US20100147594A1

US20100147594A1 - Reverse nozzle drill bit

Info

Publication number: US20100147594A1
Application number: US12/514,069
Authority: US
Inventors: Sadek Ben Lamin; Cody Graham
Original assignee: ND DOWNHOLE Tech Ltd
Current assignee: ND DOWNHOLE Tech Ltd
Priority date: 2006-11-08
Filing date: 2007-11-08
Publication date: 2010-06-17
Also published as: WO2008055349A1

Abstract

A drill bit design that employs reverse flow nozzles through which a portion of the drilling fluid is diverted. This reverse or upward flow of drilling fluid creates a condition by which the extraction of drilling sludge (combination of drilling fluid and drilling cuttings) in the cutting area of the drill bit is more efficient and has a greater amount of flow than designs of prior art. This increased flow has the effect of more efficiently removing damaging cuttings away from the drill cutters, lubricating the drill cutters more efficiently, and cooling the drill cutters more efficiently. The end result is increased drilling uptime, increased drilling speed, and less frequent drill bit catastrophic failures.

Description

CROSS REFERENCE TO RELATED APPLICATIONS

This application claims the benefit of priority of U.S. Provisional Patent Application No. 60/864,819 filed Nov. 8, 2006, which is incorporated herein by reference in its entirety.

FIELD OF THE INVENTION

The present invention relates generally to well drilling technology. More particularly, to drill bits used for drilling oil wells and other similar drilling operations.

BACKGROUND OF THE INVENTION

The technology of drilling oil wells and other similar drilling operations such as for natural gas or water or other similar boring operations is affected by the design of the drill bit itself. Specifically, it is very expensive to lease and operate drilling rigs so reduced downtime, increased drill bit operating life, and drilling speed (rate of penetration or ROP) are favorable attributes. Additionally, drill bits may be leased due to their relatively high cost. However, if a drilling operation damages the drill bit in a catastrophic manner, the client is responsible for the replacement cost of the drill bit. Therefore a drill bit design that has increased drilling speed, increased longevity, and robustness against factors that can contribute to drill bit breakage or damage are all desirable in the industry of well drilling.
Drill bits, used in subterranean drilling, are normally run on the end of hollow drillpipe which is threaded together and to the drill bit. Drill bits can be of the rotary tri-cone/uni or multi-cone design or the more modern poly-crystalline diamond compact (PDC) solid construction variety. The drill pipe is rotated at speeds generally from about 25 or 50 rpm to about 100 or 200 or 300 rpm by rotation of the drill string and a specialized drilling mud or drilling fluid flows through the drill pipe to the drill bit to aid in the drilling process. At the point of contact with the rock formations, casing or other metal being drilled, the drill bit cutting structure gouges, scrapes and chips at the rock generally pulverizing the once competent rock into debris which has to be removed from the bit as soon as it is generated.
Drilling fluid is used to lubricate and cool the drill bit cutting surfaces. It is also the mechanism by which the drilled cuttings are extracted from the drilling area. It is, in prior art designs, delivered to the drilling area through the center of the hollow drill shaft. The drill shaft is threadingly coupled to the drill bit where the pressurized fluid enters the drill bit inner cavity. The pressurized fluid is then delivered through one or more nozzles near the bottom of the bit (typically on the drill bit cutting face). Drilling occurs by the cutting heads shearing and compressingly crushing the bottom of the well hole as the drill bit is rotated and forced downward. Additionally, the drilling fluid can contribute to the drilling as well. The mixture of drilling fluid and drilled media, referred to as drilling sludge, then travels upward between the inside diameter of the drilled hole and the outside diameter of the drill shaft, commonly referred to as the annulus. Though this is common practice, the extraction process of the drilling sludge from the drill bit cutting face is not ideal. Typically, drill bits have many small cutters that are each designed to perform small amounts of shearing. Each is staged in a sequence. Therefore, when a portion of the drilled media remains in the drilling area, successive cutters in the drill bit sequence are presented with cutting media obstructions to pulverize instead of efficiently performing the next portion of cutting deeper into the media to progress the drilling operation. This leads to excessive and premature dulling of the drill bit cutters and can lead to catastrophic failures.
The removal of cuttings is particularly important when considering the drill bit's progress or “penetration rate” is detrimentally affected when the drilling operation is regrinding cuttings rather than attacking new formation. The drilling fluid serves to:

- Lubricate the drill bit
- Hydraulically remove generated cuttings
- Cool the bit and prevent it from damage due to over-heating
- Contain or help control any formation pressures encountered while drilling
- Provide formation samples for geologists to identify where in the lithological column drilling is actually taking place at any particular time
- Assists in the safe circulating of any hydrocarbons that may be released as a result of drilling through a porous formation
- The fluid also imparts a very high impact force when it exits the relatively small diameter jet openings or nozzles at the drill bit face. This action, to some degree, also contributes to dislodging any loose debris and helps to ensure the debris is flushed away from the cutting structure of the drill bit.

Under normal drilling conditions, drill bits make significant progress simply by combining the destructive forces of polycrystalline diamond compact (PDC) cutters and the drilling fluid hydraulic horsepower impact as it exits the jet nozzles. However, the confined space immediately below and around the drill bit body, at times restricts the free flow and therefore the removal of previously cut debris. The result is that the bit's efficiency referred to in terms of unit depth drilled per unit time (e.g. feet or meters per hour) suffers while the bit wastes energy regrinding the cuttings rather than being exposed to new or fresh rock formation. Furthermore, by the time cuttings generated at the bit are cleared away, pulverized and finally transported in the fluid stream to the surface, they may be of a state which renders them relatively difficult to analyze geologically.
Therefore, a drill bit design that optimizes or increases the flow of the drilling sludge upward and away from the drill bit cutting face (drilling area) will improve drilling efficiency, improve uptime, increase speed of drilling (rate of penetration), improve drill bit life, and reduce the risk of potential for catastrophic failure of the drill bit.
The confined annular space around the drill bit body also causes some fraction of the weight on the bit (applied by heavy tubulars immediately above the drill bit called drill collars) not to be directly acting on the drill bit. This action results from a “cushion” of trapped fluid under the bit which is unable to escape rapidly enough. This “hydraulicking” or “piston effect” can drastically impact drill bit performance and could transmit a false signal to the operator that the drill bit is prematurely worn out or damaged possibly beyond repair.

SUMMARY OF THE INVENTION

The present invention provides a drill bit having a reverse nozzle, directing a portion of the cutting fluid in a generally upward direction. It may be applied to newly fabricated rotary drilling bit, or as a retro-active modification to any rotary drilling bit, casing milling or junk milling device (thereafter referred to as drill bit or drill bits) which serves to ameliorate the drill bit's performance through the inclusion of one or more upwardly directed jet nozzles at an angle (preferably between about 45° and about 90° from the horizontal axis of the drill bit body) and diversion of a percentage (preferably about 15% up to about 25%) of the hydraulic drilling fluid flow up the hole (in a direction opposite the downward flow through the cutting face of the drill bit). This diversion enhances drilling performance by creating a region of relatively reduced pressure or “venturi” to promote and increase the efficiency of the removal of cuttings thereby improving the drill bit's ability to contact fresh formation. Several other enhancements, include but are not necessarily limited to, contributing to generally extending the drill bit's operating life, increasing drilling rate per hour (rate of penetration or ROP), increasing downwards weight applied to the cutting structure against the formation or medium being drilled, and enhancing the hole cleaning above the drill bit to avoid being stuck in the debris generated by the drilling action.
It is an object of the present invention to obviate or mitigate at least one disadvantage of previous drill bit designs.
In a first aspect, the present invention provides a drill bit for drilling subterranean formations having a drill bit body extending between a drill bit cutting face and a coupling, the drill bit body having an inner cavity and an outer surface, the inner cavity adapted to receive drilling fluid, a downward passage extending between the inner cavity and the drill bit cutting face, forming a downward nozzle, and a reverse passage extending between the inner cavity and the outer surface, forming a reverse nozzle, the reverse nozzle directed away from the drill bit cutting face at a reverse nozzle upward angle.
Preferably the reverse nozzle upward angle is between about 45 degrees and about 90 degrees. Preferably the reverse nozzle upward angle is substantially 90 degrees.
Preferably the reverse nozzle directed tangentially at a reverse nozzle radial angle. Preferably the drill bit is adapted to rotate in a direction of rotation, the reverse nozzle radial angle being between about 50 degrees to about 75 degrees opposite the direction of rotation.
Preferably the drill bit is adapted to receive a flow rate of drilling fluid, and the reverse flow nozzle adapted to flow less than or equal to 25 percent of the flow rate.
Preferably the reverse nozzle is adapted to discharge the drilling fluid proximate the drill bit cutting face. Preferably the reverse nozzle is adapted to discharge the drilling fluid a reverse nozzle distance from the drill bit cutting face, the reverse nozzle distance being between about 10 inches to about 12 inches (about 250 mm to about 300 mm).
Other aspects and features of the present invention will become apparent to those ordinarily skilled in the art upon review of the following description of specific embodiments of the invention in conjunction with the accompanying figures.
The diverted fluid exit point of the reverse flow nozzle or nozzles are preferably placed at a distance of not more than about 10-12 inches (about 100 mm-150 mm) from the drill bit cutting face. As the distance increases, the venturi effect decreases and at greater distances, the reverse flow nozzle(s) serve no other purpose than as a “helpful lifting flow” rather than the desired relative depressurization at the drill bit cutting face.
The effective action of partial upward fluid diversion creates a relatively lower pressure (or venturi) below where the upward jet is located and either assists in or causes:

- The drill bit to drill faster
- Improved cuttings removal as soon as they are generated
- Wastes less time and energy regrinding the cuttings
- Improves the hole cleaning action
- Improves geological samples which become more representative of the native formation from which they originated
- Reduces overall bit wear and tear
- Allows a greater part of the downhole weight on bit to be acting on the drill bit's cutting structure
- Reduces bit hydraulicking and piston effects
- Contributes to ensuring that any cuttings buildup in the annular space above the bit does not cause the bit or the drilling assembly to become stuck in the hole

All but a small percentage of drill bits in service maybe modified to take advantage of this invention. Preferably, less than about one quarter (about 25%) of the total fluid volume flow delivered to the drill bit is diverted through the reverse flow nozzle. The remaining fluid is powerful enough in terms of rate of flow and volume to maintain drilling performance without significant negative impact.

BRIEF DESCRIPTION OF THE DRAWINGS

Embodiments of the present invention will now be described, by way of example only, with reference to the attached Figures wherein,

FIG. 1 is a side view of a reverse nozzle drill bit of the present invention (of a PDC type);

FIG. 2 is a top view of the reverse nozzle drill bit of FIG. 1;

FIG. 3 is a bottom view of the reverse nozzle drill of FIG. 1;

FIG. 4 is an isometric view of the reverse nozzle drill bit of FIG. 1 with one or two reverse nozzles;

FIG. 5 is an isometric view of the reverse nozzle drill bit of FIG. 1 with two or more reverse nozzles;

FIG. 6 is an isometric view of the reverse nozzle drill bit of FIG. 1 showing the nozzle installed in the reverse nozzle;

FIG. 7 shows two section views of the reverse nozzle drill bit of FIG. 1;

FIG. 8 is a see through isometric view of the reverse nozzle drill bit of FIG. 1 with three reverse nozzles;

FIG. 9 is a simplified schematic view of a reverse nozzle drill bit of the present invention in a borehole; and

FIG. 10 is a side view of a reverse nozzle drill bit of the present invention (of a roller cone type).

DETAILED DESCRIPTION

This disclosure describes a drill bit design that employs a means for promoting efficient and increased upward flow of drilling sludge away from the drilling area and specifically away from the drill bit cutters. The reverse nozzle drill bit employs a singular or a plurality of upward pointing nozzles through which a portion of the pressurized drilling fluid is directed. The resulting flow through the reverse nozzle or reverse nozzles creates a region of relatively lower pressure area between the reverse nozzle or reverse nozzles and the drill bit cutting face. The result of this relatively lower pressure zone is increased flow upward and away from the drill bit cutting face. Additionally, the reverse nozzle or nozzles, which may be directed in a multitude of compound angles and geometric configurations, may additionally create an upward circular flow of drilling sludge.
FIGS. 1 through 8 describe the reverse nozzle drill bit in a polycrystalline diamond compact (PDC) type drill bit. The present invention is not limited to PDC type drill bits, and is applicable to rotary drill bits using drilling fluid such as tricone bits and others known to one skilled in the art.
Referring to FIGS. 1 and 4-6, the drill bit 10 of the present invention (shown as a polycrystalline diamond compact drill bit) has a plurality of cutters 20 fitted to a drill bit body 30. The upper portion of the drill bit 10 includes a coupling 40, shown as threaded, that allows the drill bit 10 and a drill string 50 (see FIG. 9) to connect. The drill string 50 (see FIG. 9), is hollow and delivers pressurized drilling fluid 60 from the surface though to the drill bit 10. A reverse nozzle 70 includes a drilled or otherwise bored hole or reverse passage 80 at an upward angle extending between an outer surface 90 and an inner cavity 100 of the drill bit body 30. The inner cavity 100 is adapted to receive the drilling fluid 60 from the drill string 50. The reverse nozzle 70 may be of a variety of types, sizes, geometries, and may have any of many different flow characteristics.
The drill bit 10 may be manufactured from a solid body of steel or other material by machining and milling in such a manner as to result in the drill bit body 30 with a cylindrical upper body portion and a bladed lower portion having normally 3, 5, 6 or more drill bit blades 145. The drill bit bladed lower portion would itself have 3, 5, 6 or more holes to enable the placement of downward nozzles 130 for the delivery of the drilling fluid 60 at very high rates and pressures proximate the drill bit cutting face 110 of the drill bit 10. The drilling fluid 60 flows through a downward passage 85 extending between the inner cavity 100 and the drill bit cutting face 110.
The drilling fluid 60 (FIG. 9) may be a specialized mixture of an aqueous phase (water, oil or an emulsion or reverse emulsion of both) containing various additives to maintain its consistency without dropping out or depositing its suspended materials and to perform the tasks of cleaning, lubricating and cooling the drill bit, conveyance of the resulting drill cuttings to the surface, counter balancing any formation or geological pressures at great depths and to stabilize the well bore walls to avoid collapse or cave in on the drill bit 10 and the drill string 50 above it.
The inclusion of more or more reverse nozzles 70 serves to direct a portion of the drilling fluid 60 in a direction opposite to the direction of drilling, up the annular space (annulus 230) between the drill string 50 and the formation 120 or rock well bore. Such a diversion of part of the drilling fluid 60 through the reverse nozzle 70 under great pressures and at great rate, serves to assist in the lifting of any cuttings immediately after generation by the cutting action of the drill bit 10. The flow through the upward or reverse nozzles 70 may also impart a cavitation or reduction of pressure at the drill bit cutting face 110. The pressure reduction proximate the drill bit cutting face promotes the rapid removal of fluid charged with new cuttings (drilling sludge 150) from the drill bit cutting face 110 which is then carried through the flow courses or channels between the drill bit blades and then above the drill bit body itself. Rapid cuttings removal from the bit face is beneficial to ensuring the cuttings are not reground or further pulverized rendering the resulting cuttings less useful as geological samples upon arrival at surface. Rapid cutting removal from the drill bit face also results in the drill bit cutting fresh or new rock. The partial flow upwards will assist in reducing or eliminating the tendency to trap particles underneath the drill bit and around the lower part of the drill bit. These trapped particles may cause the drill bit to float and contribute to reducing the effective downward force the drill bit requires to make rapid progress drilling into the formation 120. Prohibitively high drilling costs can be greatly mitigated through maximizing drilling penetration rate and hence reducing the time and the resources required to drill wells.
A previously overlooked benefit of having an upward jet nozzle or plurality of reverse nozzles in drill bits is that they impart an equal and opposite reaction by hydraulically pushing the drill bit into the formation, acting in a similar manner to jet propulsion (mass impulse). Without such upwards or reverse nozzles on any conventional drill bit, extensively used in subterranean drilling, the only hydraulic forces are those emanating from the plurality of jet nozzles located on the drill bit face and pointing directly downwards. These same nozzles serve to help push the drill bit away from the formation that is being drilled and would contribute to negatively affecting drilling performance. The addition of at least one reverse flow nozzle 70, proximate the drill bit cutting face 110 improves hydraulics.
Referring to FIG. 2, the inner cavity 100 of the drill bit 10 is typical of drill bits of the PDC, roller cone, and other types. At the bottom of the inner cavity 100 are a plurality of downward nozzles 130 associated with the drill bit cutting face 110. In this particular configuration, three downward nozzles 130 are shown which is typical in certain configurations.
Referring to FIG. 3, the reverse nozzle drill bit 10 has six drill bit flanges 140. This is one typical design. The present invention may utilize a singular or a plurality of drill bit flanges 140 in the PDC drill bit type. In other drill bit types such as tricone bits and others, the drill bit flange 140 does not exist as is known to one skilled in the art. Each drill bit flange 140 and each drill bit blade 140 has a singular or a plurality of drill bit cutters 20. Typically, the drill bit cutters 20 are configured in a fashion such that each drill bit cutter 20 and each drill bit flange 140 and each drill bit blade 145 is placed geometrically so that each successively performs a small amount of cutting as the drill bit 10 is rotated. This is common general knowledge to one skilled in the art of drill bit design and manufacture, particularly PDC drill bit design and manufacture. However, the reverse nozzle 70 and resulting flow characteristics of the drilling sludge 150 may allow drill bit designers greater flexibility in placement or number of drill bit flanges 140 and/or drill bit blades 145 and/or drill bit cutters 20 in PDC drill bit designs.
Referring to FIG. 7, section B-B depicts the downward nozzle 130 or nozzles 130 in one configuration. As discussed above, the geometric, flow, nozzle, and pressure characteristics of this aspect of the invention may occur in any of a multitude of configurations.
Section A-A describes the reverse nozzle 70 in more detail in one preferred configuration. In this configuration, the reverse nozzle 70 is includes an inner bore 160, an outer bore 170, and a jet nozzle 180 having a jet nozzle exit 185, together forming the reverse passage 80, configured at an angle 190 from the drill bit cutting face 110. This configuration has geometry such that the inner bore 160 is of a smaller diameter or cross section than the outer bore 170. The disclosed invention may take on any of many different combinations of inner bore 160 sizes and shapes, outer bore 170 sizes and shapes, jet nozzle 180 types and sizes, and upward angles 190. The jet nozzle 180 may be formed within a relatively short cylinder 200 (preferably about 1 inch to about 1.25 inch long (about 25 mm to about 35 mm long) inserted into the reverse passage 80 and fixed in place by threads, adhesive, friction/interference fit, or by a retainer means, for example a circular clip 210 that expands into a shielded groove 215 within the reverse passage 80.
Preferably, the jet nozzle exit 185 is proximate the drill bit cutting face 110. Preferably the jet nozzle exit 185 is a reverse nozzle distance 250 from the drill bit cutting face 110. Preferably the reverse nozzle distance 250 is between about 6 in. to about 18 in. (about 150 mm to about 450 mm). More preferably the reverse nozzle distance 250 is between about 10 in to about 12 in. (about 250 mm to about 300 mm).
Additionally, in embodiments having a plurality of reverse nozzles 70, each may be configured in its own, independent or like manner, Also, though the drawings describe a reverse nozzle 70 having a substantially straight reverse passage 80, the reverse passage 80 may be other shapes and configurations such as spirals and involutes and may have a circular, oval or other cross section. The drawings describe a reverse nozzle 70 configuration that has a simple angle in that it is configured at a reverse nozzle upward angle 190 measured from the center axis of the drill bit 10 (the complementary angle being from the drill bit cutting face 110). The reverse nozzle 70 may instead utilize a reverse passage 80 having a compound angle in that there is an angular component to the axis perpendicular to the plane created by the aforementioned vertical and horizontal axes.
The velocity of the drilling fluid 60 exiting jet nozzle 180 is a function of the volume flow rate and the internal area or diameter of the jet nozzle (it is a variable). The velocity out of the jet nozzle 180 at the jet nozzle exit 185 may be translated into hydraulic horsepower at the bit. The pressure drop between the inner cavity 100 and the outer surface 90 can be directly converted into power. A small nozzle opening provides a high velocity and a high hydraulic impact and a large nozzle opening provides a lower velocity and lower hydraulic impact. Preferably the exit velocity from the jet nozzle 180 is greater than or equal to the exit velocity from the downward nozzles 130.
Preferably a single reverse nozzle 70 is utilized rather than a plurality of reverse nozzles 70. Using a single, larger area jet nozzle 180 rather than a plurality of smaller are jet nozzles 180 (which could provide the equivalent total area and equivalent exit velocity) provides for increased self cleaning of the reverse nozzle 70. In normal operations, the drilling sludge 150 is returned to the drill string 50 after conditioning/cleaning at the surface as drilling fluid 60, but the returned drilling fluid 60 may include drill cuttings, particles or other debris or materials that could interfere with or block small area jet nozzles. In addition, during drilling operations, materials may be added to the drilling fluid 50, such as lost circulation materials which are designed to plug off or seal the wellbore to stop leaking drilling fluid 50. These lost circulation materials may interfere with or block small area jet nozzles. Thus, generally speaking, a single, larger bore reverse flow nozzle 70 with a corresponding single larger bore jet nozzle 180 reduce the chances of blockage. Due to the fact that a typical drill string 50 operates at in the order of 200 rpm, the rotating reverse nozzle 70 creates a sufficiently continues upward stream and pressure gradient, particularly when considering the typical viscosities of drilling fluid 50/drilling sludge 150.
The exit from the jet nozzle 180 is preferably highly concentrated into a very small diameter, high velocity stream. A short distance from the jet nozzle exit 185, it dissipates into a fan or spray. The jet nozzle 180 may be swept back at a reverse nozzle radial angle 195 of about 50 to about 75 degrees in a radial direction opposite to the rotation of the drill bit 10. As shown in FIGS. 1-9, the PDC drill bit shown is adapted for clockwise rotation, and in that case the jet nozzle 180 may be swept back at an reverse nozzle radial angle of about 50 to about 75 degrees counter-clockwise.
The jet nozzle 180 may be manufactured from a very hard, abrasion resistant material, such as tungsten carbide or a material such as steel that is coated with a hard coating such as tungsten carbide or other by hardfacing or otherwise.
The reverse nozzle 70 or reverse nozzles 70 may flow a portion of the drilling fluid 60, with the remainder flowing through the downward nozzles 130. Preferably between about 15% and about 25% of the drilling fluid 60 is directed through the reverse nozzle 70.
Referring to FIG. 9, the drill bit 10 of the present invention is connected with a drill string 50 having a multitude of sections of similarly threaded heavy weight and lighter weight hollow centered pipes or tubes all firmly connected together to form the drill string 50.
As the drilling fluid 60, which is delivered downward at high pressure though the inside diameter of the drill string 50 and into the inner cavity 100 of the drill bit 10, a portion is directed through the downward nozzle or downward nozzles 130 and a portion directed upwards through the reverse nozzle or nozzles 70. The upward flow creates a lower pressure zone between the reverse nozzle or nozzles 70 and the drill bit cutting face 110. The lower pressure area creates a condition where the drilling sludge 150 has increased flow away from the drill bit cutting face 110 upward and away from the drill bit cutters 20. The result is more efficient extraction of the drilling sludge 150, increased cooling of the drill bit cutters 20, increased lubrication of the drill bit cutters 20, and the propensity for there to be fewer obstructions in the drilling sludge 150 that can damage the drill bit cutters 20. Additionally, the flow out of the reverse nozzle 70 has the condition of spiraling flow. The spiraling flow has the advantage of greater and more efficient extraction of the drilling sludge 150 through the annulus 230 between the inside diameter of the bore hole 220 and the outside diameter of the drill string 50. The annulus 230 is not uniform throughout the length of the bore hole 20 due to the flexible nature of the drilling shaft and deviations while drilling.
Referring to FIG. 10, a drill bit 10 of the present invention (shown as a roller cone type) may have a reverse nozzle 70 or a plurality of reverse nozzles 70, either generally aligned with or between the shirttails.
The present invention is applicable not only to the PDC type drill bit shown, but also to roller cone drill bits and other rotary drill bits, casing milling or junk milling tool, diamond drill bit, solid carbide/tungsten carbide drill bit or mill, crushed carbide/crushed tungsten carbide drill bit or casing or junk mill or any variation thereof which is connected to the lower most end of the drilling or milling string or shaft and which actually performs the task of drilling, boring, cutting, grinding, scraping, gouging, ploughing, skimming or removing formation, rock, sandstones, steels or other metallic objects in a subterranean well bore or tubular materials in a subterranean well bore.
A drill bit of the rotary type of the present invention may be rotated by rotation of the drill string from surface (for example by rotary table, power swivel or otherwise) or the drill bit may be rotated downhole (for example by downhole motor or turbine or otherwise).
In the preceding description, for purposes of explanation, numerous details are set forth in order to provide a thorough understanding of the embodiments of the invention. However, it will be apparent to one skilled in the art that these specific details are not required in order to practice the invention.
The above-described embodiments of the invention are intended to be examples only. Alterations, modifications and variations can be effected to the particular embodiments by those of skill in the art without departing from the scope of the invention, which is defined solely by the claims appended hereto.

Claims

1. A drill bit for drilling subterranean formations comprising:

a. a drill bit body extending between a drill bit cutting face and a coupling, the drill bit body having an inner cavity and an outer surface, the inner cavity adapted to receive drilling fluid;

b. a downward passage extending between the inner cavity and the drill bit cutting face, forming a downward nozzle; and

c. a reverse passage extending between the inner cavity and the outer surface, forming a reverse nozzle,

the reverse nozzle directed away from the drill bit cutting face at a reverse nozzle upward angle.

2. The drill bit of claim 1, the reverse nozzle upward angle being between about 45 and about 90 degrees.

3. The drill bit of claim 2, the reverse nozzle upward angle being substantially 90 degrees.

4. The drill bit of claim 1, the reverse nozzle directed tangentially at a reverse nozzle radial angle.

5. The drill bit of claim 4, the drill bit adapted to have a direction of rotation, the reverse nozzle radial angle being between about 50 degrees to about 75 degrees opposite the direction of rotation.

6. The drill bit of claim 1, wherein the drill bit is adapted to receive a flow rate of drilling fluid, the reverse flow nozzle adapted to flow between about 10 percent and about 40 percent of the flow rate.

7. The drill bit of claim 1, wherein the drill bit is adapted to receive a flow rate of drilling fluid, the reverse flow nozzle adapted to flow between about 15 percent and about 25 percent of the flow rate.

8. The drill bit of claim 1, wherein the drill bit is adapted to receive a flow rate of drilling fluid, the reverse flow nozzle adapted to flow less than or equal to about 25 percent of the flow rate.

9. The drill bit of claim 1, wherein the drill bit is adapted to receive a flow rate of drilling fluid, the reverse flow nozzle adapted to flow less than or equal to about 15 percent of the flow rate.

10. The drill bit of claim 1, wherein the drill bit is adapted to receive a flow rate of drilling fluid, the reverse flow nozzle adapted to flow less than or equal to about 10 percent of the flow rate.

11. The drill bit of claim 1, wherein the drill bit is adapted to receive a flow rate of drilling fluid, the reverse flow nozzle adapted to flow less than or equal to about 5 percent of the flow rate.

12. The drill bit of claim 1, wherein the reverse nozzle is adapted to discharge the drilling fluid proximate the drill bit cutting face.

13. The drill bit of claim 12, wherein the reverse nozzle is adapted to discharge the drilling fluid a reverse nozzle distance from the drill bit cutting face, the reverse nozzle distance being between about 10 inches to about 12 inches (about 250 mm to about 300 mm).

14. The drill bit of claim 1, wherein the drill bit is adapted to receive a flow rate of drilling fluid, the reverse nozzle adapted to discharge a portion of the drilling fluid at a reverse nozzle velocity and the downward nozzle adapted to discharge a portion of the drilling fluid at a downward nozzle velocity, wherein the reverse nozzle velocity is between about 50 percent and about 150 percent of the downward nozzle velocity.

15. The drill bit of claim 14, wherein the reverse nozzle velocity is between about 75 percent and about 125 percent of the downward nozzle velocity.

16. The drill bit of claim 14, wherein the reverse nozzle velocity is between about 90 percent and about 110 percent of the downward nozzle velocity.

17. The drill bit of claim 14, wherein the reverse nozzle velocity is substantially 100 percent of the downward nozzle velocity.

18. The drill bit of claim 1, wherein the drill bit is a PDC type drill bit.

19. The drill bit of claim 1, wherein the drill bit is a roller cone drill bit.