,397,361 (Langford, Jr.) shows a rotary drill bit where there is a number of protective protruding elements that extend beyond the cutters. As the bit is moving down the borehole or otherwise being handled, these protectors, prevent damage to the cutting elements. During operation, these protective members are worn away, leaving the cutting elements to engage the ground surface and function during the boring operation. U.S. 4,262,757 and U.S. 4,391,339 (both of which issued to Johnson, Jr. and three other inventors) are two related patents (one being a continuation of the other) having identical drawings and descriptions. These relate to a drill bit for deep hole drilling combining mechanical cutting and plurality of "cavitating liquid jet nozzles" to assist in the drilling action. U.S. 4,351,401 (Fielder) discloses a concept for earth boring drill bits. In the bit section, there is a coating of a hard wear resistant material and cutters are mounted in the sockets in this material. Penetration of the cutters is controlled by diamonds that are embedded in the hard material adjacent to the gauge of the bit and extending around the gauge of the bit. These engage the surface of the material being cut so as to control the depth of the cut. U.S. 4,253,533 (Baker, III.) shows a drill bit where there are a number of diamond insert cutter blanks at the face of the bit. There are two wear pads positioned on diametrically opposed portions of the operating face of the drill bit. These wear pads serve to channel the flow of drilling mud emanating from fluid passages formed in the face of the drill bit. U.S. 4,174,759 (Arbuckle) shows a rotary drill bit where there are mechanical rock breaking wheels. Also, a high pressure fluid jet cuts grooves in the bore bottom. U.S. 4,073,354 (Rowley et al) shows an earth boring drill bit. The subject matter of this patent appears to be closely related to a later issued patent discussed above (U.S. 4,351,401) which is assigned to the same assignee (Christensen, Inc.), and having one common inventor. This patent shows a particular type of cutting element. U.S. 3,838,742 (Juvkam-Wold) discloses a drill in which high pressure abrasive jets cut a series of concentric grooves in the bore bottom. There are wedge-like elements that break up the material between the grooves. U.S. 3,542,142 (Hasiba) shows a drill bit where there are some high velocity fluid jets discharged from the working face of the drill bit to form concentric circular grooves. Loading elements ride in the grooves to break up the material. U.S. 3,419,220 (Goodwin et al) shows an abrasive jet nozzle. The end of the nozzle has a tapered configuration, and this nozzle is used to discharge a fluid abrasive slurry. The inner material which comes in contact with the slurry is described as being more abrasive resistant. U.S. 3,235,018 (Troeppl) shows what is called an "Earth Auger Construction" . This shows a particular arrangement of teeth spaced radially outwardly from one another. The two diametrically opposed sets of teeth appear to travel in different grooves, and one set appears to be spaced somewhat lower than the other. U.S. 3,111,179 (Albers) shows a nozzle element for an earth boring jet drill. The nozzle element is made of a shell 21 that is formed in a casing 22. The shell is of abrasive resistant material such as tungsten carbide and the casing is a less expensive material that lends support and strength to the nozzle. Summary of the Invention The present invention comprises a rotary drill bit assembly and also a method of using the same. One of the advantages of the present invention is that it is able to extend the effective life of the drill bit assembly, particularly under circumstances where the drill bit assembly is encountering occlusions or material in the earth formation of differing hardness. Also the present invention provides effective drilling through the earth formation. The bit assembly of the present invention has a longitudinal axis of rotation. There is a drill bit housing having an upper end adapted to be connected to a drill stem means and a lower end at which the housing has an operating surface. The housing is configured and arranged for rotation about the longitudinal axis. There is at least one cutter unit mounted at the operating surface along a circumferential cutting path having a circumferential axis at a predetermined radial distance from the longitudinal axis. As the drill bit assembly rotates about the longitudinal axis, the cutter unit travels along the circumferential cutting path in a forward direction around the longitudinal axis. The cutter unit comprises: i. a forwardly located lead positioning cutter having a lower relatively hard positioning portion with a downwardly facing relatively blunt contact surface. The contact surface is located axially at a lower positioning location to engage material at the drill hole end wall at the circumferential path; ii. a trailing cutter having a relatively sharp cutting edge portion which is positioned at the circumferential axis rearwardly of the leading positioning cutter at an axial location operationally lower than the contact surface of the positioning cutter, in a manner to be positioned and configured to cut into the drill hole end wall as the drill assembly advances into the drill hole. Thus, in operation, the lead positioning cutter engages the drill hole end wall to locate the drill assembly axially relative to the end wall of the drill hole, and thus locate the cutting depth of the trailing cutter axially relative to the circumferential path. In the preferred form, the positioning cutter has a relatively hard material removal surface portion of the contact surface extending forwardly and upwardly from a lowermost positioning surface portion of the contact surface in a manner to be able to engage and remove at least some material from the drill hole end wall, with the material removal surface portion desirably being relatively blunt. Also, in the preferred form, the contact surface of the positioning cutter has side surface portions extending upwardly and laterally from the lower positioning surface portion, relative to the circumferential cutting surface, and preferably defining with the positioning surface portion a downwardly facing generally convexly curved contact surface. In the preferred form, the convexly curved surface has a material engaging surface portion between about 40 to 180 degrees of curvature and a radius of curvature of between about 0.15 or 0.2 to 0.51 inches, or about one fifth to one half inch, with the preferred ranges being between about 80 to 140 degrees of curvature and the radius of curvature being between about .25 to .35 inches, or one quarter to one third inch. The cutting assembly desirably comprises a plurality of the cutter units, each of which is positioned at a respective circumferential cutting path with the cutting paths each having a respective radial distance from the longitudinal axis. Adjacent cutting paths of radially spaced cutting units are spaced radially from one another by a spacing distance no greater than a radially aligned width dimension of the convexly curved contact surface of the positioning cutter. In a preferred configuration the radially aligned width dimension of the contact surface is between about 60 to 100 percent of the spacing distance of the cutting paths of the radially adjacent cutting units, and more desirably between about 80 to 100 percent. The positioning surface portion of the side surface portions of the contact surface comprise a contact surface area having a contact width dimension measured radially from the outside edges of the side surface portions of the contact surface. The trailing cutter is desirably a fixed cutter having a forwardly facing fixed relatively sharp cutting edge portion having a lower middle cutting edge portion and side cutting edge portions, with the cutting edge having a cutting width dimension. The contact width dimension is desirably greater than the cutting width dimension in a manner that the side surface portions of the contact surface extend laterally beyond a kerf cut by the cutting edge of the trailing cutter. Preferably, the contact width dimension is at least about one tenth greater than the cutting width dimension, and also in the preferred form no greater than one quarter times greater than the cutting width dimension. The cutter unit travels axially in a generally helical path having a helical axis, as the drill bit assembly, in operation, rotates and travels downwardly as it removes material from the end wall of the drill hole. The assembly has an operational depth dimension reference line, measured at angularly spaced locations around a circumferential axis of the helical path relative to axial distance from the helical path. The assembly also has an axial depth dimension line measured relative to locations on the drill bit assembly along a plane that is fixedly located at an axial location on the drill bit assembly and perpendicular to the longitudinal axis. The trailing cutter has a lowermost cutting edge portion that is lower, relative to the operational depth dimension line, than a lowermost portion of the contact surface of the positioning cutter. In another embodiment, the lowermost cutting edge portion has an axial location at least as low as the lowermost portion of the contact surface of the positioning cutter, relative to the axial depth dimension reference line, and in another arrangement lower than the lowermost portion of the contact surface of the positioning cutter, relative to the axial depth dimension reference line. A preferred range is that the lowermost cutting edge portion is at least one twentieth of an inch below the lowermost portion of the contact surface, relative to the axial depth dimension reference line, and no more than about one and one half tenths of an inch below the lowermost portion of the contact surface, relative to the axial depth dimension reference line. Also, in a preferred embodiment, the cutter unit comprises a secondary trailing cutter which has a cutting edge and is positioned on said circumferential axis rearwardly of the trailing cutter, which is then a primary cutter. Desirably, there is a plurality of such cutter units positioned at the operating surface at different circumferential axes. In one arrangement, the secondary trailing cutter has a lowermost cutting edge portion which is at a depth location no higher than the lowermost cutting edge portion of the trailing cutter, relative to the operational depth dimension reference line of the trailing cutter. In another form, the lowermost edge portion of the secondary trailing cutter is at a lower depth dimension relative to the operational depth dimension line of the lowermost edge of the trailing cutter. In yet another arrangement, the lowermost cutting edge portion of the secondary trailing cutter is at approximately the same depth location, relative to the axial depth dimension reference line as the lowermost cutting edge portion of the trailing cutter, and the secondary trailing cutter is circumferentially closer to the trailing cutter measured in a forward direction of travel to said trailing cutter, in comparison to a circumferential distance measured in a rearward direction circumferentially to said trailing cutter. In yet another embodiment, there is at least one additional secondary trailing cutter which has a cutting edge and which is positioned on the circumferential axis rearwardly of the secondary trailing cutter. The additional secondary trailing cutter is, in different embodiments, at a depth location, relative to the operational depth dimension line of the secondary trailing cutter, lower than the lowermost edge of the secondary trailing cutter. In another arrangement, the lowermost cutting edge portion of the additional secondary trailing cutter is at least as low as approximately the depth location as the lowermost cutting edge portion of the secondary trailing cutter, relative to the axial depth dimension reference line. In another embodiment, the drill bit assembly comprises a liquid jet cutter positioned on the circumferential axis between the positioning cutter and the trailing cutter. The liquid jet cutter is arranged to direct a high velocity liquid jet downwardly against the end wall at a location forwardly of the trailing cutter. In the preferred arrangement the lowermost surface portion of a lower surface of the liquid jet cutter is positioned at a depth location above the lowermost portion of the contact surface of the positioning cutter with reference to the axial depth dimension reference line. The lower surface of the liquid jet cutter is desirably made of a wear resistant material, and this lower surface slants away from a liquid jet discharge nozzle of the cutter at an upward slant. Thus, splashback resulting from the liquid jet is deflected away from the liquid discharge nozzle. Desirably, there is a plurality of the cutter units mounted at the operating surface of the drill bit housing, and the operating surface of the drill bit housing is positioned above the lowermost portions of the positioning cutter, the liquid jet cutter, and the trailing cutter, in a manner to provide a liquid flow passage means between the drill hole end wall and the operating surface, so that liquid flow from the liquid jet cutters is able to pass from the operating surface and around the drill bit housing. In yet another embodiment, the drill bit assembly has a cutting unit where there is a forwardly located lead primary cutter having a cutting edge with a lowermost cutting edge portion located axially at a lower location at the circumferential path, and a trailing secondary cutter having a cutting edge with a lowermost cutting edge portion. The secondary cutter is positioned at the circumferential axis rearwardly of the lead primary cutter. The trailing secondary cutter is positioned relative to the lead cutter so that the distance of the lowermost edge portion of the lead cutter is at a depth location less than one half the axial distance that the cutter unit travels in one revolution. Thus, the lead cutter cuts to a greater material depth along said circumferential path than the trailing cutter. As described above, relative to other embodiments, the trailing cutter has its lowermost edge at a depth dimension no higher than the operational depth dimension of the lowermost portion of the leading cutter, and other embodiments at about the same axial location relative to the lowermost edge of the lead cutter. Also, the trailing cutter is circumferentially closer to the lead cutter, measured in a forward direction of travel. In another embodiment, there is an additional trailing secondary cutter, and this is disposed at a different depth dimensions in different embodiments, relative to the lead cutter, with respect to both the operational depth dimension line and the axial depth dimension reference line, similarly to the embodiments described above. In a further embodiment, there is provided a forwardly located lead primary cutter having a cutting edge and also a trailing secondary cutter having a cutting edge, this being followed by a liquid jet cutter. The lowermost surface portion of the lower surface of the liquid jet cutter is positioned at a depth location above a lowermost portion of the cutting edge portion of the lead positioning cutter, with reference to the operational depth reference line. In the method of the present invention, a drill bit assembly is provided as described above. In the embodiment where there is a forward lead positioning cutter and a trailing cutter, the method comprises rotating the drill bit assembly with an axially downward force exerted by the drill bit assembly against the end wall. This is done in a manner that the lead positioning cutter engages the drill hole end wall to locate the drill bit assembly axially relative to the end wall of the drill hole, and thus locate the cutting depth of the trailing cutter axially relative to the circumferential path. Other features of the method and apparatus of the present invention will become apparent from the following detailed description. Brief Description of the Drawings Figure 1 is a somewhat schematic longitudinal sectional view of a prior art drilling apparatus, comprising a drag bit mounted to a drill stem; Figure 2 is an end view, taken along line 2-2 of Figure 1, looking at the operating surface of the drill bit of Figure 1; Figure 3 is an enlarged sectional view taken at the location circled at 3-3 in Figure 1, illustrating the action of a single cutter mounted in the drill bit; Figure 4 is a view similar to Figure 3, showing the single cutter moving through a soft rock formation into some hard rock, and also showing a prior art mount stud being positioned behind the cutter; Figure 5 is a schematic longitudinal sectional view illustrating the radial spacing of cutters as commonly arranged in the prior art, but showing only two cutters for convenience of illustration; Figure 6 is an end view of the drill bit of Figure 5, taken along line 6-6 of Figure 5; Figure 7 is an enlarged view, taken at the location circled in Figure 5, and showing to an enlarged scale one drill bit cutter and the width of the grooves formed in the rock surface relative to the width of the cutter; Figure 8 is a semi-schematic longitudinal sectional view of a drill bit that combines multiple features of the present invention in a single first embodiment, and showing only one cutter unit for ease of illustration; Figure 9 is an end view looking into the operating face of the drill bit of Figure 8; Figure 10 is a sectional view illustrating a second embodiment of a single positioning cutter and a trailing cutter mounted in a drill bit, engaging a rock formation having soft rock and hard rock; Figure 11 is a sectional view taken along line 11-11 of Figure 10; Figure 12 is a view similar to Figure 10 showing a third embodiment which is a less preferred version of the embodiment shown in Figure 10; Figure 13 is a sectional view (similar to Figure 11) taken along line 13-13 of Figure 12; Figure 14 is a schematic longitudinal sectional view of a drill bit housing and a single cutter, illustrating a helical path of travel of the cutter, this being presented for background information; Figure 15 is an end view taken along line 15- 15 of Figure 14; Figure 16 is a schematic drawing, similar to Figure 14, showing two cutters, positioned at diametrically opposed locations, and illustrating two separate helical paths of the two cutters, this also being done as a presentation of background information; Figure 17 is an end view taken at line 17-17 of Figure 16; Figure 18 is a schematic showing of a fourth embodiment of a drill bit of the present invention, illustrating only two cutters, both positioned at the same depth location; Figure 19 is an end view taken at line 19-19 of Figure 18; Figure 20 is a view similar to Figure 18, illustrating a fifth embodiment of the present invention, and showing for ease of illustration only two of a plurality of cutters mounted to a drill bit housing; Figure 21 is an end view taken at line 21-21 of Figure 20; Figure 22 is a schematic drawing, similar to Figure 20, showing a sixth embodiment, similar to that shown in Figures 20 and 21, where there is a plurality of sets of cutters, with each set being at different radial distances; Figure 22A is an enlarged view taken at the location circled in Figure 22 showing one drill bit cutter and the width of the cutter relative to the grooves cut into the rock surface; Figure 23 is an end view taken at line 23-23 of Figure 22; Figure 24 is a schematic drawing, similar to Figures 20 and 22, showing for purposes of illustration a plurality of cutters mounted in a pattern where the cutters at certain radial distances are evenly spaced and at an equal depth, this being done for purposes of explanation, and not to show an embodiment of the present invention; Figure 25 is an end view taken at line 25-25 of Figure 24; Figure 26 is a somewhat schematic view (similar to Figure 24) , showing a seventh embodiment of the present invention, with a drill bit incorporating units of closely spaced cutters; Figure 27 is an end view taken along line 27- 27 of Figure 26; Figure 28 is a somewhat schematic drawing (similar to Figure 26) showing yet an eighth embodiment of the present invention where the teachings of the embodiment shown in Figures 10 through 13 are combined with the teachings of the embodiment of Figures 20 and 21 in a drill bit; Figure 28A is a view similar to Figure 28 showing a variation of the embodiment of Figure 28; Figure 29 is an end view taken at line 29-29 of Figure 28; Figure 30 is a sectional view taken along a longitudinal axis of an ultra high pressure liquid jet unit, this being a ninth embodiment of the present invention, adapted for use in the drill bit assembly of the present invention; Figure 31 is a longitudinal sectional view of only the nozzle element shown in Figure 30 and circled, as indicated at 31 in Figure 30; Figure 32 is a sectional view similar to Figure 10 showing the cutter unit of a ninth embodiment of the present invention, incorporating the eighth embodiment of Figures 30 and 31; Figure 33 is a sectional view taken along line 33-33 of Figure 32; Figure 34 is a view illustrating the cutter unit illustrated in Figures 32 and 33 as the ninth embodiment, incorporated in a drill bit assembly, and also showing the lower part of a drill stem to which the assembly is mounted; Figure 35 is a end view taken at the location of line 35-35 of Figure 34. Figure 36 is a graph illustrating the operating results utilizing the present invention incorporating liquid jet cutting relative to standard drill bit assemblies; and Figure 37 is a view similar to Figure 28, but showing a tenth embodiment of the present invention; Figure 37A is a view similar to Figure 28A, showing a modification of the tenth embodiment illustrated in 37; Figure 38 is an end view of the tenth embodiment shown in Figure 37, taken at line 38-38 of Figure 37; Descriptions of the Preferred Embodiments A. Information and Discussion of the Prior Art and Background Information It is believed that a clearer understanding of the present invention will be obtained by first discussing certain relevant teachings of the prior art, and then describing the embodiments of the present invention. This will be discussed under appropriate sub-headings. a. General Discussion of a Typical Prior Art Drill Bit Assembly. A common configuration of one type of a drill bit assembly is shown somewhat schematically in Figures 1 and 2. This drill bit assembly 10 is shown threadedly mounted to a drill stem 12 and positioned in a drill hole 14 in a below surface earth formation 16. The drill hole 14 has a generally cylindrical sidewall 18 and an end wall or surface 20 at which further material removal takes place. The drill bit assembly 10 comprises a drill bit housing, shown rather schematically at 22, having an operating end surface 24 at which a plurality of cutters 26 are mounted. For ease of illustration, only two cutters 26 are shown in Figure 1, it being understood that a greater plurality of such cutters 26 would be provided, as shown in the end view of Figure 2. (The precise arrangement of the cutters 26 shown in Figure 2 may or may not exist in the prior art, but this arrangement is believed to be reasonably representative of a prior art cutting assembly. Also placement of the cutters 26 shown in Figure 2 does not necessarily represent an optimized arrangement of cutters 26. For example, since the outer cutters 26 would normally encounter greater wear, there would likely be more cutters 26 at a more radially outward location. Further, for smaller diameter drill bits, up to approximately 8 inches or so, it is common to place as many cutters at the operating surface 24 as possible, with a main limitation being to accommodate the practical requirements of spacing the cutters 26.) The drill bit assembly 10, along with the drill stem 12 to which it is fixedly (but removably) mounted has a longitudinal center axis 28 about which the drill bit assembly 10 and the drill stem 12 rotates. For consistency and clarity of description, the drill hole 14 shall be considered at all times as being vertically aligned. Thus, the operating end surface 24 shall be considered to be at the lower end of the drill bit assembly 10, while the connecting portion 29 of the drill housing 22 shall be considered as being at an upper location. It is to be understood, however, that while it is more common for a drill hole to be drilled downwardly into an earth formation, such a drill hole (as shown at 14) could be drilled horizontally, or even in a direction which is (relative to the center of the earth) in an upward direction or upward slant. Even so, the term "downwardly" will still be applied to the direction at which the drill bit assembly 10 moves as it drills against the end wall 20 of the drill hole 14, even if it is parallel to, or away from, the center of the earth. The term "radially outward" shall denote a direction or location away from the longitudinal center axis 28, while the term "radially inward" shall refer to a direction toward, or in proximity to, the longitudinal axis 28. The term "forward" shall denote the circular direction of travel of the drill bit assembly 10 and the stem 12. Thus, as shown in Figure 2, the term "forward" is indicated by the arrows 30. The term "circumferential" or "circumferential axis" shall refer to a circular path or line having as its center the longitudinal center axis 28. For example, with reference to Figure 2, each of the cutters 26 travels on a related circumferential path. In the following description when a component (e.g. a cutter 26) is discussed relative to a circumferential axis, such as shown at 32 in Figure 2, the term "lateral" or "laterally spaced" will refer to displacement away from the circumferential axis 32 and along a radially aligned axis, such as shown as 34, either in a radially inward direction or radially outward direction. It will be noted that the circumferential path of travel or circumferential axis 32 which passes through the center of the cutter 26' does not pass through the center of any of the other cutters 26 shown in Figure 2. A further examination will show that with the exception of the outermost cutters, each of the cutters 26 shown in Figure 2 has its own circumferential path of travel, with these paths being spaced one within the other as concentric rings. This is typical of the prior art drill bit assemblies, and this will be discussed later herein, with reference to Figures 5-7. With further reference to Figure 1, the drill bit housing 22 is shown being formed with a downwardly extending passageway 36 through which a flushing fluid passes to exit at a lower end opening 38 into an operating region 40. This operating region 40 is located between the drill hole end face 20 and the operating end surface 24 of the drill bit housing 22. This flushing liquid is discharged into this operating region 40 to flush cuttings away from the drill hole end wall 20 so that the cutters 26 can continuously contact fresh rock. The fluid also acts to cool the cutters 26 and the housing 22, thus dissipating the heat generated by friction by the scraping of the rock and the heat emitted from the rock formation. As shown in Figure 2, there is a plurality of such fluid discharge openings 38 (specifically six in Figure 2) , and fluid can be directed to these various openings 38 either from multiple passages, or from a passageway manifold at the lower end of the drill bit housing 22. The common method of operation of the drill bit assembly 10 is that an axial force 45 is applied through the drill stem 12 to push the drill assembly 10 against the rock surface that is the down hole end wall 20 causing the cutters 26 to penetrate into the end wall 20 to a depth 49. At the same time rotational force (torque) 47 is applied through the drill stem 12 causing the cutters 26 to move in respective circular cutting paths to remove the rock as rock cuttings. At the same time, as indicated above, the flushing fluid passing downwardly through the openings 38 into the operating region 40 moves upwardly around the outside surface 42 of the drill housing 22 and upwardly through the annular passageway 44 between the drill stem 12 and the down hole sidewall 18. the depth 49 of the circular cutting paths will normally increase if the axial force 45 increases or if the hardness of the end wall rock 16 decreases. b. The Cutting Action of a Prior Art Drill Bit in a Rock Formation With reference to Figure 3, there is shown a single conventional fixed cutter 26 mounted in the drill bit housing 22. This cutter 26 has a generally cylindrical shape, with a cylindrical mounting portion 46 by which it is mounted in the lower end of the housing 22. The lower end portion 48 of the cutter 26 has the forward lower end portion partially removed to form a flat downwardly extending surface with a slight rearward slant, as indicated at 50. The lower surface 52 rearwardly of the flat surface 50 is rounded. There is provided a very hard disc- shaped layer 54 of cutter material, such as tungsten carbide coated or impregnated with commercial diamonds or the like. The configuration of such a cutter 26 is (or may be ) conventional, and will be described in more detail later herein. As can be seen in Figure 3, the cutting surface 54 acts against the ground formation 56 adjacent to the end wall 20 to cause the material removal along circular cutting paths to depth 49. As previously indicated, cutting depth 49 will increase or decrease according to the amount of axial force 45 transmitted to cutter 26 through housing 22. The normal mode of operation is to limit axial force 45 to an amount that will result in a cut depth 49 that will not cause the rock 56 to exert too great a resistance to cutter 26 so as to not overload and fracture cutter 26. The situation shown in Figure 4 is where the cutter 26 is moving through some relatively soft rock 58, so that depth 49 is relatively large, and is about to encounter a formation of relatively hard rock 60. When the cutter 26 is encountering the soft rock 58, it will commonly penetrate into this soft rock 58 to a greater depth, and when it then encounters the hard rock 60 at that greater depth, the resisting force provided by the hard rock 60 is substantially greater than what would normally be encountered. This often causes the cutting surface to fracture and break away, leaving the cutter 26 severely damaged. (The depths of the cuts 49 shown in Figures 3 and 4 are somewhat exaggerated for purposes of illustration. Commonly the cutting depth of a single cutter may be no greater than 0.15 inch, or less than that if the rock formation is particularly hard.) With reference to Figure 2, if the damage of a number of cutters 26 becomes sufficiently severe, the drill bit 10 cannot properly perform its cutting function. Accordingly, the drill stem 12 must be withdrawn from the hole 14, the bit assembly 10 replaced, with the new drill bit assembly 10 being attached to the lower end of the drill stem, and the drill stem with the new drill bit is then lowered downwardly into the drill hole 14. Not only is there the expense of time and labor of replacing a new drill bit assembly 10, but there is also the cost of the new drill bit assembly 10. With reference to Figure 4, one of the prior art solutions to the problem discussed specifically above is to mount studs 62 directly behind the cutters 26 with the intent of reducing high impact loads. However, as illustrated in Figure 4, such a stud 62 cannot effectively control the cutting depth 49 of the cutter 26 in a situation such as shown in Figure 4, and hence cannot protect cutter 26 from high resisting forces occurring at the transition from soft rock 58 to hard rock 60. c. Prior Art Radial Spacing and Axial Location of the Cutters Reference is made to Figures 5 through 7, where there is shown rather schematically a prior art drill bit assembly 10a, somewhat the same as that shown in Figures 1 and 2, except that for ease of illustration and description, the number of cutters has been reduced to only nine cutters 26a. Generally, the cutters 26a are at circumferentially spaced locations along the operating surface 24a in a manner that the resisting force exerted by the rock surface 20 is substantially balanced over the operating end surface 24a of the drill bit housing 22a. Also (and as mentioned earlier herein with reference to Figure 2) , it is conventional practice to have the radial spacing of the various cutters 26a (i.e. the distance from the center longitudinal axis 28a) be different for the majority of cutters 26a so that most cutters follow their own circumferential cutting paths. As illustrated in Figure 6, there are nine cutters 26a, and each of these follows its own circumferential cutting path, (For ease of illustration, in Figure 5, only two cutters 26a are shown, these being located on the circumferential paths 4 and 9, and the location of the other circumferential cutting paths being indicated by the vertical lines in Figure 5, and the circumferential arcs in Figure 6, with four of these being numbered, namely those indicated at 1, 2, 4 and 9.) It has been a conventional practice to have the radial spacing of the individual cutters 26a (shown at 64 in Figure 5) less than half the lateral width dimension of the cutters, indicated at 65 in Figure 7. Thus, as can be seen in Figures 5 and 7, the kerfs or grooves cut by the cutters 26a are closely together, with the width 66 of the grooves normally less than half the width 65 of the cutters. B. A First Embodiment of the Present Invention, in Which Main Principles of the Present Invention Are Combined in 9- Single Drill Bit Assembly The drill bit assembly 70 of this first embodiment is illustrated in Figures 8 and 9. Figure 8 is a semi-schematic longitudinal sectional view showing (for ease of illustration) only one of a plurality of cutter units 72 which are positioned at various circumferential locations, and also at various radial distances over the operating surface 74 of the drill bit housing 76. (The unit 72 shown in Figure 8 is the unit 72 seen at the top of Figure 9.) In this present embodiment, each cutter unit 72 comprises a forward lead positioning cutter 78, an ultra high pressure liquid jet cutter 80 (positioned immediately rearwardly of the positioning cutter 78), and two trailing cutters 82 and 83. These cutters 78, 80, 82 and 83 are aligned on the same circumferential axis 84 and are grouped on an arcuate segment of this circumferential axis 84. In the description that follows in this section "B", there will simply be a brief description of each of the cutters 78, 80, 82 and 83, and the general manner in which these function in this first embodiment. Then in subsequent sections of this text, there will be more detailed descriptions of these components shown in Figures 8 and 9 as separate embodiments. The lead positioning cutter 78 has an upper cylindrical portion 85 by which it is mounted in a related recess 86 formed in the drill bit housing 76. This cylindrical portion 85 extends downwardly below the operating surface 74 of the housing 76 and terminates in a lower cutting and positioning portion 88 (also called a "contact portion") which has a convex surface which is nearly hemispherical or formed as a lower curved portion of a hemisphere. This lower portion 88 has a relatively blunt cutting surface 90 coated with a very hard and wear resistant surface 90, such as a surface material impregnated or coated with polycrystalline diamond particles. Surface 90 has a forward cutting surface portion 104 curving upwardly and forwardly. The liquid jet cutter 80 is arranged to receive from the drill stem (not shown) an ultra high pressure cutting liquid, and has a discharge nozzle 92 from which the liquid jet 93 is discharged downwardly against the rock surface. It will be noted that the lowermost surface portion 176 of the liquid jet cutter 80 is positioned a moderate distance upwardly from the lowermost portion 105 of the positioning cutter 78. Positioned behind the liquid jet cutter 80 is the first fixed cutter 82, followed by the second fixed cutter 83. These fixed cutters 82 and 83 are (or may be) of conventional design and in this embodiment are the same as the cutters 26 described in the prior art drill bit assembly of Figures 1 and 2, or the same as the cutters shown in Figures 3 through 7. Each of the cutters 82 and 83 has a very hard cutting disc or layer 94 (which is the same as, or similar to the cutting layer 54 of the prior art cutter 26 of Figure 3) , having a rounded lower cutting edge 96. The lowermost portion 106 of cutting edge 96 of cutter 82 is located at distance "S" lower than the lowermost portion 105 of positioning cutter 78. The cutting edges 96 of the cutters 82 and 83 are each at a different vertical position, with the cutting edge 96 of the trailing cutter 83 being slightly higher than the cutting edge 96 of the forward cutter 82. The relatively hard cutting surface material is indicated at 97. With reference to Figure 9, it can be seen that there are five cutter units 72 positioned at various circumferential locations around the operating surface 74 of the housing 76, and that each cutter unit 72 has its individual cutters 78, 80, 82 and 83 positioned on an arcuate segment of its own circumferential path. There are seven such circumferential paths, these being designated collectively by the numeral 98. The four more radially outward cutter units 72 have the single positioning cutter 78 the single jet cutter 80 and the two fixed relatively sharp cutters 82 and 83. The two innermost circumferential cutting paths 98 have only a single sharp cutter 99, which can be the same as the cutters 82 and 83. The third innermost cutting unit 100 has a positioning cutter 78, a liquid jet cutter 80 and only a single trailing cutter 82. The reason for the two single innermost cutters 99 and only a total of three cutters in the unit 100 is simply a matter of inadequate space near the center of the operating surface 74 to fit more cutters in. As indicated previously herein, in a smaller diameter drill bit, it is common to place as many cutters over the operating surface of the drill bit housing as is practical, with a greater number being located at the more outward radial locations. Also, it is to be understood that there are lower end openings 102 to permit the flushing liquid to be discharged into the working area immediately below the operating surface 74 and above the drill hole end wall 75. Four such flush liquid discharge openings are shown in Figure 9. To describe generally the operation of this first embodiment of Figures 8 and 9, axial force 77 and rotational force 79 are exerted in sufficient amounts to rotate the drill bit assembly 70 about the longitudinal center axis 28 while forcing the positioning cutters 78 against the hole end wall surface 75. This results in the first fixed cutters 82 cutting into the rock at cut depth "s". Cut depth "s" is determined at the time the drill bit assembly 70 is manufactured and is fixed by the distance to which the lowermost portion 106 of the first fixed cutter 82 extends below the lowermost portion 105 of positioning cutter 78. The depth "s" for a drill bit assembly 70 manufactured to drill hard or non-uniform rock will be less than the depth "s" for a drill bit assembly 70 manufactured to drill soft or uniform rock. Drill bit assemblies with various depth "s" dimensions can be inventoried and selected for use according to the rock conditions expected. These conditions are often known in advance due to having previously drilled holes nearby and through the same rock strata where the next drill bit assembly 70 will be used. Depth "s" will typically be .04 to .08 inches for hard or irregular rock to as much as .07 to .15 inches for soft or uniform rock. In general, depth "s" will be selected to be as large as possible without risking premature breakage of lead cutter 82. The function of lead positioning cutter 78 is fourfold. First, its axial placement relative to the first fixed cutter 82 controls the maximum amount of cut depth "s" as described above. If axial force 77 is very low or if the rock is very hard the actual cut depth for the first fixed cutter 82 may be less than the depth "s" controlled by the lead positioning cutter 78, i.e. the lowermost portion 105 of the lead positioning cutter 78 may not be in contact with hole end wall surface 75. Thus, the actual depth of cut will be small and should not cause premature breakage of the first fixed cutter 82. As axial force 77 is increased or the rock becomes softer, the lead positioning cutter 78 will contact the hole end wall surface 75 and the cut depth "s" will be achieved. If axial force 77 is increased further or the rock becomes even softer, the lead positioning cutter 78 will dig into the hole end wall 75 and remove rock at cut depth "d". Depth "d" will vary with the amount of axial force 77 and rock hardness, but the maximum value for depth "s" is constant, protecting the first fixed cutter 82 from premature breakage. This is very important because, in practice, precise control of axial force 77 is difficult and rock hardness can change very frequently and rapidly when drilling through bedded rock formations. Thus use of the lead positioning cutters 78 permits a higher amount of axial force to be used when drilling in variable rock formations, enabling maximum drilling advance rates without fear that depth "s" will suddenly increase to an amount large enough to prematurely break the first fixed cutter 82. Secondly, the lead positioning cutter 78 sweeps aside any debris or rock cuttings that might wedge under or damage the liquid jet cutter 80. Thirdly, the lead positioning cutter 78 plows over the hole end wall 75 acting to scrape away a thin layer of the end wall that may have become impregnated with fine particles carried in the flushing fluid. This impregnation of particles into the hole end wall is often referred to as the "skin effect" and occurs due to pressure from the drilling fluid forcing tiny particles into the natural pores in the rock. The "skin effect" makes the rock surface effectively tougher and more difficult to cut with a liquid jet 93. Removal of this "skin" layer by the lead positioning cutter 78 creates a freshly exposed rock surface 79 immediately prior to the rock surface 79 being struck by the liquid jet 93 and is beneficial in allowing the liquid jet to cut deeper into the rock than it might otherwise do if no lead positioning cutter 78 were used closely preceding the liquid jet cutter 80. Fourthly, when a situation is encountered in the ground formation shown in Figure 4 (i.e. when the cutter is moving over soft rock and then encounters a harder rock formation, the upwardly and forwardly slanting leading surface 104 tends to ride up and over the newly encountered hard rock formation. The drill string to which the drill bit housing 76 is mounted acts as a large spring so that it permits this short increment of upward movement of the drill bit housing 76. However, since the operating surface 90 of the positioning cutter 78 exerts a greater downward force against the rock formation when it is forced upwardly against the resisting force of the drill string, and since the slight upward movement of the drill assembly 76 also lifts the cutters 80, 82 and 83 and the other cutting units 72 upwardly, thus increasing further the downward force exerted by the positioning cutter 78, the surface 90 does cut into the rock surface to a relatively greater extent. However, since the operating surface 90 of the cutter 78 is rather blunt, this cutting action of the cutter 78 is of somewhat limited depth into the rock formation. This "riding up" of the positioning cutter 78 over the newly encountered hard rock lifts the liquid jet cutter 80 so that it does not come into contact with the newly encountered hard rock formation. Also, this lifts the trailing cutters 82 and 83 so that they are at a lesser depth location when (with further rotation of the drill bit housing 76) the lower cutting edges 96 come into contact with the hard rock formation. Further, it should be pointed out that the particular placement of the two relatively sharp cutters 82 and 83 in the same circumferential path, positioned closely together relative to the circumferential path, and having certain relative vertical positions, produces a significant benefit. Stated briefly, the cutting edge 96 at the forward cutter 82 cuts more deeply into the rock formation, while the cutting edge 96 of the rear cutter 83 (as shown herein) has little, if any, cutting engagement. The effect of this is that if the forward cutter 82 is fractured or otherwise severely damaged, or if the cutting edge 96 of the forward cutter 82 wears away to a substantial extent, then the rear cutter 83 takes on more of a cutting function along that same circumferential path. Thus, the fracturing, wear or other deterioration of the forward sharp cutter 82 does not destroy the cutting action along the circumferential cutting path 98 of that particular cutting unit 72. This will be discussed in greater detail later herein in the description of other embodiments. As indicated at the start of this Section "B", this first embodiment of Figures 8 and 9 combines several of the main principles or components of the present invention in one embodiment. When combined in the manner shown in Figures 8 and 9, it is believed that these various inventive principles or components of the present invention cooperate in a manner that certain aspects of the functions of the present invention are significantly improved. However, it should also be understood that these individual inventive principles or components can operate advantageously apart from their being grouped into this combined embodiment of Figures 8 and 9. This will be discussed more fully in the following sections of the text. C. Controlled Depth Cutting Embodiments (Second and Third Embodiment) a. Second embodiment (Figures 10 and 11) As indicated above, the second embodiment of the present invention is illustrated in Figures 10 and 11, and comprises two of the cutters shown in the first combined embodiment of Figures 8 and 9. For clarification, the elements or components of this second embodiment will (when appropriate) be given numerical designations corresponding to those of the first embodiment of Figure 8 and 9. However, the numerical designation of this second embodiment of Figures 10 and 11 will have a "b" suffix to distinguish these as being associated with the second embodiment. It will be noted that the second embodiment comprises a cutting unit 72b having a forward or lead positioning cutter 78b, and a single trailing relatively sharp cutter 82b, aligned with (relative to the circumferential axis) and positioned behind and closely adjacent to, the forward positioning cutter 78b. The lead positioning cutter 78b can conveniently and more economically be provided as a commercially available, prior art compression or impact cutter, such as those designated as Impax diamond enhanced drilling inserts, Model I-10, manufactured by MegaDiamond. In general, the main cylindrical mounting portion 85b of the positioning cutter 78b can have a diameter (indicated at "m") in Figure 11 between about 0.3 to 1.0 inches, and the overall height dimension of the positioning cutter 78b can be between about .4 to 3.0 inches (indicated at "n" in Figure 11) . The lower contact surface 90b is conveniently rounded so as to have a generally hemispherical shape, or possibly a somewhat flattened hemispherical shape. As seen from a forward direction, the forward sloping lower middle positioning surface portion 104b has upwardly and laterally curved side surface portions 108b, all of which are part of the contact area of the positioning cutter 78b. As can be seen in Figure 11, as viewed transversely to the circumferential axis of the positioning cutter of 78b, the entire contact area would be about 40° to 180°, and the radius of curvature (indicated at "r" in Figure 11) would be between about .17 to .75 inches. Also as indicated previously, the cutter 82b has a relatively sharp cutting edge 96b, having a lowermost portion 106b and laterally upwardly curved side portions 110b. The cutting area of the sharp edge 96b can have a contact line extending along a curve between 40 to 180°, and can have a radius of curvature between about .17 to .75 inch. As can be seen in Figure 10, the lowermost portion of the cutting edge 96b of the rear cutter 82b is relatively sharp and is positioned at a depth greater than the lowermost positioning portion 105b of the positioning cutter 78b. As indicated previously, the depth of cut indicated as "d" in Figure 10, for positioning cutter 78b, depends largely on the amount of axial force 77b and on the character of the rock formation in which the cutter assembly 72b is operating. In hard rock, the depth "d" may be near zero. In general, the lowermost edge 106b of the sharp cutting edge 96b would be below the lowermost portion 105b of the contact surface 90b of the positioning cutter 78b by a distance indicated at "s" in Figure 10 between about 0.04 to 0.15 inch. Depth "s" will remain relatively constant independent of rock types or changes in rock hardness or changes in axial force 77b. As indicated previously, the relatively sharp trailing cutter 82b is or may be of conventional design. A prior art cutter 82b suitable for use in the present invention could be one designated as GE Stratapax No. 2743 by G.E. Superabrasives, or 1/2" stud cutter by MegaDiamond. In general, such a cutter would have an upper mounting portion 112b having a diameter (indicated at "e" in Figure 10) should be between about .3 to 1.5 inches. The maximum width dimension of the cutting surface 96b (indicated at "w" in Figure 11) would be approximately no greater than the same as the maximum width dimension of the positioning cutter 78b at the contact portion , shown as "b" in Figure 11. Desirably the lateral width "b" of the contact surface portion of the positioning cutter 78b would be 1/10 to 1/4 greater than the lateral width "w" of the full cutting edge 96b of the trailing cutter 82b. This would cause the furthest lateral portions 109b to extend moderately beyond the kerf or groove previously cut by the trailing cutter 82b, and in some instances have contact with rock surface portions laterally beyond the cutting area of the sharp cutter (indicated at "w") . In operation, it is to be understood that a plurality of the cutter units 72b would be positioned at different locations over the working surface 74b of the drill bit housing 76b. The particular arrangement of the cutter unit 72b of the drill bit assembly will depend to a large extent upon the type of substrate which is expected to be encountered. If the rock formation is relatively soft, then the relative depth spacing (indicated at "s" in Figure 10) would be made relatively greater so that the depth of cut of the sharp edge 96b of the trailing cutter 82b would be greater, possibly as great as 0.15 inch. On the other hand, if relatively hard rock or variable soft and hard rock is expected to be encountered, then this depth difference dimension (again indicated at "s" in Figure 10) could be made possibly as small as 0.04 inch. Since the drill bit assemblies have to be replaced periodically (e.g. possibly in excess of 30 hours or less than one hundred hours for harder rock types, depending upon the character of the rock and other factors) an optimized drill bit for the rock being encountered could be mounted to the drill string at that time. Within the broader scope of the present invention, conceivably the positioning of the individual cutters 78b and 82b could be adjusted at the drilling site. However, in view of the somewhat limited life of any drill bit assembly, it may well be more cost effective simply to provide and inventory several arrangements of drill bit assemblies and use these as replacements as needed, as previously described. The manner in which the cutter unit 72b operates has been described previously with reference to the embodiment of Figures 8 and 9, so that will not be repeated in any detail at this time. Very briefly, the upwardly and forwardly slanting contact surface portion 104b of positioning cutter 78b controls the cut depth "s" in softer rock and tends to ride up over the harder rock as it is encountered, and also bears with greater force against that hard rock. This has the effect of lifting the trailing cutter 82b to some extent, so that the trailing cutter 82b is less likely to fracture when encountering the section of hard rock. b. Third Embodiment (Figures 12 and 13) This third embodiment shown in Figures 12 and 13 is substantially similar to the first embodiment. Components of this third embodiment which are similar to the prior embodiments will be given like numerical designations, with a "c" suffix distinguishing those of the third embodiment. As in the first embodiment, there is a cutting unit 72c with a trailing, relatively sharp cutter 82c. However, instead of having the leading positioning cutter 78b as in the second embodiment, there is a forward positioning member 78c composed of a near resistant material such as tungsten carbide which acts as a passive locating pad, and has little, if any, of a cutting function. As can be seen in Figure 13, the locating pad 78c has a width dimension substantially greater than the positioning cutter pad 78b of the second embodiment. Also, this cutting pad 78c has a generally rectangular configuration with lateral edges 114c extending well beyond the width of the trailing cutter 82c. Also, the positioning member 78c has a lower substantially flat planar surface 116c which extends over a larger area of the rock at the lower end surface 20c of the drill hole. It can be seen that the positioning pad 78c serves a similar positioning function as the positioning cutter 78b of the second embodiment. However, the passive locating pad 78c performs very little of a material removal function, and essentially rides over the rock surface 20c. Thus, while the passive pad 78c does serve a function of limiting the depth of cut of the trailing cutter 82c, indicated as "s" in Figure 12, it provides no substantial cutting function when the cutter unit 72c is traveling through the rock formation. While the third embodiment of Figures 12 and 13 is believed to provide a benefit over and above the prior art, this is, in general, a less preferred embodiment, relative to the second embodiment of Figures 10 and 11. D. Relative Cutter Depth Positioning Embodiments (Figure 14 Through 29) a. Background Information on Helical Spacing Reference Dimensions (Figures 14 through 17) Figures 14 through 17 do not represent embodiments of the present invention (nor do these represent any actual prior art embodiments) . Rather, these are simplified diagrams which are used to present certain background information given in this sub-section "a" of this Section "D" . In this background description, numerical descriptions will be given to correspond to the designations of comparable components described previously, and a "d" suffix will distinguish those components referred to in this section relative to Figures 14 through 17. In Figures 14 and 15, there is shown a single drill bit assembly 70d with a housing 76d, with a single cutter 82d mounted along a circumferential line 98d at radius "g" from longitudinal axis 28d (see Figure 15) . It can be seen (Figure 14) that as the housing 76d rotates and advances downwardly, the cutter 82d follows a helical path 12Od downwardly into the rock formation. For purposes of illustration, in Figure 14 the axial rate of travel for each 360° of circumferential travel is greatly exaggerated. The depth of the cutter 82d below the operating surface 74d is indicated at horizontal plane 119d, transverse and perpendicular to the longitudinal center axis 28d, and the axial rate of travel for each 360° of rotation of the single cutter 82h is indicated at "j" (again the "j" dimension being substantially exaggerated for ease of illustration) . Now in turning our attention to Figures 16 and 17, it is seen that there are provided two cutters 82d, each having a depth dimension indicated at horizontal plane 121d. The lower cutting edges 96d are at the same depth and horizontal plane 12Id is transverse and perpendicular to the longitudinal center axis 28d. Also, the two cutters 82d in Figures 16 and 17 are positioned at diametrically opposed locations on the same circumferential axis 98d at radius "g" from longitudinal center axis 28d. It can be seen that the circumferential path 122d traveled by the cutter 82d shown at the right in Figure 16 has the same axial rate of travel (indicated at "a" in Figure 16) as the single cutter 82d shown in Figure 14 (as shown at "j") . Also, it can be seen that the cutter 82d shown at the left of Figure 16 travels another helical path 124d which also has the same axial rate of travel, indicated at ' in Figure 16, as the other two paths 12Od and 122d. Each 360° portion of the helical path 124d is equally distanced between, and parallel to, the two adjacent 360° portions of the other path 122d. The net effect of this is that while the axial rate of travel of the drill bit 70d in Figure 14 is the same as the axial rate of travel of the drill bit 70d shown in Figure 16, the depth of cut of each of the two cutters 82d of Figures 16 is half the depth cut (illustrated at the arrows having the designation "a/2") . Also, with the cutters 82d in Figure 16 being 180° apart, the depth of cut for each is equal. Again, it should be pointed out that the subject matter of Figures 14-17 is not an embodiment of the present invention, but are illustrations to help explain certain background information. b. Fourth Embodiment (Figures 18 and 19) In describing this fourth embodiment, components which are similar to previously described components will be given like numerical designations, with an "e" suffix distinguishing those of this fourth embodiment. With reference to Figures 18 and 19, it can be seen that the drill bit assembly 70e has a housing 76e rotating in the direction indicated at arrow 30e about longitudinal axis 28e and has mounted at its operating surface 74e two cutters 82e and 83e which are positioned on the same circumferential line or axis 98e at radius "g" from longitudinal center axis 28e, but are spaced from each only by a circumferential distance of "h°". (It is to be understood, of course, that this is simply a schematic illustration, and that in an actual cutter assembly there would be other cutter pairs at other locations around the circumference of the drill bit housing 76e so that the force loads would be balanced. However, only two cutters 82e and 83e are shown grouped together to illustrate the operating principle of this embodiment.) With reference to Figure 18, it can be seen that there is a lead cutter 82e, and a trailing cutter 83e. The path of the lead cutter 82e is indicated at 128e, while the path of the trailing cutter 83e is indicated at 130e. Assuming that the drill bit assembly 70e is traveling at a constant axial rate of travel for each 360° of rotation, indicated at "j" in Figure 18, it can be seen that the depth of cut of the trailing cutter 83e (indicated at "p" in Figure 18) is equal to h° divided by 360° times the total depth of cut (indicated at "j " in Figure 18). (Again, the angle of the helical paths that travel 128e and 13Oe is exaggerated for purposes of illustration.) For example, if "h" degrees equals 60 degrees, then the depth of cut "p" for the trailing cutter 83e will equal 60/360 or 1/6 (17%) of the total axial rate of travel "j", and hence the depth of cut "q" for the leading cutter 82e will be 5/6 (83%) of the total axial rate of travel "j". For further example, if "h" degrees equals 18 degrees, then the depth of cut "p" for the trailing cutter 83e will equal 18/360 or 1/20 (5%) of the total axial rate of travel "j", and hence the depth of cut "q for the leading cutter 82e will be 19/20 (95%) of the total axial rate of travel "j". Now, let us look at the significance of this relative to the operation of this fourth embodiment of the present invention. It is apparent that the leading cutter 82e in Figures 18 and 19 would be more susceptible to wear, and also more susceptible to fracturing by reason of traveling at a greater depth through a rock formation as compared to the trailing cutter 83e. Thus, the second cutter 83e has a better chance of "survival" during a cutting operation. At this point, for purposes of explanation, let us make a distinction between the "axial relative depth dimension", and the "operating relative depth dimension". In Figure 18, the bottom cutting edges 96e of the two cutters 82e and 83e are at the same axial relative depth dimension, in that these lie in the same horizontal plane 12le transverse to and perpendicular to the longitudinal axis 28e. The operating relative depth dimension is measured relative to helical paths of travel. Thus, relative to the leading cutter 82e (Figure 18) , the operating relative depth dimension of trailing cutter 83e is measured with regard to the helical path 128e. Accordingly, the trailing cutter 83e has an operating depth dimension, measured from the helical path 128e at the location of the trailing cutter 83e to the lowest part of the cutting edge 96e of the trailing cutter 83e equal to the dimension indicated at "p" in Figure 18. At the same time, the forward cutter 82e has an operating relative depth dimension with reference to the trailing cutter 83e which is equal to "q" (Figure 18) . Now contrast the arrangement shown in Figures 18 and 19 with that shown in Figures 16 and 17, where the two cutters 82d are shown as being diametrically opposed to one another. It is readily apparent that the cutters 82d of Figures 16 and 17 have the same relative axial depth locations on plane 12Id and have the same operating relative depth dimensions, with each of these depth dimensions being equal to "a/2". Thus, the chances of "survival" of one or the other of these cutters 82d shown in Figures 16 and 17 are approximately equal and neither cutter can be identified as "leading" or "trailing". Further, the wear rate of the two cutters 82e in Figures 16 and 17 would, in general, be approximately the same. Let us look at the situation where the drill bit assembly is moving through a softer rock formation and thus cutting at a greater depth and then encounters a relatively hard rock formation. With the configurations shown in Figures 18 and 19, it can be seen that for a given axial rate of travel, the depth of the cut of the lead cutter 82e is at the greater depth of cut, indicated at "q" in Figure 18, when the hard rock formation is encountered. On the other hand, when the trailing cutter 83e would come into engagement with a hard rock formation after traveling through relatively soft rock, the depth of its engagement with the hard rock would be indicated at the smaller depth dimension "p" shown in Figure 18. Thus, the presence of the forward cutter 82e circumferentially adjacent to, and on the same circumferential axis as, the trailing cutter 83e enhances the ability of the trailing cutter 83e to "survive" in going through rock formations having rock of different hardness. Thus if the leading cutter 82e is fractured, the trailing cutter 83e would have previously been subjected to less wear and stress, and also would be in a position to function to cut a kerf in the rock formation at the proper depth to function compatibly with the other cutters in the drill bit assembly 70e. At this time, it should be pointed out that one of the advantages of the cutter arrangement in Figures 8 and 9 of the first embodiment becomes more evident, relative to the cutters 82 and 83 that are positioned behind the positioning cutter 78. This feature will be discussed more completely later again in connection with the embodiments shown in Figures 28 and 29. c. Fifth Embodiment (Figures 20 and 21) Components of this fifth embodiment which are similar to the components of the prior embodiments will be given like numerical designations, with an "f" suffix distinguishing those of this fifth embodiment. In this fifth embodiment, there is a drill bit assembly 70f with housing 76f rotating in the direction indicated by the arrows 30f and having six cutters 82f and 83f mounted at its operating face 74f, these being three lead cutters 82f with cutting edges 96f located at the axial reference plane 121f and three trailing cutters 83f with cutting edges 96f located on the axial reference plane 123f with the cutters 82f and 83f being positioned alternately with one another, and cutters 83f being spaced "h" degrees apart from cutters 82f. For ease of illustration, only one unit or grouping of two cutters 82f and 83f are shown in Figure 20, while six cutters 82f and 83f are shown in Figure 21. It can be seen in Figure 20 that the lead cutter 82f is following a helical path 132f with a total axial rate of travel per revolution indicated as "j". The trailing cutter 83f is positioned (relative to an actual depth dimension) upwardly of the adjacent leading cutter 82f by a distance indicated at "p" of Figure 20 and hence reference planes 121f and 123f are separated by the distance "p". However, it will be noted that the lower part of the cutting edge 96f of the trailing cutter 83f is on the same radial path 98f as the lower part of the cutting edge 96f of the leading cutter 82f. Distance "p" is of the same ratio to distance "j" as is angle "h" to 360°. Thus, in terms of operating relative depth location, it can be seen that the operating depth location of the trailing cutter 83f is the same as that of the leading cutter 82f. With reference to Figure 21, it can be seen that all six cutters 82f and 83f lie on the same circumferential axis 98f at radius "g" from longitudinal center axis 28f. In the arrangement shown in Figure 21, the three cutters 82f act as primary cutters, taking more of the brunt of the loads, while the trailing cutters 83f act as secondary cutters. In the operating mode shown in Figure 20, each secondary cutter 83f will not engage the rock or be subjected to wear until the immediately adjacent forward cutter 82f starts to wear away. Then the cut depth for the trailing cutter 83f will be small, and equal to the wear depth of the immediately adjacent forward cutter 82f. It should be understood that this analysis is somewhat idealized since the exact rate of travel "j" per revolution axially into the rock formation may not be accurately known in advance and can only be estimated when the bit is manufactured. In practice, the drill bit assembly will be constructed with a predetermined distance "p" calculated from the average axial advance for the rock expected to be encountered. At this point, attention should be called to a "fringe benefit" of this arrangement shown in Figures 20 and 21. Quite commonly, the sharp cutters 82f or 83f are made with a very sharp cutting edge 96f. With the cutting edge 96f being very sharp, the cutter 82f or 83f is more susceptible to damage. Thus, when a new drill bit assembly is just starting to be used, there is generally a "break in" period where the engagement of the cutters is kept shallow by reducing axial thrust 77f so that the cutters have time to wear away the sharp cutting edges to some extent. This slight dulling of the sharp cutting edge does not degrade the cutting performance all that much, and it makes the cutter less susceptible to damage when, for example, it comes upon a hard rock formation, since a very sharp edge is more easily fractured. To relate this to the arrangement shown in Figures 20 and 21, the leading cutter 82f initially protects the trailing cutter 83f. As the leading cutter 82f begins to wear away, it exposes the sharp cutting edge 96f of the trailing cutter 83f more gradually. Thus, even though the drill bit assembly 70f is being operated at full capacity to maximize its rate of cutting, the trailing cutters 83f are each provided with their own individual "break-in periods". Thus, if the forward cutter 82f fractures, then the trailing cutter 83f is already "broken in" to function more reliably. Again, it is to be recognized that the arrangement shown in Figures 20 and 21 is rather schematic, and it is evident that this precise grouping and arrangement of cutters would in all likelihood not, by itself, be used in this particular arrangement. However, this embodiment of Figures 20 and 21 does show the arrangement of providing the primary and secondary cutters by varying the axial depth location and placing the cutter units 72f closer to one another along the operating depth reference line, which in Figure 20 would be indicated by the helical path 132f. Thus, in accordance with the prior explanation of the difference between the axial reference depth location and the operating relative depth location, while the two cutters 82f and 83f as shown in Figure 20 are at different axial relative depth locations, they are at the same location relative to the operating relative depth dimension. It is obvious of course that this principle shown in Figure 20 and 21, and also that shown in Figures 18 and 19 could be combined. For example, the trailing cutter 83f could be moved downwardly to some extent so that while still being (relative to axial location) above the cutter 82f, it could still be positioned to accomplish a certain amount of cutting of the rock formation by being below the operating relative depth location. d. Sixth Embodiment (Figures 22, 22a and 23) Components of this sixth embodiment which are similar to components described early herein will be given like numerical designations, with a "g" suffix distinguishing those of the sixth embodiment. For ease of illustration, only one leading cutter 82g and two trailing cutters 83g are illustrated in Figure 22, while a full nine cutters are shown in the end view of Figure 23. For purposes of comparison, attention is directed to Figures 5 and 6, which illustrate the prior art practice of spacing all nine cutters at different circumferential locations, with these being positioned circumferentially in a reasonably balanced configuration to distribute the axial forces applied by engagement with the end rock surface. It will become apparent in comparing Figure 23 with Figure 6 that there is some similarity in that both are provided with nine cutters, and also that these cutters are spaced in a somewhat symmetrically configuration for more even load distribution across the operating face 74g of the cutter housing 76g of the drill bit assembly 70g. However, the location of the cutters has been shifted to obtain the advantage of certain features of the present invention as described previously herein. In the embodiment of Figures 22 and 23, there are provided four units 72g of two cutters each, each comprising a leading or primary cutter 82g and a secondary cutter 83g located on the same circumferential axis as its related primary cutter 82g. There is also provided a single primary cutter 82g at a more central location. Instead of having a total of nine circumferential axes, as in Figure 6, there are only five circumferential axes, numbered one through five in Figure 23. In this embodiment all of the primary cutters 82g lie in the same reference plane 12lg so that all are at the same axial reference depth and all of the secondary cutters 83g lie in the same reference plane 123g. Thus, each unit 72g of cutters are positioned to function in the manner illustrated in embodiment of Figures 20 and 21, where the cutters 82e and 83e of that unit are at different axial depth locations, but are grouped circumferentially with respect to one another so as to be at the same operating depth locations. It is believed that the mode of operation of this sixth embodiment of Figures 22 and 23 is evident from the prior description relative to the fifth embodiment of Figures 20 and 21. Each leading cutter 82g is at the same operating depth as the trailing cutter 83g, and each trailing cutter 83g is circumferentially more closely adjacent to its related primary or leading cutter 82g (i.e. trailing by ninety degrees) , hence each trailing cutter 83g is "protected". Thus, in the event that it's related leading cutter 82g becomes damaged, the trailing cutter 83g is able to follow in the same circumferential path and take over the major "cutting chores" and thus effectively prolong the operating life of the drill bit assembly 70g. Further comparison of Figure 22a to Figure 7 will show that the arrangement of cutters into cutting groups 72g results in much wider cutting groove widths 66g as compared to the width of the cutter 65g. Typically groove width 66g will equal 60% to 80% of cutter width 65g. e. Seventh Embodiment (Figures 24 through 27) Figures 24 and 25 are simply provided for purposes of illustration, and do not employ the teachings of the present invention, while figures 26 and 27 illustrate the seventh embodiment of the present invention. In Figures 26 and 27, the same cutters illustrated in Figures 24 and 25 are rearranged in a manner to incorporate teachings of the present invention and thus constitute a seventh embodiment of the present invention. In discussing Figures 24 and 25, components which are similar to components described previously in this text will be given like numerical designations with an "h" suffix distinguishing those of Figures 24 and 25. It can be seen in examining Figure 25 that there is a plurality of cutters 82h arranged in seven concentric axes 98h. The outermost axis has six cutters 82h positioned symmetrically about the center longitudinal axis 28h and spaced equally at 60° apart. The next four circumferential axes proceeding in an inward direction, each have three cutters 82h, with each circumferential set being symmetrically spaced 120° apart. The two innermost circumferential axes have one cutter 82h apiece. All of these cutters are positioned at the same axial depth location on reference plane 121h. Thus, in accordance with the explanations provided earlier herein, none of these cutters 82h can be identified as primary or secondary cutters or "leading" or "trailing" cutters, and are, in general, subject to equal wear, it being understood that the outermost cutters as a group may tend to wear faster than cutters closer to the longitudinal center axis 28h. Reference is now made to Figures 26 and 27 which illustrate the seventh embodiment of the present invention. Components of the seventh embodiment which are similar to components described previously herein will be given like numerical designations with an "i" suffix distinguishing those of this seventh embodiment. It can be seen from examining Figure 27, that the total number of cutters, and the number of cutters on each circumferential axis 98i is the same as in Figure 25. However, the positions of the cutters have been grouped circumferentially in accordance with the teachings of the present invention. Thus, it can be seen in Figure 27 that the six outermost cutters have been grouped so as to be in two diametrically opposed units 72i of cutters (with three cutters in each unit) . There is thus a primary cutter 82i, and two secondary cutters 83i closely following, in each of the outermost cutter units 72i. Also, it should be noted that the second cutter 83i in line would function (in the event of the primary cutter 82i being disabled) as the primary cutter relative to the third cutter 83i in line. It will be noted that for the third through the sixth circumferential axes, there is for each circumferential axis a group of three cutters closely adjacent to one another, so that in each unit 72i of three cutters, there is the primary cutter 82i and two secondary cutters 83i. These units 72i are also circumferentially positioned in a pattern to substantially balance the axial forces exerted on the cutters 82i and 83i and transmitted into the drill bit housing. As can be seen in Figure 26, which shows only one unit of three cutters 82i - 83i, the cutters 82i-83i are arranged at the same axial depth location. However, the separation angles, indicated as "h" in Figure 27 are quite small ranging from less than 20° for the outer cutter groups 72i to no more than 45° for the innermost cutter groups 72i. Thus, the cutting depth for the trailing cutters 83i will initially be small, expressed as the ratio of h°/360° to the cut depth of the primary leading cutters 82i, as previously described for Figures 18 and 19. However, it is to be understood that the axial relative depth locations could be modified, as shown in the eighth embodiment of Figures 28, 28a and 29, and in the fifth embodiment of Figures 20 and 21. It is believed that the mode of operation of this seventh embodiment of Figures 26 and 27 is readily apparent from the explanations given previously in this text, so this will not be repeated at this time. Briefly each lead cutter 82i cuts to a greater axial depth, thus "protecting" the trailing cutters 83i which will wear at a slower rate and carry more of the cutting load upon damage or excessive wear of the lead cutter 82i. f. Eighth Embodiment (Figures 28, 28A and 29) Components of this eighth embodiment which are similar to components of earlier embodiments will be given like numerical designations with a "j " suffix distinguishing those of this eighth embodiment. This eighth embodiment combines the teachings of the second embodiment (Figures 10 and 11) with the teachings of the fourth embodiment (Figures 18 and 19) , and also with the teachings of the seventh embodiment (Figures 26 and 27) , relative to the use of multiple secondary cutters in a single cutter unit. Figure 28A shows a modification of Figure 28 and incorporates the teachings of the fifth embodiment of Figures 20 and 21, but employing two secondary cutters in each cutter unit. In Figure 28, there is shown only a single cutter unit 144j , where there is a forward positioning cutter 78j, followed immediately by a primary relatively sharp cutter 82j , which in turn is followed by two secondary cutters 83j positioned in line with one another and on the same axial depth reference plane. In this particular arrangement, the primary cutter 82j has its lowermost part of its cutting edge 96j positioned at distance "s" lower than the lowermost contact portion 106j of the positioning cutter 78j, as shown previously in Figure 10, the second embodiment. In Figure 28 there is shown somewhat schematically a line representing the rock surface 20j , the cutting or engagement path 140j of the positioning cutter 78j , and at 142j the projected helical paths of travel of the three cutters 82j and 83j . It can be seen that with the cutters 82j and 83j being at the same axial depth, and closely adjacent along the circular cutting paths 98j , the three helical cutting paths I42j are spaced from one another a rather short vertical distance. With reference to Figure 29, it can be seen that the two outermost cutter units (indicated at 144j) have the four cutters 78j-82j-83j, with the last two cutters 83j being secondary cutters, as shown in Figure 28. The next three radially inward cutter units 146j comprise simply the positioning cutter 78j , one primary cutter 82j , and one secondary cutter 83j . The next inward cutting unit 148j has only a single positioning cutter 78j and a single primary cutter 82j and is thus the same as the cutter combination 78b and 82b illustrated in Figures 10 and 11. The two innermost cutters 82j are simply primary cutters. In this arrangement, the outermost cutting units I44j which are more susceptible to wear and damage have the greatest degree of "backup" with the two backup cutters 83j, and both are on the same circumferential outermost axis 98j . The next three set of cutter units 146j only have the single backup cutter 83j . Also, it will be noted that flush liquid discharge openings 102j provide flushing liquid going into the operating area adjacent to the drill housing surface 74j . It is believed that the operation of this seventh embodiment of Figures 28 and 29 is evident from the explanations given previously in this text. It can be seen in Figure 28 that the primary cutter 82j is so positioned relative to the positioning cutter 78j that the depth of cut "s" (measured from the path 140j of the lowermost contact point 106j of the positioning cutter 78j to the path 142j of the lowermost cutting edge 96j of the primary cutter 82j is controlled by the positioning cutter 78j and is substantially greater than the cut depths along the three paths 142j of the cutters 83j . Thus, it can be appreciated that the primary cutter 82j is carrying the major "cutting chores", while the following cutters 83j each have a very shallow cut at most. Thus, as shown in Figure 28, the cutters 82j-83j are operating in rather the same manner as the cutters 82i-83i shown in Figures 26 and 27. Figure 28A shows a modified axial depth positioning of the cutters 83j relative to the cutter 82j, so that these are positioned all at the same axial reference path along helical path 150j . Thus, it is apparent that the two trailing cutters 83j of Figure 28A are positioned axially at a lesser depth relative to the leading cutter 82j in Figure 28A. Thus, the trailing cutters 83j in Figure 28A are operating in the manner of the trailing cutter 83f as shown in Figures 20 and 21. In both of the arrangements of Figure 28 and Figure 28A, each of the forward primary cutter 82j is carrying the brunt of the cutting load but somewhat protected by positioning cutter 78j which is controlling the maximum cut depth "s". In the event of excessive wear or fracture of the primary cutter 82j, the trailing cutters 83j begin to take over more of the cutting burden. E. Further Embodiments Applying Ultra High Pressure Liquid Jet Cutting a. The Ultra-high Power Jet Cutter (A Ninth Embodiment Shown in Figures 30 and 31) In describing this ninth embodiment, there will be "k" suffices added to the numerical designations, and components of this ninth embodiment which are similar to components previously described will be given like numerical designations, with the "k" suffix distinguishing those of this embodiment. In Figure 30, there is shown the ultra high pressure liquid jet cutter 80k that was described briefly as it is incorporated in the first embodiment of Figures 8 and 9. Figure 31 shows the liquid jet cutter nozzle element 92k to an enlarged scale. It can be seen that the nozzle element 92k is positioned in a cylindrical housing 156k threadedly mounted into the drill bit housing 76k. The housing 156k has a vertical through passageway 158k to receive ultra high pressure liquid (usually water or water with abrasive particles entrained therein) from a passage 160k formed in the housing 76k. The nozzle 92k has an upper cylindrical portion 162k (see Figure 31) having an outer cylindrical surface 164k and a lower downwardly and inwardly tapering portion 166k having a frusto conical outer surface 168k. The nozzle 92k defines an interior through passage 171k having a cylindrical or conical wall 170k. The nozzle element 92k is positioned in the housing 156k so that the frusto conical surface 168k fits snugly within a closely matching frusto conical recess 172k formed in the lower end of the jet cutter housing 156k. There is an ultra high pressure seal assembly 174k positioned around the upper cylindrical surface 164k of the nozzle element 92k and a second ultra high pressure seal 175k between the nozzle housing 156k and drill bit housing 76k. It can be seen that the liquid pressure exerted by the fluid against the interior passageway surface 170k of the nozzle element 92k can be reacted into the adjacent walls of the jet cutter housing 156k. Particularly, with the liquid force in the passageway 158k pressing against the upper end of the nozzle element 92k, the slanted housing surface around the lower frusto conical nozzle element surface 168k exerts radially inward loads on the nozzle element 92k. This can offset the tensile force as generated from the fluid pressure within the nozzle element 92k, thus enabling hard brittle materials like diamond, PDC and TSD that are weak in tension to be used in the ultra high pressure nozzle element 92k without cracking from internal pressure. The angle (indicated at "t") for the frusto conical surface 168k can be varied for different orifice materials and orifice diameters to achieve proper force balance. Normally, it would be expected that this angle "t" would be between about 6° to 30°. The lower surface 177k of the jet cutter housing 156k is covered with a durable wear coating layer 176k, such as Conforma Clad tungsten carbide matrix in order to survive the severe erosion caused by abrasive particles driven by the rebounding ultra high power jet that impinges on the rock surface. It will be noted that this surface 177k and the protective layer 176k have an upward and outward taper to deflect any rebounding liquid and particles radially outwardly from the opening of the nozzle element 92k itself. b. The Ultra High Power Jet Cutter Incorporated In a Single Cutting Unit (Tenth Embodiment - Figures 32 - 35) Figure 32 shows the liquid jet cutter unit 80 of Figure 30 incorporated in a cutter unit which constitutes the tenth embodiment of the present invention. Components of this tenth embodiment which are similar to components described earlier herein will be given like numerical designations, with an "m" suffix distinguishing those of this tenth embodiment. Thus, the cutter unit 72m comprises a forward positioning cutter 78m, followed by the liquid jet cutter 80m, which is in turn followed by a primary, relatively sharp cutter 82m. The positioning cutter 78m functions in substantially the same manner as described previously herein, relative to the relatively sharp primary cutter 82m. Thus, (as described earlier herein) , the lower cutting edge 96m of the cutter 82m is positioned at a slightly greater depth (e.g. 0.05 to 0.15 inches generally) than the lowermost contact point 106m of the positioning cutter 78m. On the other hand, the lowermost surface portion of the protective layer 176m and the lowermost end of the nozzle element 92m are positioned a short distance above the depth position of the lowermost contact point 106m of the positioning cutter 78m. (This spacing distance being indicated at "k" in Figure 32) . This spacing distance "k" should be no greater than about seven times the diameter of the smallest portion of the nozzle element passageway 171m. Normally, the diameter of the smallest portion of the nozzle passageway 171m would be between about .020 to .050 inch, and the spacing distance "k" would normally be between about .050 to .250 inch. Figure 34 shows the cutter unit 72m incorporated in a drill bit assembly 70m. There is a drill stem or string 180m to which the drill bit assembly 70m is removably attached. The drill string 180m has positioned concentrically therein an inner tubular member 182m defining an inner passage 184m to carry the ultra high pressure cutting liquid. This tubular member 182m also defines with the drill stem 180m an annular passageway 186m that carries the flushing liquid. The drill bit housing 76m has a plurality of passageways 188m to carry the flushing liquid to the operating surface 74m of the housing 76m to be discharged through a plurality of flush liquid outlet openings 102m. The drill bit assembly 70m also has a plurality of ultra high pressure liquid passageways 190m that carry the ultra high pressure liquid to the plurality of liquid jet cutters 80m. For ease of illustration, only one flushing liquid passageway 188m and one ultra high pressure liquid passageway 190m are shown herein. It is to be understood, however, that a plurality of such passageways would be provided, or if a single such passageway is provided, there would be a manifold arrangement where a flushing liquid and also the ultra high pressure liquid would be appropriately distributed to respective exit openings 102m or liquid jet cutters 80m. Figure 35 is an end view of the drill bit housing showing a plurality of cutter units 72m incorporating the liquid jet cutter. It can readily be seen by comparing Figure 35 with Figure 9 that the arrangement of the cutter units 72m is substantially the same as that shown in Figures 8 and 9 (which describe the first combined embodiment of the present invention) , except that the trailing cutters 83 of the embodiment of Figures 8 and 9 are not provided. Another important feature of the present invention will now be described with reference to Figures 34 and 35. It can be seen in Figure 34 that the cutter units 78m, 80m and 82m extend below the operating surface 74m of the drill bit housing 76m. Thus, there is around and between each and every cutter 78m, 80m and 82m fluid flow paths between the drill bit surface 74m and the end surface 20m of the rock formation. This is significant with respect to the liquid jet cutters 80m in substantially diminishing the effect of splash back of the ultra high pressure liquid. As the high pressure jet 93m penetrates into the rock formation to make a rather narrow kerf, it will create small rock fragments that will be carried by the liquid at very high velocity. As these strike against the slanted surface provided by the wear resistant cover, these will be deflected laterally outwardly to flow in the liquid passageways, some of which are indicated at 192m. It has been found that if the lower end surface of the wear resistant cover 176m is between about 0.3 to 0.7 inch below the operating surface 74m of the housing 76m, there is adequate space for the liquid flow. This is indicated as distance "u" in Figure 32. To describe the overall operation, the drill stem 180m is rotated and forced downwardly into the rock formation as described previously, and the flushing liquid is discharged through the outlet openings 102m to remove the rock fragments where they are being cut and carry these upwardly around the drill bit housing 76m and upwardly around the drill stem 180m. The operation and functions for the positioning cutters 78m and the stationary sharp cutters 82m is generally the same as described above. It has been found that the addition of the liquid jet cutter 80m between the positioning cutter 78m and the sharp cutter 82m of each cutter unit 72m provides significant benefits. The high velocity liquid jet (indicated at 93m) impinges upon the rock surface 20m to cut a narrow kerf at a central location along the circumferential path of its related cutter unit 72m. This weakens the rock formation along that circumferential path and enables the cutter 82m immediately behind to more easily cut into the rock formation, thus reducing the forces that wear or fracture cutter 82m. At the same time, the presence of the positioning cutter 78m protects the liquid jet cutter 80m from coming into contact with the rock formation and thus being damaged. As described previously herein, with the liquid jet cutter 80m being immediately behind its related position cutter 78m, when a hard rock formation or obstacle is encountered by the positioning cutter 78m, this cutter 78m rides upwardly over the hard rock formation, thus lifting the liquid jet cutter 80m and the cutter 82m upwardly. This maintains the liquid jet cutter 80m a spaced distance above the rock formation, while (as described previously) it limits the depth of cut of the sharp cutter 82m as it arrives at the hard rock section in the formation. c. Improved Results Obtained By Utilizing The Liquid Jet Cutter In Conjunction With the Positioning Cutter and the Relatively Sharp Stationary Cutter To demonstrate the results achieved by this tenth embodiment shown in Figures 32 through 35, tests were conducted as follows, with the results being shown as graphs in Figure 36. First, as a reference, a standard PDC fixed cutter drill bit manufactured by Reed Tool Co. was provided. This drill bit had a drill housing with a diameter of 4.75 inch, and there were provided 3 flush liquid passageway openings extending through the lower operating face of the drill bi . There was a plurality of 16 relatively sharp cutters, such as shown and described at 82 in this application. These were spaced circumferentially around the surface of the cutter, and each of these was positioned in a respective circumferential axis, there being 10 circumferential axes in all. Then there was provided a drill bit assembly 70m such as indicated and described at 70m with reference to Figures 32 through 35. This drill bit assembly had a plurality of cutter units 72m, each of which comprised a positioning cutter, a liquid jet cutter and a trailing relatively sharp stationary cutter (as described at 78m, 80m and 82m) . The drill bit housing was 4.75 inch across, and 4 cutter units (each comprising the positioning cutter, the liquid jet cutter, and the stationary cutter) were provided. Two cutters 82m were provided near the longitudinal center axis along with three flush liquid passageway openings 102m. The cutter units 72m and cutters 82m comprised a total of six circumferential axes. Ultra high pressure water was directed through each of the liquid jet cutters at a pressure of 30,000 PSI. The lowermost surface portion of each Liquid jet cutter was positioned above the lowermost edge portion of its related positioning cutter by a distance of about .05 inch. The lowermost cutting edge of each stationary cutter was positioned about .12 inch below the lowermost surface point of the positioning cutter. The experiment was conducted by utilizing the standard drill bit to drill through Carthage marble (Burlington limestone) sitting inside a pressure vessel and surrounded by ambient fluid pressure of 1,500 PSI. Drilling rates (ROP) at various rotary speeds (rpm) and WOB (weight on bit, i.e. axial thrust) were recorded. Then the drill bit assembly of the present invention, as described immediately above in this section, was also utilized in the same rock sample in a similar fashion. The results of these tests were that, for a similar rpm and wob, the drill bit assembly of the present invention drilled over two times faster than the conventional PDC drill bit. For further comparison, standard tri-cone drill bits were utilized. These were tri-cone bits that are commercially available, including one manufactured by the Reed Tool Co. , Model Q5 and one manufactured by the Security Drill Bit Co. , Model M88F. These comprise three conical elements mounted for rotation about radially extending axes, and based circumferentially around the operating face of the drill bit assembly. As illustrated in the graph, the tri-cone bits drilled only about 1/4 as fast as the bit assembly of the present invention. d. The ultra high power jet cutter incorporated in a single cutting unit with sharp cutters (eleventh embodiment Figures 37, 37a and 38) This eleventh embodiment combines the teachings of the embodiment shown in Figures 18 and 19, the embodiments shown in Figures 20 and 21, and also the embodiments shown in Figures 26 and 27, with the ultra high power jet cutter disclosed in Figures 30 and 31. Components of this eleventh embodiment which are similar to components previously disclosed herein will be given like numerical designations, with an "n" suffix distinguishing those of the eleventh embodiment. In Figure 37, there is shown a single cutter unit 72n comprising a sharp leading or primary cutter 82n, and two trailing or secondary cutters 83n and liquid jet cutter 80n. These cutters 82n and 83n have their lower edge all at the same axial location, and thereby function in somewhat the same manner as the cutters shown in the embodiments of Figures 18 and 19. Also, this arrangement of the cutters is similar to that shown in Figure 28, where three sharp cutters 82j and 83j are shown in that same arrangement. As pointed out in the description of the cutter arrangement in Figure 28, the second cutter 83j which is a secondary cutter relative to the leading sharp cutter 82j will (when the second cutter 83j becomes a primary cutter) act as a primary cutter relative to the third cutter 83j which still at that time is functioning as a secondary cutter. The lowermost surface portion of the protective layer 176n of the liquid jet cutter 80n is positioned a moderate distance above the lowermost helical path 142n of the third sharp cutter 83n. In the operation of the cutter unit 72n shown in Figure 37, initially the lead cutter 82n carries the brunt of the cutting load, while the second and third trailing cutters 83n act as secondary cutters in the manner described previously herein. As the first primary cutter 82n becomes damaged or wears away, then the second cutter 83n becomes the primary cutter, with the third cutter 83n remaining as a secondary cutter. Eventually, at such time as the second cutter 83n is fractured or wears away, then the third cutter 83n becomes the sole primary cutter. At that time, the lower edge portion of the third cutter 83n would still be sufficiently low so as to provide protection for the liquid jet cutter 80n so that it would not become damaged by contact with the rock surface. A modified arrangement is shown in Figure 37A where the three cutters 82n, and 83n are arranged so as to be positioned in the same operating reference line 150n. It will be noted that the lowermost surface portion 176n of the liquid jet cutter 8On in Figure 37A is above this operating line 150n. The cutter unit 72n shown in Figure 37A works in substantially the same manner as that shown in Figure 37, except that the cutters are positioned on the operating reference line 150n, instead of all being at the same axial cutter depth. Figure 38 illustrates the use of the cutter units 72n shown in Figures 37 arranged in an actual drill bit. It will be noted that there are seven circumferential axes, with two full cutter units 72n positioned on the outermost axis. On the fourth, fifth and sixth axis, there are only two sharp cutters 82n and 83n used in conjunction with a single ultra high pressure nozzle 80n. The ultra high pressure jet cutter 8On is not employed in the innermost three circumferential axes. It is believed that the mode of operation of this eleventh embodiment is readily understandable from the explanations given previously in this text. Briefly, the ultra high pressure liquid jet cutter 8On is positioned behind the sharp cutters so that it cuts into the groove or kerf formed immediately ahead by the cutters 82n/83n. This weakens the rock so that on the subsequent pass of the cutters 82n and 83n they are better able to cut into the rock formation. In comparing this to the embodiment of Figures 32 through 35, the cutters 82 and 83 are serving the function of protecting the liquid jet cutter 80n from damage by the rock formation, and in providing a freshly exposed rock surface 142n that can be more easily cut by the liquid cutting jet immediately following the scraping action of the rearmost sharp cutter 83n. It is obvious that various modifications and/or arrangements can be made without departing from the basic teachings of the present invention.

Claims: What is Claimed 1. A rotary drill bit assembly having a longitudinal axis of rotation, said drill bit assembly being adapted to drill into an earth formation to form a drill hole having a hole side wall and a hole end wall, said assembly comprising: a. a drill bit housing having an upper end adapted to be connected to a drill string means and a lower end at which the housing has an operating surface, said housing being configured and arranged for rotation about said longitudinal axis; b. at least one cutter unit mounted at said operating surface along a circumferential cutting path having a circumferential axis at a pre¬ determined radial distance from the longitudinal axis, in a manner that as said drill bit assembly rotates about said longitudinal axis, said cutter unit travels along said circumferential cutting path in a forward direction around said longitudinal axis; said cutter unit comprising: i. a forwardly located lead positioning cutter having a lower relatively hard positioning portion having a downwardly facing relatively blunt contact surface, which contact surface is located axially at a lower positioning location to engage material at the drill hole end wall at said circumferential path; ii. a trailing cutter having a relatively sharp cutting edge portion which is positioned at said circumferential axis rearwardly of said lead positioning cutter at an axial location operationally lower than the contact surface of the positioning cutter, in a manner to be positioned and configured to cut into said drill hole end wall as said drill assembly advances into the drill hole, whereby, in operation, said lead positioning cutter engages the drill hole end wall to locate the drill bit assembly axially relative to the end wall of the drill hole, and thus locate the cutting depth of the trailing cutter axially relative to the circumferential path. 2. The assembly as recited in claim 1, wherein said positioning cutter has a relatively hard material removal surface portion of said contact surface extending forwardly and upwardly from a lowermost positioning surface portion of said contact surface in a manner to be able to engage and remove at least some material from said drill hole end wall. 3. The assembly as recited in claim 2, wherein said material removal surface portion of said positioning cutter is a blunt, forwardly and upwardly slanting surface. 4. The assembly as recited in claim 2, wherein said contact surface of the positioning cutter has side surface portions extending upwardly and laterally from said lower positioning surface portion, relative to said circumferential cutting axis. 5. The assembly as recited in claim 4, wherein said positioning surface portion, said forwardly and upwardly slanting surface portion, and said side surface portions collectively form a downwardly facing generally convexly curved contact surface. 6. The assembly as recited in claim 5, wherein said convexly curved surface has a material engaging surface portion between about 40 to 180 degrees of curvature, and has a radius of curvature between about 1/5 to 1/2 inch. 7. The assembly as recited in claim 6, wherein said degree of curvature is between about 80 to 140 degrees, and said radius of curvature is between about 1/4 to 1/3 inch. 8. The assembly as recited in claim 6, wherein said cutting assembly comprises a plurality of said cutter units, each of which is positioned at a respective circumferential cutting path with the cutting paths each having a respective radial distance from said longitudinal axis, adjacent cutting paths of radially spaced cutting units being spaced radially from one another by a spacing distance no greater than a radially aligned width dimension of said convexly curved contact surface of said positioning cutter. 9. The assembly as recited in claim 4, said cutting assembly comprises a plurality of said cutter units, each of which is positioned at a respective circumferential cutting path with the cutting paths each having a respective radial distance from said longitudinal axis, adjacent cutting paths of radially spaced cutting units being spaced radially from one another by a spacing distance no greater than a radially aligned width dimension of said contact surface of said positioning cutter. 10. The assembly as recited in claim 9, wherein the radially aligned width dimension of said contact surface is between about 60 to 100 percent of the spacing distance of the cutting paths of the radially adjacent cutting units, (greater range of percentage values) . 11. The assembly as recited in claim 10, wherein the radially aligned width dimension of said contact surface is between 80 to 100 percent of the spacing distance of the cutting paths of the radially adjacent cutting units. 12. The assembly as recited in claim 4, wherein: a. said positioning surface portion and said side surface portions of said contact surface comprise a contact surface area having a contact width dimension measured radially from outside edges of the side surface portions of the contact surface; b. said trailing cutter being a fixed cutter having a forwardly facing fixed relatively sharp cutting edge portion having a lower middle cutting edge portion and side cutting edge portions, said cutting edge having a cutting width dimension; c. said contact width dimension being greater than said cutting width dimension in a manner that said side surface portions of contact surface extend laterally beyond a kerf cut by the cutting edge of said trailing cutter. 13. The assembly as recited in claim 12, wherein said contact width dimension is at least one tenth greater than said cutting width dimension. 14. The assembly as recited in claim 13, wherein said contact width dimension is between about 1/10 to 1/4 times greater than said cutting width dimension. 15. The assembly as recited in claim 12, wherein said contact width dimension is no greater than about one quarter times greater than said cutting width dimension. 16. The assembly as recited in claim 2, wherein there is a plurality of said cutter units positioned at said operating surface at different circumferential axes. 17. The assembly as recited in claim 1, wherein there is a plurality of said cutter units positioned at said operating surface at different circumferential axes. 18. The assembly as recited in claim l, wherein: a. said cutter unit travels axially in a generally helical path having a helical axis, as the drill bit assembly, in operation, rotates and travels downwardly as said drill bit assembly removes material from the end wall of the drill hole; b. said assembly having an operational depth dimension reference line, measured at angularly spaced locations around a circumferential axis of said helical path relative to axial distance from said helical path; c. said assembly having an axial depth dimension reference line measured relative to locations on the drill bit assembly along a plane that is fixedly located at an axial location on the drill bit assembly perpendicular to the longitudinal axis; d. said trailing cutter having a lowermost cutting edge portion which is lower, relative to the operational depth dimension line, than a lowermost portion of the contact surface of the positioning cutter. 19. The assembly as recited in claim 18, wherein said lowermost cutting edge portion has an axial location at least as low as the lowermost portion of the contact surface of the positioning cutter, relative to the axial depth dimension reference line. 20. The assembly as recited in claim 19, wherein said lowermost cutting edge portion has an axial location lower than the lowermost portion of the contact surface of the positioning cutter, relative to the axial depth dimension reference line. 21. The assembly as recited in claim 19, wherein said lowermost cutting edge portion is at least about one twentieth of an inch below said lowermost portion of the contact surface, relative to the axial depth dimension reference line. 22. The assembly as recited in claim 21, wherein said lowermost cutting edge portion is no more than about one and one half tenths of an inch below said lowermost portion of the contact surface, relative to the axial depth dimension reference line. 23. The assembly as recited in claim 20, wherein said lowermost cutting edge portion is no more than about one and one half tenths of an inch below said lowermost portion of the contact surface, relative to the axial depth dimension reference line. 24. The assembly as recited in claim 16, wherein said cutter unit comprises a secondary trailing cutter which has a cutting edge and is positioned on said circumferential axis rearwardly of said trailing cutter, which is a primary cutter. 25. The assembly as recited in claim 24 wherein there is a plurality of said cutter units positioned at said operating surface at different circumferential axes. 26. The assembly as recited in claim 24, wherein said secondary trailing cutter has a lowermost cutting edge portion which is at a depth location no higher than the lowermost cutting edge portion of the trailing cutter, relative to the operational depth dimension line of the trailing cutter. 27. The assembly as recited in claim 24, wherein the lowermost cutting edge portion of the secondary trailing edge cutter is at a lower depth relative to the operational depth dimension line of the lowermost edge of the trailing cutter. 28. The assembly as recited in claim 24, wherein the lowermost cutting edge portion of the secondary trailing cutter is at approximately the same depth location, relative to the axial depth dimension reference line as the lowermost cutting edge portion of the trailing cutter, and said secondary trailing cutter is circumferentially closer to said trailing cutter measured in a forward direction of travel to said trailing cutter, in comparison to a circumferential distance measured in a rearward direction of travel circumferentially to said trailing cutter. 29. The assembly as recited in claim 24, wherein there is at least one additional secondary trailing cutter which has a cutting edge and which is positioned on said circumferential axis rearwardly of said secondary trailing cutter, said additional secondary trailing cutter having an operational depth location, relative to said operational depth dimension reference line, no higher than the operational depth location of the trailing cutter. 30. The assembly as recited in claim 29, wherein said lowermost cutting edge portion of the additional secondary edge cutter is at a depth location, relative to the operational depth dimension line of the secondary trailing cutter, lower than the lowermost edge of the secondary trailing cutter. 31. The assembly as recited in claim 30, wherein the lowermost cutting edge portion of the additional secondary trailing cutter is at least as low as approximately the same depth location, relative to the axial depth dimension reference line, as the lowermost cutting edge portion of the secondary trailing cutter. 32. The assembly as recited in claim 18, comprising a liquid jet cutter positioned on said circumferential axis between said positioning cutter and said trailing cutter, said liquid jet cutter being arranged to direct a high velocity liquid jet downwardly against said end wall at a location forwardly of said trailing cutter. 33. The assembly as recited in claim 32, wherein there is a plurality of said cutter units positioned at said operating surface at different circumferential axes. 34. The assembly as recited in claim 32, wherein a lowermost surface portion of a lower surface of said liquid jet cutter is positioned at a depth location above the lowermost portion of the contact surface of the positioning cutter with reference to the axial depth dimension reference line. 35. The assembly as recited in claim 34, wherein said liquid jet cutter has a wear resistant material at said lower surface of the liquid jet cutter, the lower surface of the liquid jet cutter slanting away from a liquid jet discharge nozzle at an upward slant, whereby a splash back resulting from said liquid jet is deflected away from the liquid discharge nozzle. 36. The assembly as recited in claim 35, wherein there is a plurality of said cutter units mounted at the operating surface of the drill bit housing, and said operating surface of the drill bit housing is positioned above lowermost portions of said positioning cutter, said liquid jet cutter, and said trailing cutter, in a manner to provide a liquid flow passage means between said drill hole end wall and said operating surface whereby liquid flow from the liquid jet cutters of the cutter units is able to pass from said operating surface and around said drill bit housing. 37. The assembly as recited in claim 1, comprising a liquid jet cutter positioned on said circumferential axis between said positioning cutter and said trailing cutter, said liquid jet cutter being arranged to direct a high velocity liquid jet downwardly against said end wall at a location forwardly of said trailing cutter. 38. The assembly as recited in claim 37, wherein a lowermost surface portion of a lower surface of said liquid jet cutter is positioned at a depth location above the lowermost portion the contact surface of the positioning cutter with reference to the axial depth dimension reference line. 39. The assembly as recited in claim 38, wherein said liquid jet cutter has a wear resistant material at said lower surface of the liquid jet cutter, the lower surface of the liquid jet cutter slanting away from a liquid jet discharge nozzle at an upwardly slant, whereby a splash back resulting from said liquid jet is deflected away from the liquid discharge nozzle. 40. The assembly as recited in claim 39, wherein there is a plurality of said cutter units mounted at the operating surface of the drill bit housing, and said operating surface of the drill bit housing is positioned above lowermost portions of said positioning cutter, said liquid jet cutter, and said trailing cutter, in a manner to provide a liquid flow passage means between said hole end wall and said operating surface whereby liquid flow from the liquid jet cutters of the cutter units is able to pass from said operating surface and around said drill bit housing. 41. The assembly as recited in claim 37, wherein said cutter unit comprises a secondary trailing cutter which has a cutting edge and is positioned on said circumferential axis rearwardly of said trailing cutter, which is a primary cutter. 42. The assembly as recited in claim 41, wherein there is a plurality of said cutter units positioned at said operating surface at different circumferential axes. 43. A rotary drill bit assembly having a longitudinal axis of rotation, said drill bit assembly being adapted to drill into an earth formation to form a drill hole having a hole side wall and a hole end wall, said assembly comprising: a. a drill bit housing having an upper end adapted to be connected to a drill string means and a lower end at which the housing has an operating surface, said housing being configured and arranged for rotation about said longitudinal axis; b. at least one cutter unit mounted at said operating surface along a circumferential cutting path having a circumferential axis at a pre¬ determined radial distance from the longitudinal axis, in a manner that as said drill bit assembly rotates about said longitudinal axis, said cutter unit travels along said circumferential cutting path in a forward direction around said 5 longitudinal axis; said cutter unit comprising: i. a forwardly located lead primary cutter having a cutting edge with a lowermost 10 cutting edge portion located axially at a lower location at the circumferential path; ii. a trailing secondary cutter having a cutting edge with a 15 lowermost cutting edge portion, said secondary cutter being positioned at said circumferential axis rearwardly of said lead 20 primary cutter; c. said cutter unit being arranged to travel axially in a generally helical path having a helical axis, as the drill bit assembly, in 25 operation, rotates and travels downwardly as said drill bit assembly removes material from the end wall of the drill hole; d. said lead cutter having a lead 30 cutter operational depth dimension reference line, which is coincident with a helical path traveled by said lead cutter, and with location from said lead cutter operational depth dimension lines being measured at angularly spaced locations around said operational depth dimension reference line; e. said lead cutter having an axial depth dimension reference line measured relative to locations from a plane that is located at a fixed axial location on the drill bit assembly perpendicular to the longitudinal axis, and passing through the lowermost edge portion of the lead cutter; f. the trailing cutter being positioned relative to the lead cutter so that the distance of the lowermost edge portion of the trailing cutter is above a depth location of below said operational depth dimension reference line of the lead cutter by a distance of one half the axial distance that the cutter unit travels in one revolution, whereby said lead cutter cuts to a greater material depth along said circumferential path than said trailing cutter. 44. The assembly as recited in claim 43, wherein said trailing cutter has a lowermost cutting edge portion which is at a depth location no higher than approximately the lowermost cutting edge portion of the trailing cutter, relative to the operational depth dimension line of the leading cutter. 45. The assembly as recited in claim 44, wherein the lowermost cutting edge portion of the secondary trailing edge cutter is at a lower depth relative to the operational depth dimension line of the lead cutter, with the trailing cutter being spaced circumferentially rearwardly from said lead cutter a shorter distance than a circumferential distance from said lead cutter forwardly to said trailing cutter. 46. The assembly as recited in claim 43, wherein the lowermost cutting edge portion of the trailing cutter is at approximately the same depth location, relative to the axial depth dimension reference line, as the lowermost cutting edge portion of the lead cutter, and said trailing cutter is circumferentially closer to said lead cutter measured in a forward direction of travel, in comparison to a circumferential distance measured in a rearward direction of travel circumferentially to said lead cutter. 47. The assembly as recited in claim 43, wherein there is at least an additional trailing secondary cutter which has a cutting edge and which is positioned on said circumferential axis rearwardly of said trailing cutter, said additional trailing secondary cutter having an operational depth location, relative to said operational depth dimension reference line, no higher than the operational depth location of the trailing secondary cutter. 48. The assembly as recited in claim 47, wherein said lowermost cutting edge portion of the additional trailing secondary cutter is at a depth location, relative to the operational depth dimension line of the lead cutter, lower than the lowermost edge of the trailing cutter. 49. The assembly as recited in claim 48, wherein the lowermost cutting edge portion of the additional trailing secondary cutter is at least as low as approximately the same depth location, relative to the axial depth dimension reference line, as the lowermost cutting edge portion of the trailing cutter, and said additional trailing secondary trailing cutter is circumferentially closer to said trailing cutter measured in a forward direction of travel to said trailing cutter, in comparison to a circumferential distance measured in a rearward direction of travel circumferentially to said trailing cutter. 50. The assembly as recited in claim 43, comprising a liquid jet cutter positioned on said circumferential axis behind said trailing cutter, said liquid jet cutter being arranged to direct a high velocity liquid jet downwardly against said end wall at a location rearwardly of said trailing cutter. 51. The assembly as recited in claim 50, wherein a lowermost surface portion of a lower surface of said liquid jet cutter is positioned at a depth location above the lowermost portion of the cutting edge portion of the lead cutter with reference to the operational depth dimension reference line. 52. A rotary drill bit assembly having a longitudinal axis of rotation, said drill bit assembly being adapted to drill into an earth formation to form a drill hole having a hole side wall and a hole end wall, said assembly comprising: a. a drill bit housing having an upper end adapted to be connected to a drill string means and a lower end at which the housing has an operating surface, said housing being configured and arranged for rotation about said longitudinal axis; b. at least one cutter unit mounted at said operating surface along a circumferential cutting path having a circumferential axis at a pre¬ determined radial distance from the longitudinal axis, in a manner that as said drill bit assembly rotates about said longitudinal axis, said cutter unit travels along said circumferential cutting path in a forward direction around said longitudinal axis; said cutter unit comprising: i. at least one fixed lead cutter having a cutting edge with a lowermost cutting edge portion located axially at a lower location to engage material at the drill hole end wall at said circumferential path; ii. a liquid jet cutter positioned on said circumferential axis rearwardly of stationary cutter, said liquid jet cutter being arranged to direct a high velocity liquid jet downwardly against said end wall at a location rearwardly of said stationary cutter. 53. The assembly as recited in claim 52, wherein a lowermost surface portion of a lower surface of said liquid jet cutter is positioned at a depth location above the lowermost edge portion of the fixed cutter relative to a stationary plane perpendicular to the longitudinal axes. 54. The assembly as recited in claim 52, wherein said cutter unit comprises a trailing stationary cutter which has a cutting edge and is positioned on said circumferential axis rearwardly of said lead cutter, and forwardly of said liquid jet cutter. 55. A method of drilling into an earth formation to form a drill hole having a hole side wall and a hole end wall, said method comprising: a. providing a rotary drill bit assembly having a longitudinal axis of rotation, with said drill bit assembly comprising: i. a drill bit housing having an upper end adapted to be connected to a drill string means and a lower end at which the housing has an operating surface, said housing being configured and arranged for rotation about said longitudinal 5 axis; ii. at least one cutter unit mounted at said operating surface along a circumferential cutting path having a circumferential axis at a pre- 10 determined radial distance from the longitudinal axis, in a manner that as said drill bit assembly rotates about said longitudinal axis, said cutter unit travels along said 15 circumferential cutting path in a forward direction around said longitudinal axis, said cutter unit comprising: 1. a forwardly located lead 20 positioning cutter having a lower relatively hard positioning portion having a downwardly facing relatively blunt contact surface, which 25 contact surface is located axially at a lower positioning location to engage material at the drill hole end wall at said circumferential path; 30 2. a trailing cutter having a relatively sharp cutting edge portion which is positioned at said circumferential axis rearwardly of said lead positioning cutter at an axial location operationally lower than the contact surface of the positioning cutter, in a manner to be positioned and configured to cut into said drill hole end wall as said drill assembly advances into the drill hole, b. rotating said drill bit assembly with an axial downward force exerted by said drill bit assembly against said end wall, in a manner that said lead positioning cutter engages the drill hole end wall to locate the drill bit assembly axially relative to the end wall of the drill hole, and thus locate the cutting depth of the trailing cutter axially relative to the circumferential path. 56. The method as recited in claim 55, comprising providing said positioning cutter with a relatively hard material removal surface portion of said contact surface extending forwardly and upwardly from a lowermost positioning surface portion of said contact surface, and causing said positioning cutter to engage and remove at least some material from said drill hole end wall, and to ride upwardly and over a relatively hard obstruction in said earth formation. 57. The method as recited in claim 55, comprising providing said cutter unit with a secondary trailing cutter which has a cutting edge, positioned on said circumferential axis rearwardly of said trailing cutter, and positioning a lowermost cutting edge portion of said secondary trailing cutter at a depth location no higher than the lowermost cutting edge portion of the trailing cutter, relative to an operational depth dimension line of the trailing cutter. 58. The method as recited in claim 57, wherein the lowermost cutting edge portion of the secondary edge cutter is at a lower depth, relative to the operational depth dimension line of the trailing cutter, than the lowermost edge of the trailing cutter. 59. The method as recited in claim 57, wherein the lowermost cutting edge portion of the secondary trailing cutter is at approximately the same depth location, relative to an axial depth dimension reference line, as the lowermost cutting edge portion of the trailing cutter, and said secondary trailing cutter is circumferentially closer to said trailing cutter measured in a forward direction of travel to said trailing cutter, in comparison to a circumferential distance measured in a rearward direction of travel circumferentially to said trailing cutter. 60. The method as recited in claim 55, comprising providing a liquid jet cutter positioned on said circumferential axis between said positioning cutter and said trailing cutter, and directing a high velocity liquid jet downwardly against said end wall at a location forwardly of said trailing cutter. 61. The method as recited in claim 60, wherein a lowermost surface portion of a lower surface of said liquid jet cutter is positioned at a depth location above the lowermost portion the contact surface of the positioning cutter with reference to the axial depth dimension reference line. 62. The method as recited in claim 60, wherein there is a plurality of said cutter units mounted at the operating surface of the drill bit housing, and said operating surface of the drill bit housing is positioned above lowermost portions of said positioning cutter, said method further comprising providing a liquid flow passage means between said drill hole end wall and said operating surface and causing liquid flow from the liquid jet cutters to pass from said operating surface and around said drill bit housing.

Inventors: O'HANLON THOMAS ALLEN, O'HANLON, THOMAS, ALLEN
Applicants: FLOWDRIL CORP, FLOWDRIL CORPORATION
Application year: 1995
Main classification: E21B10
IPC codes: E21B10