Reduced erosion nozzle system and method for the use of drill bits to reduce erosion

Subterranean drill bits and particularly to nozzle features to be incorporated in subterranean bits. In one embodiment, the nozzle assembly of the invention defines a wear resistant structure which extends upstream from the terminus of the transition area. In another embodiment, nozzle assemblies are arranged about the transition area at low angles so as to minimize flow turbulence.

BACKGROUND OF THE INVENTION 
1. Field of the Invention 
The present invention generally relates to a nozzle system for a downhole 
drill bit. More particularly, the present invention relates to an improved 
drill bit and nozzle system which better manages fluid flow and decreases 
erosion of the drill bit body and methods for the design and operation of 
downhole drill bits to reduce erosion. 
2. Description of the Prior Art 
Subterranean drill bits are used in a number of different applications and 
under a variety of environments. In this connection, subterranean drill 
bits are conventionally used in mining, construction, oil and gas 
exploration, and oil and gas production. 
There are two general types of commercially available drill bits. A roller 
bit utilizes steel teeth or tungsten carbide inserts. A fixed cutter bit 
describes a drill bit that does not employ a moving cutting structure. 
Fixed cutter bits include polycrystalline diamond compact (PDC), thermally 
stable polycrystalline (TSP), natural diamond and other bits which do not 
use a diamond material as a cutting element. 
A conventional downhole drill bit includes a shank with a threaded 
connection for mating with a drilling motor or a drill string. The shank 
can include a pair of wrench flats, sometimes referred to as "breaker 
slots", to apply the appropriate torque to make-up the thread shank. The 
distal or bottom end of the drill bit contains the cutting structure, be 
it roller or fixed cutter as described above. The bit body further 
includes a central bore which allows fluid communication between the 
borehole and the drill string. This central bore terminates in several 
fluid openings disposed about the bit face and adapted to circulate 
pressurized fluid over the cutting surface. These openings are provided 
with nozzles which control fluid flow therethrough. 
By utilizing a small nozzle orifice in the nozzle body, fluid velocity 
through the central bore is increased with a proportionate increase in the 
pressure required to pump a given volume of fluid. Conversely, by 
increasing the nozzle orifice, the pressure to pump a given volume of 
fluid decreases and the fluid velocity decreases. By selecting the nozzle 
orifice size, the operator is able to control the velocity and pressure of 
the fluid flow through the bit. 
Internal erosion in and around nozzle bodies is a major problem in the 
longitivity of the bit and, indirectly, the economy of the drilling 
operation. Drilling fluid generally contains a percentage of entrained 
solids, many of which are highly abrasive. Given the presence of such 
entrained solids, increased fluid velocity generally results in a 
proportionate increase in the erosion of the bit body. Consequences of 
such erosion include eroded areas through the bit structures which result 
in a loss of hydraulic pressure and necessitates a trip out of the bore 
hole to replace a bit damaged as a result of fluid erosion. 
There are a number of disadvantages associated with traditional 
subterranean drill bits and methods for their operation. One such 
disadvantage relates to internal erosion of the drill bit body caused 
during operation of the bit by fluid circulation. Factors contributing to 
such erosion include mud weight, mud viscosity and flow velocity through 
the drill bit. 
A second disadvantage is internal erosion of the drill bit body caused by 
geometrical discontinuities in the fluid openings leading to the nozzle 
bodies. In this connection, sharp angles create fluid flow separation and 
high shear layer stresses as well as adding to the erosive capabilities of 
the fluid. 
Other disadvantages lie in the method of operation of traditional drill 
bits. Conventional methods of operation given known design parameters fail 
to maintain laminar fluid flow within the bit body during operation, 
thereby resulting in enhanced erosion. 
SUMMARY OF THE INVENTION 
The present invention addresses the above identified and other 
disadvantages or prior art drill bit nozzle systems and methods for their 
use. 
In one embodiment, the drill bit of the present invention comprises a drill 
bit body defining a pin end and a cutting end. The bit body further 
defines a bore therethrough which is open at both the pin and the cutting 
ends so as to provide for fluid communication between the bore and the 
borehole. The bore terminates in a counterbore or plenum which creates an 
angled transition area and a smaller area entrance to the nozzle. The 
nozzle itself generally describes an elongate cone which terminates in a 
flow restriction of a variable diameter. 
In one preferred embodiment, the nozzle assembly of the present invention 
defines a structure which protrudes a selected distance upstream from the 
terminus of the transition area. In such a fashion, any turbulence created 
through fluid flow in the bore is transitioned from the terminus to an 
intermediate area. Hence, erosion of the bit body is significantly 
reduced. 
In another embodiment, the nozzle assemblies are arranged about the 
transition area at low enough angles incident to fluid flow so as to 
minimize turbulence given other operational parameters. 
Another embodiment of the invention defines an operational regime which 
selectively contemplates those factors contributing to reduced erosion of 
the bit body. In such a fashion, turbulent flow within the counterbore is 
avoided, thereby prolonging the life of the drill bit. 
The present invention achieves a number of benefits over prior art drill 
bit nozzle systems. One such advantage is the reduction of the erosion of 
the bit body as a result of the substantial reduction of turbulent flow in 
the nozzle bore. 
Another advantage presented by the drill bit of the present invention 
includes a nozzle structure adapted to transition what turbulence is 
created in the bore to areas of the bit body not as prone to erosion. 
Still other benefits and advantages of the invention will become obvious in 
light of the following description of the preferred embodiment and the 
accompanying drawings.

DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENT 
It is well known that erosion of downhole tools is a function of a number 
of factors. One of the most significant of these factors is the existence 
of turbulent, as opposed to laminar, drilling fluid flow in the plenum of 
the bit. 
Turbulent flow is generally considered to exist when conditions in the bore 
define a Reynolds number in excess of a dimensionless figure of 4000. 
Laminar flow is generally defined as those conditions below 2000. Between 
a Reynolds numbers of 2000 and 4000 the flow pattern is in transition, and 
can demonstrate either or both laminar or turbulent tendencies. 
The Reynolds number Re is defined as a result of the following equation for 
flow inside a tube 
##EQU1## 
Where p equals mud weight expressed in pounds per gallon, v equals annular 
velocity as expressed in feet per minute, D.sub.F equals the inlet 
diameter of the nozzle in inches, and .mu. equals viscosity as measured in 
centipoise. The viscosity of the drilling fluid is a function of the types 
and quantities of additives, the temperature of the mud, and the volume of 
the entrained solids. 
The flow rate necessary to maintain a given bit in a non turbulent, and 
hence a reduced erosion, operating regime can be calculated given a 
knowledge of the aggregate nozzle inlet diameter .SIGMA.D.sub.p, the mud 
weight p and the viscosity .mu., where the goal is to maintain operation 
of the tool below a transition Reynolds value of 2300. Thus where 
##EQU2## 
Thus, where mud viscosity, mud weight and total inlet diameters are known, 
non turbulent operation of the tool may be maintained as a function of the 
velocity of the drilling fluid as measured at the nozzle inlets. This may 
be observed by reference to the following example: 
EXAMPLE 1 
Drillstring 
Drill collars 90 ft. of 61/4 in O.D. 23/4 ID 
Heavyweight pipe 1500 ft. 41/2 in O.D., 3 in 1D 
Drillpipe 10,410 ft. 41/2 in. O.D., 3.82 ID 
Bit 31/2 nozzles (X 3) 
Mud Properties at 120.degree. F. 
Weight=15 lb/gal 
Filtrates Weight: 20 cc@300.degree. F. 
Viscosity 80 
Inserting a Reynolds value of 2300 in equation (3) permits the calculation 
of a non erosional fluid velocity: 
##EQU3## 
Hence, to observe laminar flow for a drill bit operating under the 
foregoing conditions, a flow rate of 75.5 ff/min may not be exceeded. 
The above example assumes no turbulence created as a result of the 
angulation of the nozzles vis a vis the axis defined by the bore. However, 
applicant has discovered that even at flow parameters producing a Reynolds 
number at or below 2300, significant erosion still occurs as a result of 
geometrical discontinuities of the nozzles vis-a-vis the longitudinal axis 
of the drill string. 
There is no single value for which a fluid flow regime can be predicted to 
be turbulent, a general value is known to be 2300. However, flow can be 
turbulent at values less than 2000 and flow can be laminar at values 
greater than 4000. There are factors not reflected in the Reynolds number 
such as flow regime at the fluid inlet, surface roughness at the flow 
boundary, external forces to excite the flow. 
For fluid flow in the inlet of the nozzles one factor is the angle of the 
nozzle to the fluid flow direction at the nozzle entry. Changes of fluid 
flow direction lower the value of Reynolds number at which turbulent flow 
can be expected. If the nozzle direction is aligned with the fluid flow 
direction, then the fluid does not have to change direction to pass 
through the nozzle. As the angle of the nozzle increases, flow becomes 
turbulent at lower Reynolds numbers. 
Notwithstanding the aforereferenced methodology to reduce erosion in a 
conventional drill string, erosional damage nevertheless does occur. 
Applicant has thus developed a drill bit which incorporates nozzle 
structures to reduce erosional damage. 
A contemporary drill bit 2 may be seen by reference to FIGS. 1 and 2 in 
which are illustrated a pin end 4 defining a threaded shank 3, a bit body 
6 and a cutting end 10. By reference to FIG. 2, a fluid chamber or plenum 
13 is formed within bit body 6 and communicates with the open pin end 4 so 
that hydraulic fluid (drilling mud) may enter said body 6 though an 
attached drill string (not shown) and exit through nozzles 23. 
A dome 17 formed by the bit body 6 defines a portion of the terminal end 15 
of fluid plenum 13. Bit legs 20 extend from said bit body 6 toward the 
cutting end 10 of said bit 2. (See FIG. 1) A cutter cone 18 is rotatively 
secured to each leg 20 through a journal bearing (not shown) extending 
into each cone from a shirttail 22 of leg 20. As illustrated, each cone 18 
includes a plurality of spaced, cutter inserts 19. 
In the illustrated embodiment, a nozzle 23 extends from a nozzle retention 
sleeve generally designated at 30. A counterbore 3 is drilled into plenum 
13 followed by second counterbore 4 which terminates at a shoulder 5 
formed in nozzle retention body 30. The plenum entrance to straight bore 3 
creates a sharp corner 7 as well as a reduced-in-area entrance to standard 
nozzle sleeve generally designated at 8. This reduced diameter entrance 
increases mud flow velocities into the entrance of nozzle sleeve 8, thus 
accelerating any erosion of the bit body which may there occur. 
FIG. 3 illustrates the bottom or cutting end 60 of a fixed cutter bit 
incorporating cutters 62 and a series of nozzles 64 which perform in a 
similar fashion to those described above in association with a rotating 
drill bit. A cross sectional view of the nozzle system employed in 
association with the fixed cutter bit illustrated in FIG. 3 may be seen by 
reference to FIG. 4 which illustrates a bit body 61, a plenum 63 and 
nozzles 64. As illustrated in FIG. 4 and in more detail in FIGS. 5 and 6, 
the nozzles incorporated in these prior art bits are also situated such 
that their throat 66 is formed flush with the terminal end 69 of the 
plenum chamber 63. 
As illustrated in FIG. 6, this configuration precipitates and/or 
exacerbates turbulence about the edge of said throat 66, thereby leading 
to erosion of the bit body. Such erosion over time forces an independent 
fluid passageway from the plenum 63 to the bit face 60, thereby resulting 
in the destruction of nozzle 64. 
Several embodiments of the nozzle assembly of the present invention may be 
seen by reference to FIGS. 7-9. FIG. 7 illustrates a fragmentary, cross 
sectional view of a drilling bit 50 defining a bit face 52, a bit body 54 
and a pin end 56 including a threaded shank 58. Bit body 54 defines a bore 
57 which terminates in a plenum chamber 80 and a nozzle. 
The nozzle assembly of the present invention may adopt a variety of 
configurations. In the embodiment illustrated in FIG. 7, nozzle assembly 
70 includes an integral nozzle body 72 which includes an upstream, 
proximal end 74 defining a throat 75 and a distal end 79 which is 
threadedly engagable with a liner 81 which may be brazed or welded into 
bit body 54 in a conventional fashion. In the embodiment illustrated in 
FIG. 7, throat 75 terminates in a constricted neck region 80. Throat 75 
forms a fluid flow path from plenum chamber 83 to the constricted neck 
region 80. The restrictions in the neck 80 converts the potential energy 
of the fluid at high pressure and low velocity to kinetic energy. 
As illustrated in FIG. 7, the upstream, proximal end 74 of nozzle assembly 
70 is raised above the terminal end 61 of plenum chamber 83. In such a 
fashion, any turbulence in the drilling fluid created around proximal end 
74 does not erode the bit body 61 but instead acts solely on the proximal 
end 74 of the nozzle body 61 which is preferably manufactured from an 
erosion resistant material, e.g. tungsten carbide. 
In a preferred embodiment, proximal end 74 is raised a distance "L" above 
said terminal end 61, where "L" is preferably in a range of one eighth 
(1/8") to one half (1/2") inch in length. 
A second embodiment of the nozzle system of the present invention may be 
seen by reference to FIG. 8. In FIG. 8, nozzle assembly 88 threadedly 
receives a liner 90 which itself defines an upstream, proximal end 92 and 
a distal end 94, where said proximal end 92 of liner 90 is carried above 
the terminus of plenum chamber 96 a distance "L.sub.2 ", where L.sub.2 is 
in the range of 1/8"-1/2" in length. In this embodiment, liner 90 is 
preferably comprised of a hard, erosion resistant compound such as 
tungsten carbide. 
Yet a third embodiment of the nozzle assembly of the present invention may 
be seen by reference to FIG. 9. In FIG. 9, a conventional nozzle 100 is 
seated on a liner 101, where the liner 101 defines an upstream or proximal 
end 102 and a distal end 103. As with prior embodiments, the proximal end 
of liner 101 is formed above the terminus 111 of plenum chamber 106 a 
distance L.sub.3, where L.sub.3 is in the range of 1/8"-1/2" in length. 
Although particular detailed embodiments of the apparatus and method have 
been described herein, it should be understood that the invention is not 
restricted to the details of the preferred embodiment. Many changes in 
design, composition, configuration and dimensions are possible without 
departing from the spirit and scope of the instant invention.