Jet dual bit

Dual flow passage drilling means includes a dual flow passage sub and a dual flow passage bit. The bit has a threaded tubular pin and a flat seal shoulder there around, adapted to make a rotary shouldered connection with a central box at the lower end of the sub. The bit includes a cylindrical body with a central flow passage and three circumferentially spaced off-axial holes centered 120 degrees apart providing outer fluid passage means communicating through the bit shoulder with the sub's annulus. Beneath the body are earth formation reducing means, including three jet nozzles connected to the off-axial holes. The earth formation reducing means further includes three drilling cones rotatably mounted on three legs depending from the body. The legs are centered 120 degrees apart, for example midway between the nozzles. The diameter of the earth bore is determined by the locus of the outermost parts of the cones as the cones rotate at the bottom of the bore. The outer surfaces of the bit legs and sub are well within the bore diameter. A belt around the bit body above the level of the earth formation reducing means has only a rotating clearance with the earth bore, thereby to seal the bore annulus and centralize the bit tending to keep the legs and sub out of contact with the earth bore. Detritus retention means in the form of single or double webs between the nozzles and legs, or braces between the legs, may be provided.

INDEX 
Background of the Invention 
(a) Single Flow Passage Drill Bit 
(b) Dual Flow Passage Drill Pipe 
(c) Dual Flow Passage Bits 
(d) Annulus Seals 
(i) Seal at Upper End of Drill String 
(ii) Differential Pressure 
(iii) Seal Down Hole Just Above Bit 
(iv) Seal Around Bit 
(1) Without Cones 
(2) With Cones 
(3) With Cones and Sub 
(e) Subs 
(f) Comparison of Dual Conduit Bits with Certain Single Conduit Bits 
(i) Shrouded Single Conduit Bits 
(ii) Core Bits 
(iii) Caisson Bits 
(g) Comparison of Bit Seals, Barriers, or Outside Skirts with Other Forms 
of Bit Flow Control Means 
(i) Weirs 
(ii) Inside Skirt 
(iii) Nozzles or Tubes 
(iv) Outside Skirt 
(v) Examples of Flow Control Means 
(h) Outside Fluid Passage Means 
(i) Single Conduit Bit 
(ii) Fluted bit 
(iii) Hole through Shoulder 
(iv) Off-Axial Holes Through Pin 
(v) Holes Through Pin Shoulder 
(i) Commercial Examples 
(i) Shrouded Security Cross Section Core Bit 
(ii) Skirted Smith Dual Flow Passage Jet Rock Bit 
(iii) Grunder-Williams 
(1) Early Work 
(2) Williams KB-3 
(3) Gruner Integral Bit 
(4) Proposed Modifications 
(5) Gruner G-6 Bits 
(6) Gruner Bits with Elenburg Subs 
(7) Gruner Air Cooled Bits 
(iv) Drilco Dual Pipe 
(v) Dual Subs 
(vi) Skirted Standard Bits 
(vii) Special Dual Flow Passage Bits 
(viii) Reaming Shell and Bridge 
(j) Difficulties with Dual Conduit Down Hole Drilling Apparatus 
(i) Introduction 
(ii) Bit with Sub 
(iii) Seal Bits 
(iv) Summary 
Summary of the Invention 
Brief Description of the Drawings 
Description of Preferred Embodiments 
(a) Dual Conduit Rotary Drill String 
(b) Dual Drill Pipe 
(c) Dual Conduit Drilling Assembly 
(d) Dual Conduit Sub 
(e) Dual Conduit Bit--First Embodiment 
(f) Dual Conduit Bit--Further Embodiments 
(g) Dual Conduit Bit--Second Embodiment 
(h) Dual Conduit Bit--Third Embodiment 
(i) Dual Conduit Bit--Fourth Embodiment 
Claims 
BACKGROUND OF THE INVENTION 
This application pertains to drill bits and more particularly to bits 
adapted for use with dual flow passage drill pipe in the rotary system of 
drilling, employing a drilling fluid such as air, gas, water, oil or mud 
to remove the detritus. 
(a) Single Flow Passage Drill Bit 
Conventional rock bits used with single conduit drill pipe, hereinafter 
sometimes called single flow passage bits because all the flow inside the 
bit is in a single general direction, include three legs depending from a 
tubular body with a toothed cone rotatably mounted on each leg. The upper 
end of the tubular body is threaded for making a rotary shouldered 
connection with the drill string member thereabove, e.g. with a drill 
collar in the case of deep drilling where the drill pipe is run in 
tension, or a stiff drill pipe for shallow holes drilled with a drill rig 
equipped to push down on the drill string. Usually the bit's tubular body 
is threaded as a pin rather than a box. Since drill pipe usually is run 
pin down, a dual box sub or drill collar or drill pipe is usually employed 
between the drill bit and the rest of the drill string. 
(b) Dual Flow Passage Drill Pipe 
It is known to drill earth bores using a string of dual flow passage drill 
pipe. Each length of drill pipe may comprise an outer tube and an inner 
tube with one flow passage provided by the annulus formed between the 
inner and outer tubes and a second flow passage provided by the inner 
tube. See, for example, the patents referred to in U.S. Pat. No. 
4,067,596--Kellner et al. 
(c) Dual Flow Passage Bits 
It is known to employ a dual flow passage drill bit at the lower end of a 
string of such dual flow passage drill pipe. The bit has flow passage 
means communicating with the flow passage through the drill string 
provided by the inner tubes. The drill bit has other flow passge means 
communicating with the flow passage through the drill string formed by the 
annulus passages between the inner and outer tubes. 
Typically, the bit flow passage means communicating with the inner tube of 
the lowermost length of drill pipe in the drill string is a central hole 
in the bit body. Usually the bit flow passage means communicating with the 
annulus flow passage of the lowermost length of the drill pipe comprises a 
plurality of holes through the bit body. 
It is known to provide dual flow passage bits with rolling cutters, with 
drag blades, or with diamond studded downwardly facing abrading surfaces, 
e.g. for drilling hard formations, soft formations, or coring. 
The following patents illustrate certain dual conduit and analogous bits 
and the like: 
U.S. Pat. No. 2,894,727--Henderson 
U.S. Pat. No. 3,198,267--Madson 
U.S. Pat. No. 3,215,215--Kellner 
U.S. Pat. No. 3,578,093--Elenburg 
In addition, reference may be made to many of the further patents listed 
and discussed hereinafter with reference to dual conduit and other forms 
of drilling. 
(d) Annulus Seals 
(i) Seal at Upper End of Drill String 
In early dual conduit drilling, return upflow through the dual conduit bit 
and drill pipe was insured by sealing the annulus at the upper end of the 
drill string using a drilling head or the like. In this regard compare 
some of the following patents: 
U.S. Pat. No. 2,543,382--Schabarum 
U.S. Pat. No. 3,208,539--Henderson 
U.S. Pat. No. 3,795,283--Oughton 
Such an arrangement, however, is little better than the practice known as 
"split-streaming" in which loss to the annulus is merely tolerated, for 
with a seal at the upper end of the annulus the annulus capacity must be 
satisfied before fluid loss stops; also, the formation may be permeable, 
causing continuous lost circulation 
(ii) Differential Pressure 
Sometimes the annulus adjacent the bit is pressurized, either with a heavy 
fluid or with a gas under pressure, to prevent fluid flow up the annulus. 
(iii) Seal Down Hole Just Above Bit 
It has also been disclosed that an annulus seal may be placed down the hole 
just above the bit. In this connection, compare some of the following 
patents: 
U.S. Pat. No. 2,234,454--Richter (hood 55) 
U.S. Pat. No. 2,550,080--Moore (packer or cup 7) 
U.S. Pat. No. 2,657,016--Grable (packer 75) 
U.S. Pat. No. 2,885,184--Ortloff et al. (seal 15) 
U.S. Pat. No. 3,155,179--Hunt et al. (packer seal ring or collar 38) 
U.S. Pat. No. 3,283,835--Kellner (packer sealing element 28) 
U.S. Pat. No. 3,417,830--Nichols (packer 70) 
U.S. Pat. No. 3,503,461--Shirley (packer P) 
U.S. Pat. No.3,638,742--Wallace (seal means S-1) 
U.S. Pat. No. 3,655,001--Hoffman (skirt 158) 
U.S. Pat. No. 3,712,392--Dela Gorgendiere (sleeve 16) 
(iv) Seal Around Bit 
It is also known to provide a down hole seal or barrier between the well 
bore and drilling means by providing the latter with a portion of full 
hole diameter. The full hole diameter portion tends to seal with the side 
of the hole being bored, thereby to cause fluid flowing out of one of the 
bit flow passage means to flow back up the outer bit flow passage means 
rather than into other places such as the space in the bore hole around 
the drill pipe. In this connection compare some of the following patents 
and other disclosures: 
(1) Core Bit Type--No Roller Cutters 
British Pat. No. 309,101--Rotinoff (1929)-Dredge (No Rotation) 
U.S. Pat. No. 1,133,162--McAllister 
U.S. Pat. No. 1,547,461--Steele 
U.S. Pat. No. 2,016,785--Lawlor 
U.S. Pat. No. Re. 26,669--Henderson (Seal Also at Face of Bit) 
U.S. Pat. No. 3,583,502--Henderson 
U.S. Pat. No. 3,807,514--Murrell 
(2) Dual Flow Passage Roller Cone Bit 
U.S. Pat. No. 3,151,690--Grable (Splined Seal Sleeve) 
U.S. Pat. No. Re. 27,316--Elenburg (Orig. 3416617) 
U.S. Pat. No. 3,416,618--Kunneman 
U.S. Pat. No. 3,542,144--White 
(3) Modified Single Flow Passage Roller Cone Bit plus Special Sub 
U.S. Pat. No. 3,439,757--Elenburg 
U.S. Pat. No. 3,596,720--Elenburg 
U.S. Pat. No. 3,667,555--Elenburg ps where the full hole or seal portion 
rotates with the drill string, there will be a certain amount of 
clearance, i.e. a rotating clearance, between the well bore and the seal 
portion. Such a portion is therefore sometimes called a barrier rather 
than a seal. However, the rotating clearance is filled with detritus and 
drilling fluid so that it may actually seal. 
(e) Subs 
As mentioned above, to facilitate stabbing when making up drill string 
connections, the drill string components, e.g. drill pipe and drill 
collars, are usually run with the threaded pins lowermost. This is true of 
dual tube drill pipe and drill collars as well as for single conduit drill 
pipe and collars. On the other hand, for various reasons, e.g. to prevent 
wobble off, drill bits are usually provided with upstanding threaded pins 
rather than with threaded boxes. This holds true for dual flow passage 
bits as well as for single flow passage bits. 
In order to connect a bit having a threaded upstanding pin with a drill 
collar having a threaded pin on its lower end, double box drill string 
member, for example a double box sub is interposed therebetween. 
A sub provides an opportunity to switch from outer tube threaded 
connections present in the drill stem of a dual conduit drill string to an 
inner tube threaded connection between the dual bit and sub. Having the 
bit threaded on the inner flow passage between bit and sub, the outer flow 
passage means is connected through the tool joint shoulder, there being a 
plurality of passages or ports through the drill bit shoulder 
communicating with the dual sub annulus forming its outer flow passage 
means. In this connection compare the disclosure of U.S. Pat. No. 
3,542,144--White (supra). 
A single flow passage bit can therefore be readily modified for dual flow 
by a machine shop or the manufacturer. It is only necessary to cut back 
the bit shoulder a little in order better to receive the shoulder of the 
dual box sub and to bore ports through the bit body between the bit legs. 
For an even simpler conversion the sub may be provided with a skirt 
extending down around the outer periphery of the bit body forming a flow 
passge exterior to the bit body. Such a construction is exemplified by 
U.S. Pat. No. 3,439,757--Elenburg (supra). This type of construction is 
believed now to be more or less standard for dual conduit drilling as 
currently practiced. 
In connection with subs, or the like, with skirts or skirt-like 
configuration or wherein ports above cutters direct flow to the outside 
part of the hole, compare some of the following patents: 
U.S. Pat. No. 597,316--Durbrow 
U.S. Pat. No. 701,547--Davis 
U.S. Pat. No. 1,685,045--Clarke 
U.S. Pat. No. 1,721,921--Phipps et al. 
U.S. Pat. No. 2,238,895--Gage 
U.S. Pat. No. 2,293,259--Johnson 
U.S. Pat. No. 2,419,738--Smith 
U.S. Pat. No. 2,543,382--Schabarum 
U.S. Pat. No. 2,562,346--Whittaker 
U.S. Pat. No. 2,849,214--Hall 
U.S. Pat. No. 3,077,358--Costa 
U.S. Pat. No. 3,102,600--Jackson 
U.S. Pat. No. 3,155,177--Fly 
U.S. Pat. No. 3,268,071--Yarbrough 
U.S. Pat. No. 3,713,488--Elenburg 
(f) Comparison of Dual Conduit Bits with Certain Single Conduit Bits 
Dual conduit bits, i.e. bits intended for use with dual conduit drill pipe, 
are related both to single conduit bits intended for reverse circulation 
and to core bits employing local reverse circulation at the bottom of the 
hole, and to caisson bits, but there are certain basic differences as will 
be discussed in the following: 
(i) Shrouded Single Conduit Bits 
Single conduit bits, especially when used for reverse circulation, have 
been provided with webs or "shrouds" extending between the bit legs or 
with a skirt extending about the cutter blades to insure that drilling 
fluid flowing down the annulus will reach bottom before turning inwardly 
across the cutters to flow up the center of the bit. This is to insure 
that cuttings are swept up and that the cutter cones or blades are 
cleaned. Such "shrouded" or "skirted" bits are usually field modifications 
of ordinary single conduit bits, so the literature about them is not 
extensive. 
In connection with shrouded or skirted single conduit reverse circulation 
bits, compare some of the following U.S. patents: 
U.S. Pat. No. 1,236,981--Reed 
U.S. Pat. No. 1,289,179--Hughes 
U.S. Pat. No. 1,582,332--Brutus 
U.S. Pat. No. 1,778,966--Stokes 
U.S. Pat. No. 2,020,625--Thaheld 
U.S. Pat. No. 2,261,546--Gipson 
U.S. Pat. No. 2,849,214--Hall 
U.S. Pat. No. 3,174,564--Morlan 
U.S. Pat. No. 3,292,719--Schumacher, Jr. 
It is to be noted that whether a shrouded or skirted single conduit bit is 
used for reverse or direct circulation, there is flow of drilling fluid 
past the outside of the skirt, for which reason the skirts may be called 
inside skirts. An inside skirt is necessarily not full gage, i.e. its 
outer diameter is not that of the hole being bored, since there must be 
room between the outer surface of the skirt and the wall of the hole for 
fluid to flow. 
(ii) Core Bits 
U.S. Pat. No. 2,698,737--Dean shows a core drill. In core bits, since the 
center of the bit must be open to allow passage of the core, the passages 
for drilling fluid are annularly disposed around the bit axis within the 
tubular wall forming the body of the bit. The bit thus has two passage 
means, one in the center for the core and the other comprising annularly 
disposed fluid passages for down flow of the drilling fluid. In additon, 
since face type cutting means, i.e., surfaces studded with diamonds or 
tungsten carbide or milled and hardened teeth, are used to abrade the hole 
bottom, the bit body has an outwardly cylindrical appearance similar to 
that of a shrouded bit. 
However, in the conventional core bit, the drilling fluid exiting the 
bottom of the bit must flow across the bottom face of the bit and back up 
the outside of the bit body, so the body is not full hole in diameter. 
Also, the central passage of the drill bit is not a regular flow passage 
for drilling fluid; the core moves through the central passage into a 
blind or valve controlled core tube. 
(iii) Caisson Bits 
In caisson type drilling, a casing, usually having a sharpened lower edge, 
is lowered into a hole as the material in the center is removed, e.g. by a 
rotary drill. In such case the drilling fluid may flow through the central 
drill pipe and up or down on the inside of the casing in the annulus 
between the casing and pipe according to whether direct or reverse 
circulation is used for the rotary or other drill. The casing may extend 
closer to the hole than the skirt on a single conduit shrouded bit or the 
body of a core bit, but the casing does not rotate with the bit and is not 
part of the bit. 
In connection with caisson type drilling, compare the disclosures of some 
of the following patents: 
U.S. Pat. No. 146,202--Pontez 
U.S. Pat. No. 1,306,674--Esseling 
British Pat. No. 407,111--Rotinoff 
U.S. Pat. No. 2,485,098--Johnson 
U.S. Pat. No. 3,381,766--Bannister 
U.S. Pat. No. 3,674,100--Becker 
(g) Comparison of Bit Seals, Barriers, or Outside Skirts, with Other Forms 
of Bit Flow Control Means 
In closed circulation drilling, there may be provided at the lower end of 
the dual conduit drill string drilling means (bit or bit plus sub) some 
suitable flow control means for directing the down flowing drilling fluid 
and receiving the spent fluid for return to the drill string and upflow to 
the surface. The flow control means may be provided by the dual conduit 
bit alone, or by the bit in combination with a sub. Such means for 
controlling the direction and location of flow at the bottom of the hole 
come in a variety of forms which may be classified as weirs, inside 
skirts, nozzles or tubes and outside skirts, as discussed hereinafter. 
(i) Weirs 
If, as is usual in closed circuit drilling, the fluid flow is down the 
drill string (dual flow passage drill pipe) annulus and up its inner tube 
and assuming like flow in the drilling means (bit) at the bottom of the 
hole, there may be provided an annular weir around the central flow 
passage of the bit to direct down flowing drilling fluid to the bottom of 
the hole before it is allowed to return upwardly. Such a weir is similar 
to an inside skirt to the extent that there is fluid flow past its 
outermost surface but differs therefrom in that a weir is closer to the 
central flow passage of the bit than an inside skirt. 
(ii) Inside Skirt 
Inside skirts, previously discussed in connection with shrouded, single 
conduit drill bits, may also be employed with the drilling means (bit) at 
the bottom of the hole in closed circuit (dual conduit) drilling. For 
example, when the down flowing fluid is directed to the outside of the 
cutters and it is desired that the fluid flow to the bottom rather than 
between the cutters before entering the central, upflow fluid passage 
means in the drilling mechanism, such a skirt may be employed between the 
down flowing fluid and the cutters. 
(iii) Nozzles or Tubes 
Nozzles or tubes whose inlets receive down flowing fluid may jet or 
positively conduct the fluid toward the cutters or between the cutters 
toward the bottom of the hole, after which the fluid returns up through 
the bit. Nozzles or tubes may be viewed as serving a function similar to 
weirs and inside skirts but differing therefrom in that the fluid flow is 
down inside the nozzles or tubes rather than down the outside thereof. 
(iv) Outside Skirt 
An outside skirt, that is, one which is outside the flow of drilling fluid, 
may be employed in the drilling means at the bottom of a closed 
circulation drill string, for directing fluid from the drill string 
annulus down around the outside the drill bit to the bottom of the hole. 
Such an outside skirt typically would be part of a sub to which the bit is 
to be connected. 
(v) Examples of Flow Control Means 
Various flow control means for closed circuit dual conduit bits are shown 
in the patents listed previously. In connection with other forms of dual 
conduit drilling with flow control means, compare the disclosures of the 
following patents: 
U.S. Pat. No. 3,195,661--Jackson et al. (Nozzles and Weir) 
U.S. Pat. No. 3,297,100--Crews (Tubes) 
U.S. Pat. No. 3,762,486--Grovenburg (Jets and Baffles) 
See also the following patents: 
British Pat No. 11,902/1902--Grumbacher 
German Pat. No. 334,834--Siemens (1919) 
U.S. Pat. No. 1,615,921--Thompson 
British Pat. No. 448,559--Schweitzer (1936) 
U.S. Pat. No. 2,329,405--Mann 
British Pat. No. 744,044--Coal (1952) 
U.S. Pat. No. 2,701,122--Grable (1955) 
French Pat. No. 1,437,230--Salzgitter (1965) 
British Pat. No. 1,018,950--Hydraulic (1966) 
(h) Outside Fluid Passages 
One of the fluid passages in a bit employed in dual conduit drilling is 
almost always a central hole in the bit. This passage may be called the 
inner fluid passage means, and the remaining fluid passage means may be 
called the outer fluid passage means. Some of the patents discussed or 
listed above may be reclassified according to their outer fluid passage 
means as follows: 
(i) Outer Fluid Passage Holes Do Not Enter Bit--Single Conduit Bit. 
U.S. Pat. No. 1,685,045--Clarke 
U.S. Pat. No. 2,234,454--Richter 
U.S. Pat. No. 2,238,895--Gage 
U.S. Pat. No. 2,293,259--Johnson 
U.S. Pat. No. 2,419,738--Smith 
U.S. Pat. No. 2,550,080--Moore 
U.S. Pat. No. 2,562,346--Whittaker 
U.S. Pat. No. 2,849,214--Hall 
U.S. Pat. No. 3,102,600--Jackson 
U.S. Pat. No. 3,198,267--Madson 
U.S. Pat. No. 3,439,757--Elenburg 
U.S. Pat. No. 3,503,461--Shirley 
U.S. Pat. No. 3,542,144--White 
U.S. Pat. No. 3,638,742--Wallace 
U.S. Pat. No. 3,655,001--Hoffman 
(ii) Outer Fluid Passages are Slots in Exterior of Bit With Skirted Sub 
U.S. Pat. No. 3,596,720--Elenburg 
(iii) Outer Fluid Passage Holes Through Box Shoulder 
U.S. Pat. No. 1,547,461--Steele 
U.S. Pat. No. Re. 26,669--Henderson (3308896) 
U.S. Pat. No. 3,583,502--Henderson 
U.S. Pat. No. 3,215,215--Killner 
U.S. Pat. No. 3,151,690--Grable 
U.S. Pat. No. Re. 27,316--Elenburg (3416617) 
U.S. Pat. No. 3,416,618--Kunnemann 
U.S. Pat. No. 3,195,661--Jackson et al 
U.S. Pat. No. 2,329,405--Mann 
U.S. Pat. No. 2,657,016--Grable 
U.S. Pat. No. 3,807,514--Murrell 
(iv) Outer Fluid Passage Holes Through Pin 
British Pat. No. 309,101--Rotinoff (1929) 
U.S. Pat. No. 1,133,162--McAllister (1915) 
U.S. Pat. No. 1,721,921--Phipps 
U.S. Pat. No. 2,894,727--Henderson 
U.S. Pat. No. 3,208,539--Henderson 
U.S. Pat. No. 3,795,283--Oughton 
U.S. Pat. No. 3,283,835--Kellner 
(v) Outer Fluid Passage Holes Through Pin Shoulder 
U.S. Pat. No. 3,198,267--Madson 
U.S. Pat. No. 3,542,144--White 
(i) Commercial Examples 
(i) Shrouded Security Cross Section Core Bit 
A paper dated May, 1959 entitled "Reverse Circulation Drilling with a 
Hinderliter Tool and Adapted Security Bit" by Earl Smith, described a core 
drilling program by Shell Oil Company employing continuous coring. Reverse 
circulation was employed. Reference was made to prior activity by 
Hostetter in which the hole was cased with drive casing to prevent loss of 
annulus drilling fluid. The Shell program employed instead a Hinderliter 
sub, just below the kelly, to provide for quick switching between direct 
and reverse circulation. The sub included an annular seal just above the 
annulus fluid port. A modified Natland core bit (Security) was employed, 
the modifications including removal of the core catcher and tube, 
enlarging the hole in the bridge, and "shrouding between the legs of the 
bit to direct the mud stream to the bottom of the hole." Note that in this 
case the mud flows down outside the shrouds. 
(ii) Skirted Smith Dual Flow Passage Jet Rock Bit 
H. C. Smith Oil Tool Company, predecessor of the Smith Tool division of 
applicant's assignee, is believed to have offered for sale, though not 
built, a skirted jet bit with a central return flow passage or tube for 
use in reverse circulation drilling employing Grable dual flow passage 
drill pipe. See Drawing No. 7079--H. C. Smith Oil Company entitled "7-5/8 
3CF2P For Nitrogen Reverse Circulation" (4-21-57). Note that in this 
construction fluid flows down through tubes which are inside of skirts 
between the bit legs, and that the skirt extends below the tubes to about 
the lower extremities of the bit legs. Bits the same as shown in the 
drawing except without the skirts are believed to have been built, sold 
and used. 
(iii) Gruner-Williams 
Applicant's assignee, Smith International, Inc., acquired Gruner & Company, 
which was an offshoot of Williams Rock Bit Company, also acquired by 
applicant's assignee. Masson, operator of a nearby machine shop, produced 
bits for William and Gruner. 
(1) Early Work 
It is understood from interviews with Masson and Williams that they skirted 
rock bits as far back as 1929 and sold toothed skirted bits to Canada in 
about 1952-54. 
(2) Williams KB3 
It is understood that about 1972 Masson made some bits for Williams Rock 
Bit Company of Tonkawa, Oklahoma, as advertised on page 10 of that 
company's 1973 catalog under the title "Small Button Bit" whereat it is 
stated: 
"The KB3 can be machined for use with dual pipe for reverse circulation." 
See also drawing bearing notation N-Rod Thread which appears to show a 
drill string member or sub to be connected to a KB3 bit. 
(3) Gruner Integral Bit 
It is understood that the modified KB3 became inactive in favor of a dual 
bit exemplified by the accompanying photo and sketches. This bit has a one 
piece annular bit body which is bored out from solid bar stock to provide 
a central flow passage therethrough. A straight threaded tubular pin at 
the top of the body screws into a box at the lower end of the inner tube 
of a dual sub and is in communication with the flow passage through the 
inner tube of the sub. The outer tube of the dual sub seals on an outer 
shoulder lower down on the bit body than the shoulder around the pin. 
Off-axial holes in the body extend down from the upper shoulder to the 
underside of the body. The tops of the holes are in between the inner tube 
and outer tube of the sub to receive drilling fluid from the annulus of 
the sub. The lower part of the body is conically counterbored to form a 
downwardly flaring sleeve. The sleeve is slotted to receive bars on which 
roller cutter cones are mounted, the bars being welded to the sleeve. The 
lower ends of the holes in the body terminate in the sleeve in between the 
slots. 
(4) Proposed Modification 
As shown on the photo, it has been proposed to modify the above-described 
bit by omitting the off-axial holes through the body and by providing 
flats on the exterior of the body. In this latter regard compare the 
construction shown at: pages 4922, 4923 of the 1970-71 edition of the 
Composite Catalog of Oil Field Equipment and Services illustrating the 
diamond drill bits and core bits of the former Williams division of 
applicant's assignee. 
(5) Gruner G-6 Bits 
Gruner's "Granite 6" bits are advertised on pages 4 and 5 of Gruner's 
catalog entitled "Gruner Rock Bits". Similar bits have also been made with 
integral aprons or shrouds between the legs for reverse circulation. 
Williams also makes such bits and welds on the skirts. For Williams' bits 
see pages 4612, 4613 of the 1972-73 edition of the Composite Catalog of 
Oil Field Equipment and Services. 
(6) Gruner Bits with Elenburg Subs 
Gruner bits with the upper part of the body turned down to receive the 
skirt of an Elenburg-type skirted sub are illustrated in the accompanying 
drawing. 
(7) Gruner Air Cooled Bits 
Gruner bits with air passages in the legs to supply air to the cone 
bearings to cool them are shown in a U.S. patent application entitled "Air 
Cooled Bit" filed January of 1975 by R. D. Thomas, now abandoned. 
(iv) Drilco Dual Pipe 
Drilco Industrial, division of applicant's assignee, makes dual flow 
passage drill pipe, e.g. as shown in the accompanying copy of its house 
magazine "D.I. Diary" Vol. 1 No. 6 for May-June, 1975. 
(v) Dual Subs 
Dual flow passage subs have been furnished to Drilco Industrial. See the 
accompanying drawing of a dual sub. 
(vi) Skirted Standard Bits 
Various concerns offer three cone (jet and regular) bits. See for example: 
pages 5138, 5139 and 5144 of the 1974-75 edition of the Composite Catalog 
of Oil Field Equipment and Services, advertising Varel bits, and 
pages 2744, 2745 and 2746 of the 1974-75 edition of the Composite Catalog 
of Oil Field Equipment and Services illustrating Hughes bits, and 
pages 1704, 1705 of the same catalog, advertising Dresser-Security bits. 
It is understood that at various times, either in this country or in 
Canada, such bits have had shrouds or skirts added between the bit legs. 
(vii) Special Dual Flow Passage Bits 
Dual flow passage bits and related equipment are offered for sale by 
Walker-Neer at pages 5215-5218 of the 1974-75 edition of the Composite 
Catalog of Oil Field Equipment and Services and by 
Dresser OME (Security) at page 1675 of the 1970-71 edition of the same 
catalog. 
Note also Security's regular bit shown at page 1663 thereof. The 
Walker-Neer and Dresser dual bits may be compared with the core and 
drilling bits offered by 
Christiansen Diamond Products Company at pages 1262-1265 of the 1952 
edition of the Composite Catalog of Oil Field Equipment and Services. 
(viii) Reaming Shell and Bridge 
A Walker-Neer brochure designated Service 2183 refers to a variety of dual 
flow passage equipment including a dual swivel, dual pipe, box-type rock 
bits, coring bits, and a reaming shell and bridge. 
(j) Difficulties With Dual Conduit Down Hole Drilling Assemblies 
(i) Introduction 
It has already been pointed out that absent a down hole annulus seal, much 
fluid may be lost filling the annulus and flowing into the formation. A 
down hole seal just above the bit but separate therefrom has the 
disadvantage of consitituting an additional piece of equipment to be 
purchased, installed, and replaced. Full hole bits in which the bit body 
is close to full gage at cutter level are apt to get stuck in the hole. 
(ii) Bit with Sub 
Since single flow passage roller cone bits are easily modified for reverse 
circulation by welding plates between the bit legs, as shown, for example, 
in the above-listed article by Earl Smith (1950), the commonly used 
arrangement for dual flow drilling is the addition of a skirted dual sub, 
to such a shrouded single flow passage bit, the skirt on the sub 
performing the dual functions of: 
(1) cooperating with the outer surface of the bit legs and shroud to form 
an outer flow passage, and 
(2) cooperating with the inner periphery of the earth bore to seal the 
annulus between earth bore and drill string. 
Such a combination has two problems: 
(a) the skirt makes a very close fit with the earth bore and may wear out 
as fast or faster than the bit. 
(b) the skirt, extending close to the bottom of the hole and being of 
nearly full bore diameter, is apt to get stuck in the hole, the bottom of 
the hole being only partially completed and containing detritus. 
Some bit and subassemblies using short shirts, e.g. as shown in the 
above-listed Gruner-Williams patent application, fail to get the drilling 
fluid to the bottom of the hole as fast as desirable. 
(iii) Seal Bits 
It has long been known that a complete dual bit could be provided, not 
requiring the use of a skirted sub. See, for example, the above-listed 
Steel patent of 1925 showing a bit employing fixed blades, and the 
aforelisted Smith Tool Company Drwg. No. 7079 of 1957. It will be noted 
that in both of these constructions, the bit is near full gage near the 
bottom of the bit, so that it may be expected that such bits will become 
stuck in the hole. 
One can speculate that the reason fixed blade dual bits, such as that of 
Steele, carried the full gage diameter close to the hole bottom, was a 
desire to give bottom support to the outermost portions of the fixed 
blades, coupled with lack of appreciation of the likelihood of a bit so 
constructed getting stuck in the hole. 
As for roller cutter construction, such as shown in the Smith Tool Company 
drawing, one can speculate that the provision of shrouds between the bit 
legs was in the tradition of modifying ordinary single flow passage bits 
for reverse circulation at the customer's request and at minimum expense, 
and the full gage part of the shrouds had to be close to the bottom of the 
bit where the bit leg was of largest diameter (to give maximum support for 
the roller cones), upper parts of the bit leg extending radially to a 
lesser distance. 
For whatever the reason, it appears that the tradition of carrying the seal 
down close to the bottom of the hole adjacent to the bottom elements of 
the roller cones was continued in later designs, as exemplified by the 
above-listed U.S. patents: 
U.S. Pat. No. Re. 27,316--Elenburg 
U.S. Pat. No. Re. 3,416,617--Elenburg 
U.S. Pat. No. Re. 3,416,618--Kunneman 
U.S. Pat. No. Re. 3,542,144--White 
It is expected that such bits will frequently become stuck in the hole 
because the full gage seal portion extends into the semi-finished, 
detritus-laden bottom of the hole. 
(iv) Summary 
It is perhaps due to the vagaries of their history of development or 
perhaps for other reasons or no reason at all, that most workers in the 
field of dual circulation bits have thought it to be desirable to locate 
the annulus seal or barrier as near as possible to the lower end of the 
bit. This is true whether the barrier is located on the bit itself or on 
the sub used for connecting the bit to the lower end of the drill stem. 
See, for example, U.S. Pat. No. 3,416,617 (bit) and U.S. Pat. No. 
3,439,757 (sub) to Wayland Elenburg (supra). But bits with seals at the 
bottom of the hole often become stuck in the hole. 
Drilling means including skirted subs, especially seal skirted subs, are 
expensive and wear out rapidly, as compared to ordinary subs. 
It is an object of the present invention to overcome the difficulties 
present in known types of bottom hole drilling means. 
SUMMARY OF THE INVENTION 
According to the invention there is provided bottom hole drilling means 
comprising a dual conduit roller cone bit including an annular body, 
providing a central flow passage through the bit body and pin for upflow 
of cuttings (or core), and peripheral flow passage means in the form of 
off-axial flow passages extending down through the bit body connecting to 
tubes or nozzles extending down below the body between the bit legs to a 
level close to the bit bottom, and a barrier or seal belt about the body 
of the bit at a level above the cones. The bottom hole drilling means 
further includes a dual conduit sub, of smaller outer diameter than the 
barrier belt, and having an inner threaded box to screw onto the bit pin, 
and an outer shoulder to abut and seal with the bit shoulder whereby fluid 
in the sub's annulus will be communicated to the upper ends of ports in 
the bit body that communicate with the off-axial passages therethrough. 
The upper end of the sub has an outer threaded box and an inner telescopic 
pin for making connection with correlative dual conduit drill pipe. 
The construction of the invention thus eliminates all skirts, shrouds, 
weirs, seals and barriers from the sub, so that the sub does not wear out 
any faster than the dual pipe and is of inexpensive construction. The 
barrier belt on the bit body is above the level of the bit cones so that 
it is less likely to become stuck in the hole. The belt acts as a 
centralizer, tending to keep the bit legs out of contact with the earth 
bore, thereby reducing wear on the bit legs. The barrier belt, being on 
the bit, is replaced whenever the bit cones wear out, necessitating bit 
replacement. No weirs, skirts, or shrouds are required for the bit, 
although detritus retention webs between the bit legs are employed in 
certain embodiments of the invention. Such webs are not skirts, shrouds or 
weirs as hereinabove discussed, since they do not serve as primary fluid 
flow directors. Rather they are detritus retainers to prevent same from 
rising into the annulus to cause wear on the barrier belt or to get jammed 
between the belt and well bore and cause the bit to get stuck in the hole. 
They will not cause the bit to get stuck in the hole becuase they are 
positioned radially inward of the earth bore.

The drawings are to scale. The drawings employ the conventions of the U.S. 
Patent and Trademark Office for patent cases to indicate materials, from 
which it will be seen that the entire construction depicted in the 
drawings is made of metal, e.g. steel, except for the tungsten carbide or 
other hard metal inserts on the bit cones, and except for the O ring seals 
at the upper end of the sub. 
DESCRIPTION OF PREFERRED EMBODIMENTS 
(a) Dual Conduit Rotary Drill String 
Referring now to FIG. 1, there is shown a dual conduit bottom hole drilling 
assembly 21 incorporating the invention. The assembly is to be used in 
earth boring by the rotary method, e.g. as described in the aforementioned 
Grable patents. 
(b) Dual Drill Pipe 
The assembly is connected to the lower end of the lowermost dual pipe 23 of 
a string of dual conduit drill pipe. Such lowermost dual pipe may be a 
dual drill collar, i.e. it may be a thick-walled member which has enough 
stiffness that it can be run in compression and which may have enough 
weight to load the bit, for which reasons it will usually be of large 
outer diameter; nevertheless it will have a considerably smaller outer 
diameter than the earth bore 25 formed by drilling apparatus 21. 
Dual pipe 23 includes an inner pipe 27 providing an inner flow passage 28 
and an outer pipe 29 forming with the inner pipe an outer annular flow 
passage 30. The entire construction of dual pipe 23 may be as disclosed in 
U.S. Pat. Nos. 
3,998,479-- Bishop 
4,012,061-- Olson 
to which reference is made for further details. The dual pipe includes 
connection means at each end for making connection with other drill string 
members. Such connection means at the lower end of the pipe includes a box 
telescopic connector 31 having a cuff 33 at its upper end slipped over the 
lower end of inner pipe 27 and welded thereto at 35. The lower end of 
connector 31 has an internal groove 37 within which is disposed a seal 
ring 39 made of elastomeric or other suitable packing material, e.g. 
rubber. Below groove 37 connector 31 has a smooth bore 41, large enough to 
receive telescopically a correlative portion of a pin telescopic connector 
43 at the upper end of the drilling assembly. Connector 31 has a 
downwardly flaring internally beveled tip 45. The lower end of outer tube 
29 is provided with a pin threaded connector 51 of the tool joint type, 
i.e. adapted to make a rotary shouldered connection with a correlative box 
threaded connector 53 at the upper end of drilling assembly 21. In this 
regard it will be noted that pin threaded connector 51 includes a smooth, 
flat seal shoulder 55 perpendicular to the axis of the sub, an unthreaded 
smooth conical neck 57, and a tapered, externally threaded spigot 59. 
Suitable means, not shown, support inner pipe 27 axially and radially and 
circumferentially relative to outer pipe 29, as disclosed in the 
aforementioned Bishop and Olsen patents. 
(c) Dual Conduit Drilling Assembly 
Drilling assembly 21 includes dual conduit drill bit 61 and dual conduit 
sub 63. 
(d) Dual Conduit Sub 
Dual conduit sub 63 includes an inner tube 65 providing an axial flow 
passage 66 communicating with passage 28 and an outer tube 67 which, in 
cooperating with inner tube 65, provides an annular flow passage 68 
communicating with passage 30. Outer tube 67 will have the same outer 
diameter as dual pipe 23 if, as shown, dual pipe 23 is a drill collar. In 
other words, there will be a considerable radial clearance x between earth 
bore 25 and the outer periphery of outer tube 67. 
Four upper radial webs 69 and four lower radial webs 71 at 
circumferentially spaced apart locations about the axis of the sub (see 
also FIG. 2) are welded to the inner tube by axial and/or circumferential 
welds and the outer tube is shrink-fitted onto the webs. Also, the upper 
ends of the webs bear against downwardly facing annular shoulders 73, 
and/or 75 on the interior of the outer tube to transmit downward 
(compressive) forces on the outer tube to the inner tube. 
The upper end of sub 63 is provided with connection means 43, 53 
correlative to connection means 31, 51 on the lower end of the dual pipe. 
The connection means, not shown, at the upper end of dual pipe 23 will be 
the same as connection means 43, 53 at the upper end of sub 63. 
Connection means 43, 53 includes pin telescopic connector 43 and box 
threaded connector 53. Pin connector 43 includes an annular groove 81 in 
which is disposed seal ring 83. Seal ring 83 is made of an elastomer or 
other suitable packing material, e.g. rubber, similar to seal ring 39, and 
is positioned to be compressed by tip 45. Above groove 81, connector 43 is 
provided with a smooth cylindrical portion 85 of a diameter adapted to fit 
telescopically within smooth cylindrical portion 41 of connector 31. The 
upper end of connector 43 has a downwardly flaring beveled tip 87 adapted 
to compress seal ring 39. 
Box threaded connector 53 on the upper end of outer tube 67 is of the tool 
joint type, i.e. adapted to make a rotary shouldered connection with pin 
threaded connector 51 at the lower end of the dual pipe. In this regard it 
will be noted that box threaded connector 53 includes a smooth, flat seal 
shoulder or end face 91 perpendicular to the axis of the sub adapted to 
seal with seal shoulder 55, an unthreaded smooth cylindrical mouth 93 
adapted to fit over neck 57, and a tapered, internally threaded bell 95 
adapted to mate with spigot 59. Space 92 enables bell 95 to be made up 
with spigot 59 sufficiently to put box mouth 93 in compression and pin 
neck 57 in tension. 
The lower end of sub 63 is provided with connection means for making 
connection with dual bit 61, such connection means including a box 
threaded connector 101 and a butt joint portion 103. Box threaded 
connector 101 is of the tool joint type, i.e. adapted to make a rotary 
shouldered connection with correlative pin threaded connector 105 on dual 
bit 61. Box threaded connector 101 includes tapered, internally threaded 
bell 107, smooth conically tapered mouth portion 109, and a smooth flat 
seal shoulder or end face 111 perpendicular to the axis of the sub. Butt 
joint portion 103 is merely the smooth, inwardly tapered shoulder or end 
face at the lower end of outer tube 67 adapted to seal with the smooth, 
matingly inwardly tapered shoulder 115 on dual bit 61, both shoulder 115 
and butt joint portion 103 being inwardly tapered to prevent the flaring 
of the lower end of the sub. Obviously, other types of sealing means can 
be provided between shoulder 115 and butt joint portion 103. Space 110 
functions like space 92. 
(e) Dual Conduit Bit--First Embodiment 
Referring now also to FIGS. 3, 4, 5 and 6, as well as FIG. 1, dual bit 61 
includes annular body 121 through which extend three flow passages 123 
equally, circumferentially spaced apart by 120 degrees, providing outer 
flow passage means. Internally, body 121 provides a cylindrical inner flow 
passage 125. As best shown in FIG. 5, the lower end of passage 125 is 
provided with a downwardly flaring or funnel-shaped mouth 126. Rising 
above body 121 and coaxial therewith is tubular pin threaded connector 105 
providing a continuation of flow passage 125. Passage 125 communicates 
with passage 66 in the sub and through passage 68 with passage 28 in the 
drill collar. Connector 105 is of the tool joint type to form a rotary 
shouldered connection with box connector 107 at the lower end of sub 63. 
Connector 105 includes tapered, externally threaded spigot 127 adapted to 
make up with bell 107, a smooth, conically tapered neck 129 adapted to fit 
within smooth tapered mouth portion 109, and smooth, flat seal shoulder 
113 adapted to seal with shoulder 111 and form a rotary shouldered 
connection. Neck 129 is in tension and mouth 109 is in compression when 
the connectors are fully made up, and outer fluid passage means 123 of the 
bit is placed in communication with annular flow passage 68 of the sub. As 
best shown in FIG. 2, since there are four webs 71 and only three passages 
123, at least two of passages 123 will be out of alignment with webs 71, 
and as best shown in FIG. 1, since webs 71 are spaced vertically from the 
lower end of the sub, the tops of all three passages 123 in the bit are in 
full communication with annular passage 68 in the sub. 
Depending from body 121 are three legs 131. The vertical center planes of 
legs 131 are equally circumferentially spaced apart by 120 degrees and are 
located midway between pasages 123. Preferably body 121 is made in three 
sectors, each with a leg 131 integral therewith and depending therefrom 
and each with a sector of connector 105 integral therewith and rising 
therefrom, the three sectors being welded together at 133, as shown in 
FIG. 6. 
Integral with each bit leg is a stepped spindle 135. On each spindle is 
rotatably mounted a roller cone 137, each cone carrying a plurality of 
rings 139 (FIG. 1) of earth formation reducing means, e.g. protuberant 
tungsten carbide inserts or milled cutter teeth, all of conventional 
design, as illustrated for example in the aforementioned Gruner-Williams 
catalog. The axis of each cone points inwardly downwardly whereby the 
bottom edges of the cones as the cones roll in the bottom of a well bore 
define a surface that is nearly flat, being in a range between conical 
pointing up and conical pointing down. 
Referring to FIG. 5, each of the cones 137 has a stepped interior 
correlative to the stepped exterior of its spindle and each is rotatably 
mounted on its spindle by suitable bearing means, typically roller 
bearings 141, such as shown, for example, at pages 5148-5149 of the 
1976-77 Composite Catalog of Oil Field Equipment and Services. The rollers 
are placed in a race 143 extending around the largest diameter step of 
each spindle or in a correlative race 145 in the cone. Each cone is then 
placed on the spindle, and locked in place by ball bearings 149 placed in 
the space between annular grooves 151, 153 extending around the interior 
of each cone and the intermediate step on the exterior of each spindle. 
The balls may be put into position through a hole in the cone or leg (not 
shown) which is later closed with a screw plug or weld metal. Additional 
rotation support for each cone is provided by the cylindrical tip 155 
received in socket 157 in the cone, forming a journal bearing. 
In order to cool the bearing means for each cone (the journal bearing, ball 
bearings, and roller bearings), drilling fluid (typically air, gas, oil, 
water or even mud) is admitted to the bearing means by fluid passage means 
comprising a horizontal passage 159 in the leg extending radially 
outwardly from ball groove 153 to join with a sloping vertical passage 
161. The outer end of each passage 159 is closed with a drive pin 160 or 
screw plug or weld metal. The top end of each passage 161 opens to 
shoulder 115 to communicate with flow passage 68 between inner tube 65 and 
outer tube 67 of sub 63, which in turn communicates with passage 30 
between inner pipe 27 and outer pipe 29. As best shown in FIG. 2, the 
center lines of flow passages 161 are equally circumferentially spaced 
apart by 120 degrees and are disposed midway between flow passages 123. 
During drilling air or other drilling fluid flows down passages 30 and 68 
into passage 161 and thence into passage 161 to cool the bearing means, 
the air flowing past the bearing means and then out between the cones and 
spindles to return back through passages 125, 66 and 28. 
At the lower side of body 121, in between legs 131 are three nozzles 171 
(see especially FIG. 6). These nozzles connect to the lower ends of fluid 
passages 123 in bit body 121 and are formed integral therewith or are 
removably replaceably secured thereto by any suitable means, e.g. screw 
threads, as shown, for example, at page 4578 of the 1974-75 edition of the 
Composite Catalogs of Oil Field Equipment and Services. As shown, the 
bodies of nozzles 171 are forged integral with bit bodies 121 and 
thereafter machined to provide bores 172 and other finished dimensions. 
Nozzles 171 extend far enough below body 121 to open at a level well below 
the horizontal plane through the top edges of cones 137 and normally 
somewhat above hole bottom 174. Typically the nozzles will open at a level 
within about the mid third of the distance between the horizontal planes 
of the bottommost and topmost portions of cones 137, contrary to at least 
some more conventional jet bits such as those shown at page 4223 of the 
1974-75 edition of the Composite Catalog of Oil Field Services and 
Equipment, in which the nozzles open near the plane of the topmost 
portions of the cones. In the present example, nozzles 171 extend to the 
level of the horizontal plane though the uppermost rollers 141 supporting 
the cones on the spindles. A lower limit of the typical range would be the 
horizontal plane through the lowermost rollers 141. As appears from the 
drawing, which as noted previously is to scale, the horizontal planes 
through the uppermost and lowermost rollers 141 bracket the mid 
three-fifths of the distance between horizontal planes through the 
bottommost and topmost portions of cones 137. 
During drilling, air or other drilling fluid flows down passages 30 in the 
drill pipe (and drill collars) into sub passage 68 and thence into bit 
body passages 123 and out through nozzles 171. Drilling fluid emerging 
from nozzles 171 helps cones 137 reduce earth formation at the bottom 174 
of earth bore 25, flows over the outer surfaces of the cones to cool and 
clean them and then flows back up through inner flow passage 125, sub 
passage 66 and pipe passages 28. 
To prevent loss of drilling fluid to bore annulus 175 (FIG. 1) bit body 121 
is provided on its outer periphery with a belt 177, as best shown in FIG. 
4. The belt has an outer periphery 179 whose diameter is smaller than bore 
25 by an amount which may be called a rotating clearance, i.e. enough 
clearance to allow rotation of the bit in the bore without excessive 
frictional torque and wear and with little likelihood of the bit becoming 
stuck in the bore, especially when not rotating, yet large enough to form 
a seal or barrier to the flow of drilling fluid (e.g. air, gas, water, oil 
or mud) when the clearance is bridged by detritus and formation fluid. For 
example, belt 177 may have a clearance of 150 -inch radially all around 
within bore 25. 
Since belt 177 is wholly on body 121, it is above legs 131 and well above 
the horizontal plane defined by the uppermost portions of cones 137 (FIG. 
4). It is therefore positioned to minimize the possibility of detritus 
thrown up by the cones getting in between the belt and earth bore and 
causing the bit to become stuck in the hole. Also, the belt is in the 
fully formed portion of the earth bore where it is of full diameter. 
Further, the belt is out of the detritus zone in which the earth formation 
reducing means provided by the nozzles and on the cones is churning the 
detritus prior to its being carried away by the drilling fluid flowing up 
fluid passage 125, so there is less wear on the belt. At the same time the 
belt serves as a centralizer and keeps legs 131 away from the side bore 
25, thereby reducing wear on the legs. 
Cones 137 extend radially from the axis of the bit slightly beyond legs 131 
to cut the full gage of bore 25. Although FIG. 4 shows the cones with 
nearly zero, or zero offset (cone axes intersect the bit axis) as is 
typical for hard formations, the cones may have offset, especially for 
soft formations, in which case, as shown in FIG. 4, the cones cut to full 
gage only at a level 181 somewhat above bottom. This is another reason why 
it is desirable to place belt 177 above cones 137. 
(f) Dual Conduit--Further Embodiments 
Referring now to FIGS. 7-9, 10-12, and 13-15, there are shown second, third 
and fourth embodiments of the bit previously described. Parts that are the 
same as in the first embodiment are given the same numbers. 
(g) Dual Conduit Bit--Second Embodiment 
The only difference between the first and second embodiments is the 
addition to the second embodiment of webs 201 between the trailing side of 
each nozzle and the leading side of the adjacent bit leg. In this 
connection it is assumed that the bit is to be rotated in the usual 
manner, i.e. clockwise, or to the right, as viewed from the top. Webs 201 
are not to be confused with forging fillets 203 at the junctures of 
nozzles 171 and legs 131 in the first embodiment. 
Webs 201 provide means to help retain detritus at the interior of the bit, 
especially that created by nozzles 171. 
Webs 201 extend vertically down to the same level as the lower ends of 
nozzles 171; greater or lesser downward extension of webs 201, while 
possible, would not be as desirable, since lesser extension would provide 
less retention and greater extension would interfere with the flow of 
drilling fluid from the nozzles, which are assumed to extend to the 
optimum downward position for jetting of the drilling fluid to the bottom 
of the hole. 
As best shown in FIG. 7, webs 201 are radially inward of earth bore 25, so 
that there is little wear on the outer peripheries of the webs. 
(h) Dual Conduit Bit--Third Embodiment 
Referring now to FIGS. 10, 11 and 12, there is shown a third embodiment of 
the bit. The only difference between the third embodiment and the second 
embodiment is in the addition of further webs, 301. Webs 301 provide 
additional detritus retention means, especially for retention of detritus 
kicked up by cones 137 (See FIG. 10). 
With both webs 201 and 301, there is provided means for full retention of 
detritus at the interior of the bit above the level of the bottoms of the 
jets. 
Webs 301, like webs 201 are positioned radially inward of the full gage 
bore 25 defined by cones 137, and may extend vertically to a lesser or 
greater but preferably equal extent compared to the lower ends of nozzles 
171. 
(i) Dual Conduit Bit--Fourth Embodiment 
Referring now to FIGS. 13-15, there is shown a fourth embodiment of the 
bit. In this embodiment, as in the first embodiment, there are no webs 
between the nozzles and legs. This embodiment is the same as the first 
embodiment except for the provision of webs 401 directly between legs 131. 
Also, nozzles 171 are set at an angle to the vertical. To this extent the 
construction is similar to that of shrouded (inside skirted) bits used 
with skirted (outside skirted) bit subs as previously described. However, 
the webs between the legs serve in this case not only as flow directing 
inside skirts but as detritus retention means. Note that in this case, 
however, such detritus retention means is radially inward of nozzles 171 
(see FIG. 15). 
While several preferred embodiments of the invention have been shown and 
described, many modifications thereof can be made by one skilled in the 
art without departing from the spirit of the invention. For example, 
although the nozzles are shown as being centered between the bit legs, 
they could be offcenter, either close to or farther from the cone leading 
the respective nozzle as the bit rotates. Also, one or more nozzles and 
cones could be omitted, e.g. as in the type BHDJ two cutter (two cone) bit 
illustrated in: 
The Composite Catalog of Oil Field Equipment and Services; 32nd Revision, 
1976-1977; page 5152 
or additional cones or nozzles could be employed. The cutter cones 
themselves and also the nozzles do not necessarily have to be 
symmetrically positioned or equally spaced apart. Although the disclosed 
belted jet dual bit is disclosed in conjunction with a dual sub, it could 
be connected to the lower end of a dual collar, dual drill pipe, dual 
stabilizer or other dual drill stem member, with either dual box or pin 
and box ends, or in the case of a bit having a box instead of a pin, the 
connected dual drill string member could have box and pin ends or be a 
dual pin member. Although cutter cones having carbide inserts are 
disclosed, milled teeth or other forms of reducing means could be 
employed. Also other forms of rolling cutters could be employed, and the 
nozzles could be omitted.