Drill bit having offset roller cutters and improved nozzles

This invention discloses a rolling cone drilling bit comprising a plurality of conical roller cutters having hard metal cutting elements thereon and being so positioned relative to each other that their rotational axes are offset from the rotational axis of the drill bit, and a drilling fluid nozzle system for directing a pressurized fluid stream across certain of the cutting elements and thereafter against the formation generally at the bottom of the well bore so that when the drill bit is used in its most advantageous areas, such as the soft, medium-soft and plastic formations, the nozzle system prevents "balling up" of the cutters and greatly increases the drilling efficiency of the bit.

BACKGROUND OF THE INVENTION 
This invention relates to a rotary drill bit for drilling oil and gas wells 
in the earth, and more particularly to a rotary drill bit comprising 
generally conical roller cutters having cutting elements thereon which 
engage and "drill" the formation. 
Cutting elements may be of two principal types; namely (1) milled tooth 
type which are relatively long, wide teeth having tapering sides formed by 
machining a steel roller cutter body, and (2) insert type which are 
generally cylindrical studs or inserts of tungsten carbide material press 
fit into bores drilled in a steel roller cutter body. Rotary drill bits 
are characterized as either "milled tooth" bits or "insert" bits, 
depending on which type of cutting element is used. A conventional "milled 
tooth" bit is shown in U.S. Pat. No. 2,148,372 and a conventional "insert" 
bit is shown in U.S. Pat. No. 2,687,875. 
Roller cone rotary drill bits are the most widely used of the various kinds 
of oil field drill bits, because they offer satisfactory rates of 
penetration, as measured in feet per hour, in drilling most commonly 
encountered formations. Milled tooth bits, for example, present an 
aggressive cutting structure for providing relatively high rates of 
penetration in soft formations. Soft formations are typically encountered 
"high in the hole" (e.g., 0 to 5000 feet deep). Moreover, while the teeth 
are of steel and thus subject to relatively rapid wear due to abrasion by 
the formation and erosion by the high-velocity drilling fluid at the 
bottom of the well bore, the time required for tripping the drill string 
in and out of the well bore to replace a worn bit is relatively low. 
Accordingly, in drilling soft formations, the milled tooth bit's high rate 
of penetration outweighs its replacement cost (i.e., bit cost plus trip 
time cost). 
In contrast, insert drill bits, which have relatively small tungsten 
carbide studs or inserts of generally cylindrical or conical shape having 
a blunt tip, are successful in drilling medium and hard formations. Such 
formations are typically encountered "deep in the hole". The success of 
insert drill bits in hard formations is due to the nature of the drilling 
action of such bits and their relatively long useful life as measured in 
the number of feet of formation drilled. As opposed to the teeth of milled 
tooth bits which drill principally by means of a dragging, scrapping or 
gouging action, insert bits drill by means of a compressive loading action 
in which the inserts apply high point loads to the formation. Medium and 
hard formations, which are typically brittle, crack or fracture in 
compression under such point loads. Moreover, tungsten carbide, from which 
the inserts are formed, has high compressive strength and abrasion 
resistance for extended bit life. In deep hole drilling, reducing the 
number of relatively time-consuming (and thus costly) trips for bit 
replacement is critical in reducing overall drilling costs. 
In February, 1970, a new bit design was patented by P. W. Schumacher, Jr. 
(U.S. Pat. No. 3,495,668) which incorporated offset axis cutters to 
provide some measure gouging and scraping cutting action in the drill bit. 
A subsequent patent, U.S. Pat. No. 3,696,876, issued to Ott in October, 
1972, also disclosed a similar invention wherein offset axis cutting 
elements were incorporated into an insert bit. 
Drilling bits incorporating the novel combination of offset cutters and 
tungsten carbide inserts were successfully introduced by the assignee of 
the present invention, Reed Rock Bit Company, in 1970, and have become a 
commonly used type of drill bit in the drilling industry over the past ten 
years. This second generation of drill bits utilize offset axes and 
tungsten carbide insert and are particularly advantageous in soft to 
medium-soft formations by reason of their imparting of some measure of 
gouging and scraping action to the cutting action of the bit which 
enhances the drilling efficiency and rate of penetration of the bit in 
these formations. The amount of offset utilized in these bits ranges on 
the order of from about 1/64 to about 1/32 inch offset per inch of drill 
bit diameter. For instance, a 77/8 inch bit having offset would have from 
1/8 inch to 1/4 inch total offset of the cutters. 
Coventional drilling bits currently on the market are limited in the amount 
of offset introduced into the cutters to about 1/32 inch of offset per 
inch of diameter. Thus, the maximum amount of offset utilized in these 
soft formations bits currently runs about 1/4 inch in a 77/8 inch diameter 
bit. During this ten year period when offset axis insert bits have been 
made commercially successful, those skilled in the art of drill bit 
technology generally have followed the principle that any additional 
offset in the cutters above about 1/32 inch per inch of bit diameter would 
not add any significant efficiency or increased drilling rate to the bit, 
but would increase the tendency of inserts to fail under the shear forces 
such increased offset would introduce. Thus, those skilled in the art have 
restricted their insert bit designs to having an offset range of from zero 
to 1/32 inch per inch of bit diameter. In addition, as the amount of 
offset is increased and some measure of drag cutting action is imparted to 
the drill bit, there is an accompanying increased tendency of certain 
types of formations (i.e., so-called "sticky" formations) to adhere to the 
roller cutters. Over time, this can result in "bit-balling" in which a 
thick layer or coating of cut formation covers the roller cutters, 
limiting the depth of penetration of the cutting elements into the 
formation and reducing rates of drilling penetration. 
Moreover, one drilling application for which neither conventional milled 
tooth nor insert bits have been satisfactory has been the deep hole 
drilling of medium and hard formations, such as Mancos shale and Colton 
sandstone, which become relatively ductile or plastically deformable under 
extreme "over balanced" conditions. Overbalance occurs when the 
hydrostatic pressure at the bottom of the column of drilling fluid in the 
well bore exceeds the pore pressure of the fluid in the formation 
surrounding the well bore bottom. This pressure differential causes 
certain otherwise brittle formations to become ductile. When a 
conventional insert bit is used to drill such formations, the inserts tend 
to deform rather than fracture the formation and thus the rate of 
penetration of the bit is relatively slow. When tooth bits are used to 
drill such a formation, they are rapidly worn and thus provide an 
unsatisfactory useful life. Moreover, over-balance tends to cause "chip 
hold down" in which cuttings from the formation are held at the well bore 
bottom rather than carried away by the drilling fluid. 
Conventional nozzle systems are generally of two types. The oldest type, 
such as shown in U.S. Pat. No. 2,244,617, utilizes large, relatively 
unrestricted fluid openings in the bit body directly above the roller 
cutters to allow a low pressure flow of the drilling fluid to impinge 
directly on the roller cutter bodies and to flow around the roller cutters 
to the bottom of the borehole. By necessity, this is a low-volume, 
low-velocity flow since the fluid stream impinges directly upon the cutter 
face, and erosion of the cones by the fluid stream would be a serious 
problem under these circumstances. The second type of conventional bit 
fluid system comprises the "jet" bits. In a jet bit, a high velocity 
stream of fluid is directed by a nozzle in the bit body against the 
formation face without impinging any cutting elements or any other portion 
of the bit. Impingement of the steel roller cutter body by the stream 
would result in significant erosion. In some instances, the so-called jet 
bits have fluid nozzles extending from the bit bodies to a point only a 
fraction of an inch above the formation face to maximize the hydraulic 
energy of the fluid stream impinging the formation face. Thus, while the 
stream of drilling fluid may at least partially clean the formation before 
being engaged by the roller cutter, it does not clean the roller cutters. 
SUMMARY OF THE INVENTION 
Among the several objects of this invention may be noted the provision of a 
rotary drill bit providing satisfactory rates of penetration together with 
a satisfactory useful life in drilling most commonly encountered 
formations including formations which become ductile or plastically 
deformable under over-balance conditions; the provisions of such a drill 
bit which has improved nozzles for cleaning the roller cutters even when 
drilling ductile or sticky formations; the provision of such a drill bit 
having a heretofore unknown large degree of offset; and the provision of 
such a drill bit in which the roller cutter and the formation are subject 
to separate cleaning actions immediately prior to their engagement for 
enhanced cutting action. 
Briefly, the rotary drill bit of this invention comprises a bit body 
adapted to be detachably secured to a drill string for rotating the bit 
and to receive drilling fluid under pressure from the drill string, the 
bit body having a plurality of spaced apart, depending legs at its lower 
end, and a plurality of nozzles, one for each of said legs for exit of the 
drilling fluid from the body. The bit further comprises a plurality of 
roller cutters, one for each of said legs, rotatably secured to the legs 
at the lower end thereof, each roller cutter comprising a generally 
frusto-conical cutter body and a plurality of powder metallurgy composite 
cutting elements secured to the cutter body. The roller cutters are so 
mounted on the legs of the bit body that the apices of the roller cutters 
are positioned generally toward a central portion of the bit body with the 
axes of rotation of the roller cutters spaced from the longitudinal 
centerline of the bit body a relatively large offset distance (i.e., 
greater than that of the above-described conventional drill bits), whereby 
some measure of drag motion of the cutting elements across the formation 
at the bottom of the well bore is imparted thereto which results in 
enhanced drill bit cutting action but also an accompanying increased 
tendency of the cut formation to adhere to the roller cutters in certain 
formations. Each of the nozzles of the bit has passaging therein directing 
the drilling fluid under pressure to flow downwardly in a stream toward 
the cutter body of one of the roller cutters along a line generally 
adjacent to its cutter body, the drilling fluid impinging at least some of 
the cutting elements on the roller cutter and thereafter impinging the 
formation generally at the bottom of the well bore, whereby the formation 
and the cutting elements impinged by the stream are subjected to separate 
cleaning actions immediately prior to their engagement for presenting 
clean engagement surfaces to further enhance the drill bit cutting action. 
Stated in different terminology, the nozzle passaging directs the drilling 
fluid under pressure to flow downwardly in a stream so angled and 
positioned relative to one of the roller cutters that as this roller 
cutter rotates cutting elements thereon enter the stream for being cleaned 
thereby and then exit the stream prior to engaging the formation. After 
flowing past the cutting elements, the stream of drilling fluid impinges 
the formation generally at the bottom of the well bore. As earlier 
described, the formation and the cutting elements impinged by the stream 
are thus subjected to separate cleaning actions immediately prior to their 
engagement for presenting clean engagement surfaces to further enhance the 
drill bit cutting action. 
The present invention utilizes a unique insert bit design having a 
relatively large degree of offset or offset distance in the cutting 
structure exceeding those ranges utilized in conventional offsetaxis 
insert bits such as the above-described conventional bits. It was found 
through extensive experimentation that when an amount of offset equal to 
or greater than 1/16 inch per inch of bit diameter was introduced into a 
tri-cone insert bit, the rate of penetration and bit performance can be 
significantly increased. For some reason unknown to the inventor, the 
penetration rate and drilling efficiency of an offset insert bit was found 
not to increase from the commonly accepted optimum offset of about 1/32 
inch offset per inch of bit diameter up to about 1/16 inch offset per inch 
of bit diameter. 
In addition to the aforementioned unique drill bit construction, the 
present invention also embodies a new and unique nozzle jetting system for 
directing drilling fluid against cutting elements on the roller cutters to 
clean them and thereafter against the face of the formation to clean it. 
This nozzle system utilizes directed nozzles to direct the stream of 
pressurized drilling fluid across the protruding tungsten carbide inserts 
and thereafter against the formation face. The new nozzle system provides 
a dual function of first cleaning material from the inserts and second 
sweeping the cuttings from the borehole face. This system is particularly 
advantageous when drilling through those certain types of formations 
which, because of their softness or ductility, become very plastic during 
drilling operations, and tend to "ball up" in the spaces between the 
inserts on the cutters and when used in conjunction with a drill bit 
having a relatively large offset distance (i.e. greater than that in the 
above-described conventional drill bits). This "balling up" greatly 
reduces the rate of penetration and the cutting efficiency of drill bits 
when penetrating such plastic formations. The new nozzle system provides a 
plurality of fluid jets directed at preselected angles to spray drilling 
fluid across the inserts without impinging the roller cutter body 
surfaces, with the stream after flowing past the inserts impinging the 
formation to clean the portions of the formation surface which will soon 
thereafter be engaged by the inserts.

DESCRIPTION OF THE PREFERRED EMBODIMENTS 
Referring to FIG. 1, a first embodiment of the drill bit 10 of this 
invention is shown in isometric comprising having a central main body 
section 12 with an upwardly extended threaded pin end 14. The threaded pin 
14 comprises a tapered pin connection adapted for threadedly engaging the 
female end of a drill string and to receive drilling fluid under pressure 
from the drill string. The body section 12 has three downwardly extending 
legs 18 formed thereon, on each of which is rotatably mounted a roller 
cutter 16. A plurality of nozzles 20 (e.g., three nozzles as illustrated) 
are located at the periphery of the body section 12 angled downward past 
cutters 16. In FIG. 2, which is an axial view looking up from the borehole 
toward the bottom of the bit, the cutters 16 of bit 10 are shown to 
comprise a generally frustoconical roller cutter body and a plurality of 
hard metal cutting elements 22 projecting from raised lands 24 formed on 
the surfaces of the cutter bodies. In a typical embodiment, the inserts 
are arranged in three different rows, as gauge row inserts 26, 
intermediate row inserts 28, and nose inserts 30. As is well known in the 
industry, the inserts are secured in the cones by drilling a hole in the 
cutter body for each insert with the hole having a slightly smaller 
diameter than the insert diameter, thus resulting in an interference fit. 
The inserts are then pressed under relatively high pressure into the holes 
and the press fit insures that the inserts are securely held in the cones. 
Although not shown in the drawings, each cutter 16 is rotatably mounted on 
a cylindrical bearing journal machined on each leg 8, as is well known in 
the art. As is also well known in the art, bearings such as roller 
bearings, ball bearings, or sleeve bearings are located between the cutter 
and the bearing journal to provide the rotational mounting. 
In FIG. 3, the cutters 16 are illustrated schematically as simple 
frusto-conical figures. Each cutter cone 16 has an axis of rotation 32 
passing substantially through the center of the frusto-conical figure. The 
central rotational axis of the bit 10 is illustrated as point 34 in FIG. 3 
since FIG. 3 is taken from a view looking directly along the rotational 
axis of the bit. From FIG. 3, it can be seen that because of the offset of 
axes 32, none of the axes intersect axis 34 of the bit. In this flat 
projection, the intersection of the axes 32 forms an equilateral triangle 
36. The amount of offset for a bit is the distance from axis 34 to the 
mid-point of any side of triangle 36. Preferably, the amount of offset is 
greater than about 1/16 inch of offset per inch of drill bit diameter and 
less than about 1/8 inch of offset per inch of drill bit diameter. This is 
in sharp contrast to the commonly accepted theory that the optimum offset 
is approximately 1/32 inch of offset per inch of bit diameter and that 
offsets greater than the optimum result in reduced rates of penetration 
and thus are undesirable. 
Referring now to FIG. 4, in which a cutter layout is illustrated, the 
profiles or cross-sections of each of the cutters on the tri-cone bit of 
the preferred embodiment are layed out in relation to each other to show 
the intermesh of the cutting elements or inserts 22. Generally, each 
cutter in a tri-cone bit is of a slightly different profile in order to 
allow optimum spacing of the inserts for the entire bit. In FIG. 4, the 
three cutters are labeled A, B and C. The C cutter has been divided to 
illustrate its intermesh with both cutters A and B. It should be noted 
that the projections have been flattened out, and because of the 
two-dimensional aspect of this relationship, a distortion in the true 
three dimensional relationship of the cutters is necessary. In FIG. 4, the 
central axis of rotation 34 of the bit is indicated. Each cutter A, B and 
C, has a rotational axis 32 which is offset by a distance Y from an 
imaginary axis 32' which is parallel to the actual axis 32 and passes 
through point 34 which is the bit rotational axis. 
FIG. 5 is a cutter profile which is an overlay of one-half of each of the 
cutters A, B and C to indicate the placement of all of the inserts with 
respect to bottom hole coverage. Each insert in the profile of FIG. 5 is 
labeled according to the particular cutter cone in which the insert is 
located. The angle X is indicated to show the journal angle of the bit. 
The journal angle is the angle that the bearing journal axis, which 
coincides with the rotational axis 32 of the cutter, makes with a plane 
normal to the bit rotational axis 34. 
In this particular embodiment it was found that the preferred range of 
insert protrusion above the cutter surface should be greater than or equal 
to about one-half the diameter of the insert. Any protrusion significantly 
less than one-half the diameter would make the gouging and scraping action 
resulting from the large amount of offset ineffective. The preferred range 
of insert protrusion is from one-half to one times the insert diameter. 
The preferred shape of the protruding portion of the insert is conical or 
chisel. Acceptable alternate shapes are the hemispherical and the 
sharpened hemispherical inserts. 
The inserts may be made of a suitable powder metallurgy composite material 
having good abrasion and erosion resistant properties, such as titanium 
carbide, tantalum carbide, chromium carbide, or tungsten carbide in a 
suitable matrix. The preferred embodiment utilizes tungsten carbide in a 
cobalt matrix. The cobalt content ranges from about 5% to about 20% by 
weight of the insert material, with the remainder of the metal being 
either sintered or cast tungsten carbide, or both. The hardness of the 
inserts is controlled by varying the cobalt content and by other 
well-known methods. The hardness ranges from about 85 Rockwell A to about 
90 Rockwell A. In one particular embodiment, conical inserts having a 
protrusion greater than one-half of their diameter were used, with the 
inserts being made of tungsten carbide-cobalt alloy, having a cobalt 
content of around 12% and a hardness of about 86.5 Rockwell A. 
Referring now to FIG. 6, a schematic sketch of the directed nozzle fluid 
system of the invention is illustrated. In FIG. 6, a generally cylindrical 
jet nozzle 40 is shown connected to bit body 12 and communicating with a 
high pressure drilling fluid passage 42 passing therethrough. Nozzle 40 
has an exit jet or nozzle 44 from which high pressure drilling fluid 46 is 
emitted in a concentrated stream flowing generally toward the underside of 
the adjacent roller cutter 16 (i.e., the half of the roller cutter below 
its longitudinal axis or axis of rotation 32). Bit leg 18 is illustrated 
having conical cutter 16 located thereon. A direction arrow 48 is drawn on 
leg 18 to indicate the direction of movement of the bit leg in the 
borehole as the drill bit is rotated. Likewise, a second rotation arrow 50 
is drawn on cutter 16 to indicate the simultaneous rotation of cutter 16 
with movement of bit 10 in the borehole. The high-pressure drilling fluid 
stream 46 is directed by passaging in the nozzle 40 in a predetermined 
direction such that the fluid stream is either tangent with the surface of 
the roller cutter body or slightly displaced therefrom as shown in the 
drawing. The placement of stream 46 in a tangential relationship with 
cutter 16 allows effective cleaning of inserts 22 as they move through 
stream 46, but also prevents abrasive erosion of the steel cutter shell 16 
which would occur if the stream impinged it directly. Although the 
preferred embodiment is to have stream 46 either tangential to or slightly 
displaced from cutter shell 16, a slight impingement of 46 with cutter 
shell 16 is also contemplated in that such impingement would not be highly 
detrimental due to the very slight angle of incidence of stream 46 against 
the cutter surface. After fluid stream 46 passes the inserts it impinges 
the bottom 52 of the borehole and travels along the bottom picking up 
cuttings that were chipped and gouged from the formation by inserts 22. 
The drilling fluid then passes below the cutter 16 and moves back upward 
outside the drill bit and up through the borehole in the conventional 
manner. 
Thus, the passaging in the nozzles is so angled relative to the bit body 
and roller cutters that the nozzles direct the drilling fluid under 
pressure to exit downwardly and in the direction opposite to the direction 
of rotation of the bit, indicated by arrow 48 in FIG. 3. As earlier 
described, the fluid flows in a high velocity stream 46 at an angle 
relative to the longitudinal axis 34 of the bit body and adjacent to the 
cutter body of the adjacent roller cutter, which is typically of steel 
alloy which has a relatively low resistance to erosion by high velocity 
streams of drilling fluid. As the fluid flows past the cutters, it 
impinges inserts of the gage row of inserts and the row adjacent thereto. 
Being formed of tungsten carbide material having a high erosion 
resistance, the inserts, however, are not subject to significant erosion 
by the stream of high velocity drilling fluid. After flowing past the 
roller cutter, the stream 46 of drilling fluid then impinges portions of 
the bottom 52 of the well bore closely adjacent to, but spaced apart from 
(i.e., ahead or forward with respect to the direction of rotation 48 of 
the drill bit) all of the points of engagement of the inserts of the 
adjacent roller cutter with the bottom of the bore. These portions of the 
well bore bore are cleaned by the high velocity fluid, thereby exposing a 
clean surface at the bottom 52 prior to its engagement by an insert 22. 
It will be observed from the foregoing that the nozzles direct the drilling 
fluid under pressure to flow downwardly in a stream so angled and 
positioned relative to the adjacent roller cutter that as the roller 
cutter rotates cutting elements or inserts thereon enter the stream for 
being cleaned thereby and then exit the stream, with the stream after 
flowing past the cutting elements impinging the formation at the bottom of 
the well bore. Thus the formation and all of the cutting elements impinged 
by the stream are subjected to separate cleaning actions immediately prior 
to their engagement for presenting clean engagement surfaces. These 
separate or sequential cleaning actions have been found to result in 
enhanced drill bit cutting action and increased rates of drilling 
penetration; particularly in drilling sticky formations or formations that 
become ductile or plastically deformable in over-balanced pressure 
conditions, and when used in conjunction with a drill bit hhaving a 
relatively large offset distance, i.e., greater than that of the 
above-described conventional drill bit, such as applicant' drill bit 
having 1/16 to 1/8 inch of offset per inch of bit diameter. In this latter 
regard and as described above, an unwanted side-effect of relatively large 
offset is an increased tendency for the cut formation to adhere to the 
roller cutters of the bit (i.e., an increased tendency to "bit ball"). The 
cleaning of the inserts on the roller cutters immediately prior to their 
engagement with the formation has been found to be effective in preventing 
bit balling in high offset bits, even when used to drill sticky or ductile 
formations. Moreover, the cleaning of areas of the formations at the 
bottom of the well bore to be engaged by the inserts imediately prior to 
the engagement has been found to be effective in presenting a clean 
engagement surface, even when there is severe "chip hold down". 
The drill bit 10 of this invention thus represents a significant 
improvement over conventional drill bits of the type such as shown in U.S. 
Pat No. 3,495,668, in which the nozzles extend generally vertically down 
between adjacent roller cutters. Being so angled, these nozzles direct the 
drilling fluid so as not to impinge the roller cutters but, rather, only 
to impinge the formation at areas substantially forward of the roller 
cutter. The drill bit 10 also represents an improvement over drill bits of 
the type, such as shown in U.S. Pat. No. 4,106,577 and British Pat. No. 
1,104,310, in which the nozzles direct the drilling fluid so as to 
simultaneously engage the cutting elements of the roller cutter and the 
bottom of the well bore (i.e., engage the cutting elements only at their 
points of engagement with formation). 
Referring now to FIGS. 7 and 8, a second embodiment of the directed nozzle 
system is disclosed. This embodiment utilizes a multi-orifice jet nozzle 
which protrudes downwardly from the central area of the bit body toward 
the central area between the three conical cutters. FIG. 7 is a partial 
axial end-view of the bit 10 illustrating two cutters 16 and the location 
of the multi-orifice jet or nozzle 56. Jet 56 is generally cylindrical in 
nature having a bevelled edge 58 at the downward projecting end thereof 
and having three nozzle openings 60 formed through the bevelled surface 
58. A flat, closed end 62 is located at the bottom of the nozzle. A fluid 
stream 64 is shown emanating from one of the openings 60. This spray 
passes across the inserts in the cutters 16 without impinging the roller 
cutter body surfaces. The stream cleans any packed cuttings which may be 
lodged between the various inserts and then moves outward and then 
downward to sweep the bottom of the borehole in front of the cutters as 
they roll into the formation surface. FIG. 8 is a partial side view of the 
bit of FIG. 7 showing a single cutter 16 and the multi-jet nozzle 56. In 
this figure, the nozzle 56 is shown in a cross-sectional diagram and it 
can be seen that the nozzle has a central passage 66 which communicates 
with the nozzle openings 60. Nozzle 56 is securely located in a bore 68 
formed in bit body 12. Bit body 12 has a fluid cavity 70 formed therein 
which communicates with threaded pin end 14 which also is tubular in 
nature. Thus, it can be seen that drilling fluid pumped down the drill 
string passes through threaded pin 14 into bit cavity 70, through nozzle 
bore 66 and out the nozzle opening 60 into a jet or spray 64 which 
impinges the major cutting inserts on cone 16 and then is directed either 
against the face of the borehole or, as shown in FIG. 8, may be directed 
against the wall of the borehole whereupon the fluid moves down the wall 
and across the formation at the bottom of the well bore to pick up 
additional loose cuttings thereon. 
Referring now to FIGS. 9 through 11, a third embodiment of the directed 
nozzle system is disclosed in which the fluid jetting system is directed 
across the main cutting inserts and impinges directly upon the well bore 
bottom. In this embodiment, the projected nozzle arrangement is replaced 
by a slanted jet configuration formed through the wall of the bit body 12 
and communicating with bit cavity 70. FIG. 9 is a partial axial view 
showing part of two cutter cones 16, the bit body 12 and a directed jet 
passage 74. The drilling fluid is emitted from jet passage 74 in a stream 
76 which impinges the major cutting inserts on cones 16 and passes 
downward to impinge the bottom of the borehole. In this embodiment three 
of the jet passages 74 are formed in bit body 12 so that each conical 
cutter 16 has one jet passage associated therewith for sweeping cuttings 
from the inserts and impinging the bottom of the borehole. FIG. 10 is a 
side view of one cutter looking from the central axis of the bit radially 
outward at the cutter. Jet passage 74 passes through bit body 12, 
communicating with the drilling fluid in the drill string by means of 
cavity 70 and pin 14. In FIG. 11 one of the three jet passages 74 is shown 
in communication with cavity 70 and emitting a jet stream 60 of drilling 
fluid passing across the cutting inserts of cutter 16 and impinging the 
borehole bottom. 
Referring to FIGS. 12 through 14, two further embodiments of the directed 
nozzle system of the present invention are shown. In FIG. 12 a drill bit 
is shown in the axial view looking up from the bottom of the borehole. The 
bit has three conical cutters 16 having a plurality of tungsten carbide 
inserts 22 securely held in raised lands 24 on the cutters. A set of three 
peripherally directed nozzles 80 are located around the outer periphery of 
bit body 12, extending downward therefrom into the generally open areas 
between the outer rows of inserts on the conical cutters. The embodiment 
of FIG. 12 utilizes the three directed nozzles which are generally 
cylindrical in nature, each having a bevelled face 82 and a nozzle passage 
84 formed through face 82 and communicating with central bore passage in 
nozzle 80. Nozzle passage 84 is formed such that a directed spray of fluid 
86 is emitted therefrom which impinges across the main cutting inserts of 
the conical cutters which are located clockwise from each nozzle 80. Each 
nozzle passage 84 is aimed in a generally circumferential direction with 
respect to bit body 12 and in a tangential direction to cutter cones 16 
such that the fluid spray emitted therefrom does not impinge squarely on 
the cone 16. Each nozzle 80 having the single jet passage 84 is arranged 
to clean the inserts on the cutter located in a clockwise direction from 
the nozzle. After the spray passes across the main cutting inserts, it is 
directed against the bottom of the borehole to further provide cleaning 
action during the drilling operation. In FIG. 13, a slightly different 
embodiment of the peripheral nozzle system is disclosed in which three 
double jet nozzles 90 are located around the periphery of the bit bottom 
extending downwardly therefrom between the outer edges of the cones 16. 
Each nozzle 90 has two nozzle passages formed therein passing through 
opposed bevelled faces 92 and 94. Thus, each nozzle 90 has a jet passage 
directed at each cutter cone 16 located adjacent thereto. FIG. 14 is a 
diagramatic sketch showing the nozzle 90 from the side and illustrating 
the two bevelled faces 92 and 94. The jet passages 96 pass through the two 
bevelled faces and communicate with an inner bore in nozzles 90. 
Pressurized drilling fluid passes through the drill bit and into the 
nozzles 90 in a manner similar to that of the embodiment shown in FIG. 12. 
The nozzles utilized in the embodiments illustrated in FIGS. 6 through 14 
are preferably formed by casting, forging, and/or machining from a hard 
material such as steel or one of the hard metal alloys such as tungsten 
carbide in a cobalt matrix. The tungsten carbide-cobalt alloy can be of 
the type using sintered tungsten carbide, cast tungsten carbide, or a 
combination of both. Alternatively, the nozzles could be formed of any 
material having good erosion resistant properties. 
Thus, the present invention defines several unique features, one of which 
is the utilization of a heretofore unknown high degree of offset of the 
cutter axes of an insert type bit. Another feature is the novel fluid 
nozzle system which provides a highly efficient cleaning of the protruding 
inserts as well as a cleaning of the formation face as it is being 
drilled. This system directs the high-pressure fluid stream at or near a 
tangent to the cutter cones in a position to sweep the main cutting 
inserts, thereby cleaning any balled up material therefrom, and the fluid 
stream thereafter passes from the insert region to the formation face 
directly, or from the insert region to the borehole wall and then down the 
wall and across the formation face, thereby subjecting the formation and 
the inserts to separate, sequential cleaning actions. 
Thus, as the roller cutters rotate, the cutting elements thereon enter the 
respective stream of drilling fluid for being cleaned thereby and then 
exit the stream prior to engaging the formation, with the stream after 
flowing past the cutting impinging the formation generally at the bottom 
of the well bore. 
Although certain preferred embodiments of the present invention have been 
herein described in order to provide an understanding of the general 
priciples of the invention, it will be appreciated that various changes 
and innovations can be effected in the described drill bit structure 
without departure from these principles. For example, whereas a tri-cone 
bit having three conical cutters is disclosed, it is clear that the bit 
structure could be of the four-cone type, and still embody the principles 
of the present invention. Likewise, the number and location of the 
directed nozzles could be varied from those shown and still obtain 
equivalent operation, function, and results. Thus, all modifications and 
changes of this type are deemed to embraced by the spirit and scope of the 
invention except as the same may be necessarily limited by the appended 
claims or reasonable equivalents thereof.