Method for increasing hydraulic efficiency of drilling

An apparatus and a method for adjusting the total flow area of a drilling bit concurrently with drilling which includes a bit having a plurality of nozzles, each nozzle having a flow area and the bit having a total flow area, with at least one nozzle which is initially open and having a first flow area and at least one other nozzle which is initially closed and having a second flow area including a closure means for maintaining the nozzle in an initially closed state below a pre-selected differential pressure across the bit.

FIELD OF THE INVENTION 
The present invention generally involves drilling bits, and more 
particularly the invention is directed to a method and an apparatus that 
allows an adjustment in the total flow area of the bit concurrently with 
drilling. 
BACKGROUND OF THE INVENTION 
In known drilling methods, the rock is destroyed by rolling cutters on a 
drill bit or by stationary cutting surfaces such as in drag bits or 
diamond bits. This mechanical destruction of the rock produces debris 
which has to be removed as it is formed so that the bit is constantly 
operating on new rock. 
To remove the debris being formed during drilling, a drilling fluid is 
circulated through the well as it is drilled. Bits incorporate nozzles 
which direct the drilling fluid (or mud) to the hole-bottom. A typical 
rock drilling bit has three rotating cutters with three nozzles arranged 
around the cutters. A fourth centrally placed nozzle is also available on 
some drill bits. Other bits can have as few as two or more than four 
nozzles. The drilling fluid is in constant circulation while drilling and 
has several basic functions. The circulating drilling fluid maintains 
higher pressure in the wellbore than in the surrounding rock to prevent 
formation fluid(s) from entering the wellbore. The circulating fluid also 
cools the drill bit, cleans the cutters, and removes the rock debris from 
the bottom of the hole. 
The hydraulic system of a drilling well controls the speed and pressure of 
the circulating mud and an optimized hydraulic system can improve the 
drilling rate, reduce equipment inefficiencies and lower drilling costs. 
The hydraulic system is controlled by four different factors. The first is 
the surface pumps which circulate the drilling fluid down the pipe, 
through the bit nozzles, back up the annulus, and back down the pipe. The 
second is the loss in pressure caused by friction as the drilling fluid 
goes down the pipe. A third factor is the pressure loss at the drill bit 
which occurs when the drilling fluid leaves the drill bit nozzles and the 
fourth is the pressure loss in the annulus which occurs as the drilling 
fluid is circulated back up the annulus to the surface to be recirculated 
back down the pipe. A comprehensive discussion of well hydraulics can be 
found in J. S. Short, Drilling and Casing Operations, Tulsa, Okla., 
PennWell Publishing Company, p. 241-248, TN871.2S537, and numerous other 
drilling publications. 
The pressure loss that occurs at the drill bit, is largely dependent upon 
the diameter of the nozzles placed in the drill bit prior to drilling for 
a given mud weight and mud flow rate. Thus, the larger the diameter of 
nozzles used, the less of a pressure drop at the bit, which results in a 
decrease in fluid velocity as the mud exits the nozzles. Conversely, the 
smaller the diameter, the greater the pressure drop at the bit, which 
results in an increase in fluid velocity as the mud exits the nozzles. 
The diameters of the nozzles determine the total flow area (TFA) of a bit. 
The TFA of a bit is equal to the sum of the flow areas of the nozzles in 
the bit. The appropriate total flow area for any given drill bit is 
determined by the depth of the well, the drilling assembly used, the 
drilling fluid characteristics, and the hydraulic system's flow rate. 
Currently, when a drill bit TFA needs to be increased or decreased, 
drilling is stopped, the drill bit is removed from the well and the 
nozzles are replaced. 
When drilling is stopped to remove the drill bit from the well, the average 
drilling rate slows down and drilling costs increase or the well is 
drilled with non-optimum hydraulics. Thus, it would be an advantage to be 
able to optimize a drilling well's hydraulic system by having the ability 
to change the drill bit TFA concurrently with drilling without having to 
remove the drill bit from the well. 
SUMMARY OF THE INVENTION 
The present invention is directed to an apparatus and a method for changing 
the total flow area of a drill bit concurrently with drilling. The drill 
bit has a plurality of nozzles with each nozzle having a flow area and the 
bit having a total flow area. The bit has at least one nozzle which is 
initially open and at least one nozzle which is initially closed by means 
of a rupture disc that will open at pre-selected differential pressures. 
In one embodiment, the rupture disc has a threshold that is above the 
differential pressure level present when at least one of the nozzles is 
normally open and below the pressure level present when at least one of 
the normally open nozzles is closed. When the rupture disc opens fluid 
flows through the nozzle causing a change in the drill bit TFA which 
results in an adjustment in the pressure loss at the drill bit. 
The rupture disc fits in a sleeve that is shaped to fit within a drill bit 
nozzle and is retained within the sleeve by a locking retaining ring. In a 
preferred embodiment, the sleeve and the retaining ring are formed of a 
mild tool steel or other material that is rapidly eroded by the flow of 
drilling fluid through the nozzle after the flow blocking disc ruptures. 
The erodibility of the mild tool steel allows the complete elimination of 
the sleeve and retaining ring after the rupture disc has opened. 
A method is provided to adjust the total flow area of a drilling bit 
concurrently with drilling by mounting a rupture disc or pressure 
activated valve on at least one of the nozzles of a drill bit which has a 
plurality of nozzles, with the rupture disc or valve being adapted to open 
at a pre-selected differential pressure. Closing at least one of the open 
nozzles or increasing pump pressure will cause an increase in the 
differential pressure, the increase causing the rupture disc to open 
allowing fluid to flow through the nozzle which results in an adjustment 
in the total flow area of the bit. Similarly, any other method of 
increasing the differential pressure will also permit adjustment of the 
total flow area of the bit.

DETAILED DESCRIPTION OF PREFERRED EMBODIMENT 
The present invention includes an apparatus and method which allows an 
adjustment in the total flow area of the bit concurrently with drilling. A 
typical drilling bit 10, illustrated in FIG. 1, has three rotating cutters 
with three nozzles 12, 14 and 16 arranged around the cutters. In current 
drilling bits all three of the nozzles 12, 14 and 16 are normally open or 
are permanently blanked or closed allowing drilling fluid or mud to flow 
through the open nozzles to the hole-bottom. In the present invention, one 
or more of the nozzles 12,14,16 of the drilling bit 10, contains a rupture 
disc 18 (not shown in FIG. 1) or a pressure activated valve (not shown) 
which will allow the nozzle to be maintained in a normally closed state as 
a blank nozzle until the rupture disc 18 is opened by a pressure 
differential across the bit. Alternatively, a normally closed valve which 
opens at a pre-selected differential pressure may be used. 
FIG. 2 illustrates a blank nozzle 12A containing the rupture disc 18 in a 
sleeve 20 with a retaining ring 28 secured to an inner surface 38 of the 
nozzle 12A. The rupture disc 18 is designed to open at a specific 
differential pressure range. Such rupture discs are well known in the 
industry and are available, for example, from Autoclave Engineers of 
Houston, Tex. When the pre-selected differential pressure range is 
reached, the opening of the rupture disc 18 will cause the blank nozzle 
12A to become a working part of the drill bit 10 with mud flowing through 
the nozzle 12A. 
As shown in FIGS. 2 and 3, the rupture disc 18 is maintained in a circular 
sleeve 20 with a retaining ring 28. The sleeve 20 has an inner surface 22 
and an outer surface 24 and in a preferred embodiment is formed of mild 
tool steel which will erode away with fluid circulation so as to eliminate 
the sleeve 20 from an opened nozzle. A groove 26 is in the inner surface 
22 of the sleeve 20 for holding the rupture disc 18 in place within the 
sleeve 20. The sleeve 20 also has threading 21 along a portion of its 
inner surface 22 adapted to thread with the retainer ring 28. 
The retaining ring 28, as illustrated in FIG. 4, has an inner surface 30 
and a threaded outer surface 32 and in a preferred embodiment is formed of 
mild tool steel which will also erode away with fluid circulation so as to 
eliminate the ring 28 from an opened nozzle. The surface 34 of the 
retaining ring 28 can include notches 34a or a similar female cavity for 
engaging with an allen wrench (not shown) or other torque applying device 
to properly secure the retaining ring 28 in the sleeve 20 of FIGS. 2 and 
3. 
The sleeve 20 can be fastened to the inner surface 38 of the nozzle 12A in 
any manner. In a preferred embodiment, the outer surface 24 of the ring 20 
is brazed to the inner surface 38 of the nozzle 12A. 
In operation the blank or closed nozzle 12A is installed in the drill bit 
10 by replacing a nozzle, such as nozzle 12 prior to drilling. The closed 
nozzle 12A may or may not have a different nozzle size from the nozzle 
being replaced depending upon the anticipated changes in drilling 
conditions. If during drilling, the total flow area of the bit needs to be 
changed in order to optimize the well's hydraulic system, the rate of flow 
of drilling fluid through the bit can be temporarily increased to cause 
the rupture disc 18 to open. The drilling fluid or mud flowing through the 
previously closed nozzle 12A causes a change in the total flow area of the 
bit which decreases the pressure loss at the drilling bit. 
Alternatively, a ball can be dropped into the drill pipe to plug one of the 
drill bit nozzles 14,16. The dropping of balls to plug nozzles is well 
know in the art. The blocked nozzle 14 or 16 will create an increase in 
the hydraulic system's pressure which will cause the rupture disc 18 to 
open allowing mud to flow through the previously closed nozzle 12A. 
There are several drilling situations in which the present invention can be 
beneficial. The first situation occurs when drilling fluid density 
changes. When the drilling fluid density is changed, a well's hydraulic 
efficiency is drastically decreased since hydraulics is optimized by 
having the appropriate bit TFA for one relative drilling fluid density. 
Hydraulic and cost efficiency are lost if the bit TFA cannot be changed 
also. For example, when drilling fluid density is changed from 9 pounds 
per gallon (ppg) to 13 ppg, the optimized bit TFA for the 13 ppg fluid is 
much greater than for the 9 ppg fluid for a given flow rate. This increase 
in fluid density will cause the drill bit pressure loss to increase. The 
increase in bit pressure loss creates an increase in the hydraulic 
system's pressure which will increase the fluid velocity of the mud as it 
exits the nozzle. If a drill bit 10 having the closed nozzle 12A is used, 
this bit pressure loss increase will open the rupture disc 18 and return 
the system's pressure to normal and allow drilling to continue with the 
optimized bit TFA for the 13 ppg fluid. In a reverse situation, when the 
fluid changes density from a higher ppg to a lower ppg, the present 
invention can also be utilized by using a drill bit with a closed nozzle 
12A having a flow area more appropriate for the lower density fluid when 
one of the previous nozzles having a flow area appropriate for the higher 
density fluid is plugged by dropping a ball. 
The present invention is also beneficial when a lengthy bit run is in 
progress. Drill bit hydraulics is also a function of depth, and the 
associated hydraulic drill pipe frictional loss is proportional to the 
depth of the well for a given flow rate. Drill bit hydraulics can be 
optimized when drilling a short bit run, but cannot be completely 
optimized for long bit runs. For example, when drilling a long bit run, 
the optimized drill bit TFA in the shallower section may be greater than 
the optimized bit TFA in the deeper section. If a drill bit 10 is used, 
which has a closed nozzle 12A with a smaller nozzle flow area than the 
area of the open nozzles, the optimization for a long bit run will improve 
by allowing the bit TFA to be changed while drilling. The hydraulic 
system's pressure can be temporarily increased at the correct depth by 
dropping a ball into the drill pipe to plug one nozzle of the drill bit. 
The change in differential pressure will cause the rupture disc 18 in the 
closed nozzle 12A to open and fluid will flow through the smaller nozzle 
area, allowing a lower optimized bit TFA to be realized. 
Another situation in which the present invention is advantageous is when 
drill bit nozzles become plugged while drilling. If a drill bit drills in 
a formation that is very unconsolidated and clay enriched (gumbo) the 
drill bit nozzles tend to plug with the gumbo. When this occurs, a 
downhole attempt is made to unplug the nozzles, but the bit must usually 
be removed from the well to unplug the debris. If a drill bit containing a 
closed nozzle 12A is used, a plugged nozzle situation will cause the 
rupture disc 18 to open due to excess hydraulic pressure. Fluid will flow 
through the previously closed nozzle 12A returning the hydraulic system to 
an optimized condition and drilling can continue uninterrupted. 
Another example of when the invention may be used as a safety valve is when 
nozzles get plugged with drilling fluid additives. When drilling wells 
that tend to lose drilling fluid into weak, permeable formations, lost 
circulation material (LCM), is commonly added to the mud to help control 
and prevent fluid losses. Some LCM particles are large enough to plug the 
nozzles. Traditional drilling practice for this type of well has been to 
use large diameter nozzles that are less likely to become plugged. This 
usually means that the hydraulics are not optimized for the well. With the 
present invention, a drill bit can be used with optimum nozzle sizes and a 
large diameter closed nozzle 12A can be added for activation in case the 
optimized nozzles are plugged by the LCM. 
The present invention can also be used in hydraulics experiments. 
Previously, drill bit TFA has been a fixed value in experiments since it 
could not be altered during a test. However, since a drill bit containing 
a closed nozzle 12A would allow the bit TFA to be increased or decreased 
during testing by methods mentioned above, it could be used as an 
experimental variable, allowing data interpretation and deduction to be 
attributed to specific changes in the bit TFA and associated parameters. 
For example, in an experiment to see if the hydraulic system's flow rate 
has an effect on the drilling penetration rate for a given a certain mud 
weight, the present invention can be utilized to allow a test to be done 
at two different flow rates, while keeping the system's pressure constant, 
which is the needed control. The test would start at a lower flow rate and 
specific pressure. When the required data has been collected, the flow 
rate can be increased, causing a temporary increase in the system's 
pressure until the rupture disc 18 in the closed nozzle 12A opens. When 
the rupture disc 18 opens, the pressure will return to the previous level 
and the higher flow rate test can be conducted since the bit TFA has been 
increased. 
The subject invention was used in a field test. A drill bit, containing 
three open nozzles with nozzle diameter sizes of 12, 13, 13 (for example, 
a 13 size nozzle has a diameter of 3/32 ") and a closed size 18 nozzle 
containing a rupture disc rated at 2100 psi was used to drill a well. The 
maximum pump pressure was 2500 psi and with an 8.5 PPG drilling fluid the 
bit nozzle pressure loss was calculated to be about 1586 psi at 5000 feet. 
At 5020 feet a salt water injection zone was encountered which required an 
increase in drilling fluid density to 13.0 PPG. The rupture disc was 
opened by maintaining the original flow rate of 530 GPM. This allowed 
fluid to flow through the closed size 18 nozzle plus the existing 12, 13 
and 13 sized nozzles resulting in an optimized hydraulic system with a 
13.0 PPG drilling fluid, a flow rate of 530 GPM, and a bit pressure loss 
of 871 psi, without having to remove the drill bit from the well in order 
to make the nozzle changes on the surface. 
The ability to increase or decrease the total flow area of the drill bit is 
important since an optimized hydraulic system can improve the drilling 
rate, reduce equipment inefficiencies and lower drilling costs. The 
present invention allows the bit total flow area to be easily and quickly 
adjusted concurrently with drilling. 
It should be understood that there can be improvements and modifications 
made to the embodiments of the invention described in detail above without 
departing from the spirit or scope of the invention, as set forth in the 
accompanying drawings.