DRILL BIT

Abstract

A drill bit is made from a shank, lid and blades. Junk slots with higher resistance to flow are provided to force drilling fluid between cutters on adjacent blades to improve cleaning. Blades are canted back, and openings at a high angle are provided to further enhance cleaning. The use of a lid facilitates high angle openings. The cutters may be made of sintered powder metal, and may include polycrystalline inserts. The blades may include a preferential conductive cooling material. The drill bit may include an enlarged hollow chamber and a relatively thin and long peripheral drill bit wall.

Description

FIELD OF THE INVENTION

This invention relates to the field of drilling equipment, including drill bits for drilling equipment.

BACKGROUND OF THE INVENTION

A challenge in underground drilling is to provide a drill bit with extended life, that cuts reasonably quickly through geological formations of various types and that avoids balling up of cuttings in the vicinity of the drill bit. The balling up of cuttings in the vicinity of the drill bit may cause the drill bit to cease cutting as the cutting elements no longer contact the earth formation.

Modern drilling bits may typically have a form that includes a body, blades extending from the body, predominantly forwardly (i.e., in the direction of drilling) but also extending somewhat radially outward of the body, and polycrystalline diamond cutters (PDCs) embedded in the cutting faces of the blades. Two main types of PDC drill bits on the market are the matrix body and steel body. Matrix body bits are one piece construction and are made in a mold as for example disclosed in U.S. Pat. No. 6,823,952. The material is a mixture of steel and tungsten carbide. Steel body bits are also one piece construction but are cut on a lathe and made from 4140 steel, 4145 steel or a similar material. The blades on PDC bits are typically set in a vertical plane, or may be canted forward slightly towards the cutting surface. Some bits have forward sweeping cutting elements, as for example disclosed in U.S. Pat. No. 5,443,565. The PDC cutting elements provide hard wearing surfaces that cut the formation. Junk slots between the blades provide pathways for the removal of cuttings away from the bit face into the annular space of the wellbore. Most PDC bits make the junk slot area as wide and as obstruction free as possible for the pathway to remove cuttings.

To assist in removal of cuttings, drill bits of this nature may tend to have a central bore, roughly corresponding in size to the central bore of the drill string more generally. The end of the drill bit may be bored to provide openings or nozzles in the forward end of the drill bit by which drilling mud supplied through the main bore may flow out as direct fluid jets oriented to urge flow between the blade surfaces. The drilling fluid, which is also typically used in a mud motor to power the drill bit, passes through the inside of the drill bit, through the nozzles and the junk slots, and draws cuttings away from the drill bit towards the surface. The bits tend to be quite robust, having thick, or very thick walls, typically well over 1 inch in thickness.

In a further problem with PDC type drill bits, cutter surfaces often fail as a result of high temperatures created from friction between the cutter and the rock it is cutting. When a PDC cutter reaches a critical temperature known as the thermal degradation temperature, the diamond surface will separate from the tungsten carbide substrate. The thermal degradation temperature ranges from 300° C. to 700° C. Heat is removed from the bit face and the cutters by the drilling fluid as it removes the cuttings from the surface of the drill bit. Heat is also transferred through the tungsten carbide cutter into the blade and bit body. Tungsten carbide is a much better conductor of heat than steel. Therefore the transfer of heat away from the cutters into the blades and bit body may not be as efficient as may be desired in a steel body bit.

SUMMARY OF THE INVENTION

According to an aspect of this invention, there is provided a drill bit, and a method of manufacturing a drill bit, that uses the design of junk slots between the blades of the drill bit to enhance removal of cuttings from the drill bit. In a method of construction of a drill bit, according to an aspect of the invention, a drill bit is made of a shank, lid welded to the shank and blades welded in slots in the lid.

According to further aspects of the invention, junk slot impingement is used to increase cuttings removal through alternating junk slots. Provision of high angle nozzles in the forward end of the drill bit, which is facilitated by the method of construction, also assists in cuttings removal. According to a further aspect of the invention, a drill bit with PDC cutters is provided with a cooling feature to remove heat from the PDC cutters more efficiently. A high conductivity conduit leading from the cutters guides heat away from the cutters into the blade and hence into the bit body.

In an aspect of the invention, there is provided a drill bit that has a central axis of rotation, and a direction of rotation. The drill bit has a body that has a driven end for connection to a drive train operable to rotate said bit, and a cutting end axially distant from said driven end. The cutting end has an array of cutting members mounted thereto. The array include members defining at least first and second junk slots therebetween. The first junk slot is at least part of a first flow path for cutting fluid. The second junk slot is at least part of a second flow path for cutting fluid. The first of the cutting members of the array defines a partition between the first and second flow paths. The first and second paths for cutting fluid has an entrance at which to introduce cutting fluid, and an exit at which to discharge cutting fluid. At least a portion of the second flow path is constricted as compared to the first flow path.

In a feature of that aspect of the invention, the second flow path includes a constriction that has a hydraulic diameter that is less than ¾ of a hydraulic diameter of a corresponding portion of said first flow path. In another feature, the second flow path includes a first, predominantly radial, portion; and a second, predominantly axial, portion. The portion of the flow path that is constricted forms at least part of the predominantly axial portion of the second flow path. In another feature, the first flow path has a first, predominantly radial portion that has a first resistance to flow R1, and a second, predominantly axial portion that has a second resistance to flow R2. The second flow path has a first, predominantly radial portion that has a third resistance to flow R3, and a second, predominantly axial portion that has a fourth resistance to flow R4 wherein R1/R2 is greater than R3/R4. In another feature, the first of the cutting members of the array defines a leaky partition between the first and second flow paths. In another feature the first of the cutting members extends predominantly radially and has a toothed profile. In a further feature, the first cutting member extends predominantly radially and has a first toothed profile. The second cutting member extends predominantly radially, and has a second tooth profile. One of the first and second toothed profiles includes at least one axially protruding asperity radially offset from any asperity of the other of the toothed profiles. In still another feature, the first and second tooth profiles are radially phase shifted. In yet another feature, the array of cutting members includes at least one member formed of sintered powder metal. In a still further feature, the sintered powder metal cutting member includes a polycrystalline diamond insert. In again another feature, the second junk slot has a flow restriction mounted therewithin. In a further feature the restrictions include a blade extension. In a further feature, each restriction comprises an extension of a secondary blade. In still yet another feature, each restriction of a pair of junk slots sweeps circumferentially under the intervening blade. In a still further feature, the drill bit has a hollow head through which cutting fluid may be supplied. The hollow end of the drill bit has a lid. In another feature, the drill bit lid has porting to permit the transport of cutting fluid therethrough. In an additional feature, the drill bit porting includes ports angled in an orientation that has a radial component of direction. In still yet another feature, the drill bit body has a rotational axis, and nozzles oriented at an angle greater than 15° to the rotational axis and directed to feed drilling fluid between the members of the array. In yet another further feature, the drill bit body includes a cylindrical sidewall capped by an end lid welded thereto. The end lid is multiply ported whereby the end lid defines a drill fluid delivery manifold.

In another aspect of the invention there is a drill bit for drilling well bores in geological formations. The drill bit has a drill bit body. The drill bit body has a first end and a second end, the first end of the drill bit body having a cutting face and cutting members mounted thereto, the second end facing away from the first end and providing a member to which a shank for engagement to a drill string can be mounted. The drill bit body has a peripheral wall extending between the first and second ends. The peripheral wall has a thickness of less than 1 inch. The body has a chamber defined therein. The chamber has a diameter of at least 3 inches. The chamber has an inlet of a diameter less than 3 inches through which drilling mud may flow into the bit body, and the bit body having ports by which drilling fluid may exit the bit body.

In a feature of that aspect of the invention, the chamber is a resonating chamber. In another feature, the bit body has a wall thickness of less than 15% of the diameter of the chamber. In another feature, the wall thickness is up to ½″. In a further feature, the wall thickness is at least 5/16″. In another feature, the chamber has an internal cross sectional area A_f, the wall has a cross sectional area Aw, and a ratio of Af:Aw lies in the range of greater than 4:1. In still another feature, the chamber has a length, that length being in the range of at least ⅔ as great as the chamber diameter. In still another feature, the chamber has a length, that length being in the range of ¾ to 2 times the diameter of the chamber. In yet another feature, the drill bit has vane members extending predominantly axially externally of the peripheral wall, and at least one of the vane members is relieved to accommodate radial flexing of the peripheral wall.

In still another feature, there is a combination of the bit body and the shank, the shank being mounted to the drill bit body, the combination having at least one of the following features (a) the shank having a re-entrant nose; and (b) the ports have nozzles mounted therein, and at least one of the nozzles has a re-entrant end extending into the chamber.

In another aspect of the invention there is a drill string combination. It includes a pulsating source of drilling fluid; drill pipe sections for connection together and for connection to the source of drilling fluid; drill collars for connection to the drill pipe sections; and a drill bit for mounting below the drill collars. The drill bit has a first end for cutting the well bore, and a second end having a shank for connecting the drill bit to the drill string below the drill collars. The combination includes a tensioning device for holding back a portion of the weight of the drill collars. The drill pipe section has an internal diameter. The drill bit has a chamber therein between the first and second ends, the chamber having a diameter greater than the drill pipe section. The chamber is surrounded by a peripheral wall, the peripheral wall having a wall thickness of less than 1″, and the chamber having a length at least ⅔ as great as the diameter of the chamber. The chamber having an inlet through which drilling mud can enter the chamber, and an outlet through which drilling mud may be directed to remove cuttings.

In another feature the combination includes between 30,000 lbs and 50,000 lbs of drill collars. In a further feature, the drill bit includes at least one of the following features: (a) the wall thickness is in the range of ¼ to ½ inches; (b) the wall thickness is in the range of 5/16″ to 7/16″; (c) the wall thickness is in the range of 5% to 15% of the diameter; (d) the wall thickness is in the range of 6% to 10% of the diameter; (e) the wall has a cross sectional area A_w, and the chamber has a cross-sectional area A_f, and A_w lies in the range of less than 25% of A_f; (f) the chamber has a length, and the thickness is less than ⅕ of the length; (g) the chamber has a length and the thickness is less than 1/10 of the length; (h) the chamber has a length, and the length is at least ⅔ of the diameter of the chamber; and (i) the chamber has a length, and the length lies in the range of ¾ to 2 times the diameter of the chamber. In still another feature, the drill bit includes items (b), (d), (g) and (i).

In another feature of that aspect of the invention, there is a well boring process employing the drill string combination, the process including providing a pulsating flow of drilling fluid to the bit while the bit is boring a well. In a further feature, there is a well boring process employing the drill string combination, the process including inducing torsional stress in the bit body and at the same time imposing a time varying stress field in the body that in addition to the torsional stress includes at least one of (a) a fluctuating hoop stress in the peripheral wall; (b) a fluctuating axial stress in the peripheral wall; and (c) a fluctuating bending stress in the peripheral wall. In another feature, the process includes inducing a reversing axial stress in the peripheral wall. In still another feature, the chamber has a face area, A_f, the drill string includes a weight of drill collars W and the drill string is partially tensioned to impose a hold down force on the drill bit, the hold down force being a portion of W, the process includes pumping the drilling fluid at a pressure P, and the force obtained by multiplying the pressure P by Af is greater than the hold down force. In a further feature, the process includes providing pulsating jets of drilling fluid to urge cuttings away from the drill bit. In still another feature, the process includes at least one of the following: (a) operating pumping equipment to supply drilling fluid at a pressure in the range of 500 to 1500 psi; (b) operating pumping equipment to produce pulsations in the range of 150 to 300 pulses per minute in the drilling fluid; and (c) operating rotating equipment to cause the bit to rotate at a rotational speed in the range of 60 to 150 r.p.m.

In another aspect of the invention there is a drill bit. It has a drill bit body having a cutting end and a central flow passage; plural blades extending out from the cutting end of the drill bit body; cutters in each one of the plural blades; nozzles in the drill bit body passing through the cutting end, and providing a flow path between the central flow passage and the cutting end; plural junk slots in the drill bit body, each blade of the plural blades separating adjacent junk slots; the junk slots alternating in pairs around the cutting end, each pair of junk slots including a junk slot with a higher resistance to fluid flow and a junk slot with a lower resistance to fluid flow, with an intervening blade between the pair of junk slots, such that, in operation, the junk slot of each pair of junk slots with higher resistance to fluid flow forces drilling fluid from the junk slot with higher resistance into the junk slot with lower resistance, the drilling fluid being forced across the intervening blade and between the cutters of the intervening blade.

In another feature of that aspect of the invention, the blades alternate between primary blades and secondary blades, and the primary blades are the intervening blades. In another feature each junk slot with higher resistance incorporates a restriction in the junk slot. In another feature, in which the restrictions comprise an extension of a blade. In another feature, in which each restriction comprises an extension of a secondary blade. In another feature, in which each restriction of a pair of junk slots sweeps circumferentially under the intervening blade. In another feature each blade is canted backward. In another feature the drill bit body has a rotational axis, and the nozzles are oriented at an angle greater than 15° to the rotational axis and directed to force drilling fluid between the blades. In another feature the drill bit body includes a shank, and the cutting end of the drill bit body is formed of a peripheral wall welded to the shank. In another feature, the blades are welded into slots in the bit body.

In another aspect of the invention there is a drill bit having a drill bit body having a cutting end, a central flow passage and a rotational axis; plural blades extending out from the cutting end of the drill bit body; cutters in each one of the plural blades; nozzles in the drill bit body passing through the cutting end, and providing a flow path between the central flow passage and the cutting end, the nozzles being oriented at an angle greater than 15° to the rotational axis and directed to force drilling fluid between the blades; and plural junk slots in the drill bit body, each blade of the plural blades separating adjacent junk slots. In another feature of that aspect of the invention the drill bit body includes a shank, and the cutting end of the drill bit body is formed of a peripheral wall welded to the shank. In another feature the blades are welded into slots in the bit body. In another feature each blade is canted backward.

In yet another aspect of the invention, there is a drill bit having a drill bit body having a cutting end, a central flow passage and a rotational axis; the cutting end of the drill bit body including a front facing plate member; plural blades extending out from the plate member; cutters in each one of the plural blades; nozzles in the drill bit body passing through the cutting end, and providing a flow path between the central flow passage and the cutting end; and plural junk slots in the drill bit body, each blade of the plural blades separating adjacent junk slots.

In yet another aspect, there is a drill bit having a drill bit body having a cutting end and a central flow passage; plural blades extending out from the cutting end of the drill bit body; cutters in each one of the plural blades; nozzles in the drill bit body passing through the cutting end, and providing a flow path between the central flow passage and the cutting end; and plural junk slots in the drill bit body, each blade of the plural blades separating adjacent junk slots, the plural junk slots including junk slots with unimpeded flow paths for removal of cuttings and junk slots with impeded flow paths for removal of cuttings. In another feature of that aspect of the invention, the junk slots with unimpeded flow paths alternate with the junk slots with impeded flow paths.

In still another aspect, there is a drill bit, having a drill bit body having a cutting end, a central flow passage and an outer periphery; plural blades extending out from the cutting end of the drill bit body, the plural blades extending forward of the cutting end, radially outward from the cutting end and along the outer periphery of the drill bit body to form a stabilizer; the plural blades including blades extending along the outer periphery of the drill bit body for different distances; cutters in each one of the plural blades; nozzles in the drill bit body passing through the cutting end, and providing a flow path between the central flow passage and the cutting end; and plural junk slots in the drill bit body, each blade of the plural blades separating adjacent junk slots. In another feature the plural blades alternate between shorter blades and longer blades in length extending along the outer periphery of the drill bit body. In another feature, each blade of one set of blades in the plural blades curves under a respective adjacent blade.

In still another aspect there is a drill bit having a drill bit body having a cutting end, a central flow passage and a central axis; plural blades extending out from the cutting end of the drill bit body; each blade of the plural blades being oriented on the cutting end of the drill bit body such that a linear extension of the blade would pass behind the central axis; cutters in each one of the plural blades; nozzles in the drill bit body passing through the cutting end, and providing a flow path between the central flow passage and the cutting end; and plural junk slots in the drill bit body, each blade of the plural blades separating adjacent junk slots. In another feature the blades are canted rearward.

In still yet another aspect of the invention, there is a drill bit having a drill bit body having a cutting end and a central flow passage; plural blades extending out from the cutting end of the drill bit body; cutters in each one of the plural blades, cutters in succeeding blades overlapping cutters in preceding blades in the direction of rotation by more than 25% and less than 100%, each cutter in a succeeding blade overlapping only one cutter in the corresponding preceding blade; nozzles in the drill bit body passing through the cutting end, and providing a flow path between the central flow passage and the cutting end; and plural junk slots in the drill bit body, each blade of the plural blades separating adjacent junk slots.

In still yet a further aspect of the invention there is a drill bit having a drill bit body having a cutting end, a central flow passage and a rotational axis; plural blades extending out from the cutting end of the drill bit body, the blades being made of material having a first heat conductivity; cutters in each one of the plural blades; nozzles in the drill bit body passing through the cutting end, and providing a flow path between the central flow passage and the cutting end, the nozzles being directed to force drilling fluid between the blades; heat conducting conduits in each blade, each heat conducting conduit terminating in heat conducting proximity to a cutter on the respective blade, the heat conducting conduits leading into the blade away from the cutters, and the heat conducting conduits being made of a material having a second heat conductivity, the second heat conductivity being higher than the first heat conductivity; and plural junk slots in the drill bit body, each blade of the plural blades separating adjacent junk slots. In another aspect there is a method of making a drill bit, the method including separately machining a shank and peripheral wall to join to the shank; forming slots in the lid for blades; welding the peripheral wall to the shank; and welding blades into the slots in the lid.

BRIEF DESCRIPTION OF THE FIGURES

The principles, aspects and features of the present invention may be understood with reference to the following description and the accompanying illustrations, in which:

FIG. 1a is perspective view of a drill bit according to the invention;

FIG. 1b is a sectional view of the drill bit of FIG. 1a as drilling in a geological formation;

FIG. 1c is a side view of the drill bit of FIG. 1a as drilling in a geological formation;

FIG. 2 is a view of a shank for use with the drill bit of FIG. 1a;

FIG. 3 is a perspective view of a cutting end of a lid for use with the drill bit of Figure 1a;

FIG. 4 is a perspective view of the opposite end of the lid of FIG. 3;

FIGS. 5a to 5d relate to method of making a blade having the drill bit of FIG. 1a;

FIG. 6 shows a method of assembling blades into the drill bit of FIG. 1a;

FIG. 7 is a cross-section through a blade showing a cooling feature according to an aspect of the invention;

FIG. 8 is a cross-section through the bit showing a nozzle aspect of the invention;

FIG. 9 illustrates offset cutters on succeeding blades;

FIG. 10 is a section through a blade and cutter showing a soft metal insert behind the cutter;

FIG. 11a shows a cross section like that of FIG. 1b, of an alternate bit to that of FIG. 1a; and

FIG. 11b shows a view similar to that of FIG. 1c of the alternate bit of FIG. 11a.

DETAILED DESCRIPTION

The description that follows, and the embodiments described therein, are provided by way of illustration of an example, or examples, of particular embodiments of the principles of the present invention. These examples are provided for the purposes of explanation, and not of limitation, of those principles and of the invention. In the description, like parts are marked throughout the specification and the drawings with the same respective reference numerals. The drawings are not necessarily to scale and in some instances proportions may have been exaggerated in order to more clearly depict certain features of the invention. In the claims, the word “comprising” is used in its inclusive sense and does not exclude other elements being present. The indefinite article “a” before a claim feature does not exclude more than one of the feature being present.

It may be helpful to identify co-ordinate systems that may aid in understanding the present description. This description pertains to drill bits that most typically are driven rotationally about an axis of rotation, and that advance along that axis. In terms of a cylindrical polar co-ordinate system, the axial, or z-direction is defined by the axis of rotation of the drill bit. The circumferential direction is that through which angles, angular velocity, and angular accelerations, (typically θ, ω, and α) may be measured, often from an angular datum, or angular direction, in a plane perpendicular to the axial direction. The radial direction is defined in the plane to which the axial direction is normal, extending away from the axial centerline of the bit.

As a preliminary matter, this description relates to various embodiments of drill bits and their operation. These bits are generally employed at the downhole end of a drill string. The drill string is driven by a drilling rig at the surface, which may include a rotating drill table. The speed of rotation of the drill string may be of the order of perhaps 60 to 90 r.p.m. The drill string is most typically 3½, 4, 4½, or 5 inches in diameter, and is made of sections of hollow pipe, usually ½ inch thick. Cutting fluid, in the nature of water or drilling mud is force down the inside of the hollow drill sting under pressure, and flows back up the generally annular space about the drill string, and back to the surface. The deeper the well, the higher proportion of drilling mud as opposed to water. The drilling mud is driven by pumps, which are usually duplex or triplex pumps. A duplex pump is a double acting reciprocating pump. A triplex pump is a positive displacement, reciprocating pump that has three plungers. Triplex pumps are the most commonly used pump configuration for drilling and well service operations. Both duplex and triplex pumps tend to yield a vibrating or pulsating effect in the drilling fluid, an effect that may be more pronounced when duplex pumps are used. A duplex pump running at 60 r.p.m. will give off 240 pulsations per minute, a triples single acting pump will give off 180 pulses per minutes. These pulses can be observed in the drill string. Output flow may be of the order of 1.0 to 2.0 cubic meters per minute, or roughly 4 to 8 U.S. gallons per second. More commonly the flow rate may be in the range of 1.3 to 1.6 cubic meters per minute. For a hollow pipe having an internal bore of 2¼ or 2½ inches, this will give a velocity of roughly 20 to 30 ft/s. The pressure at the outlet of the pump may be in the range of about 400 or 500 to about 1500 p.s.i., and may run in the narrower band of about 800 p.s.i. to about 1000 p.s.i.

A drill string may have a very high aspect ratio of length to diameter, and a certain overall springiness or resilience both longitudinally and torsionally. The lower end of the drill string may include a number of sections of drill collars. Drill collars are often thick walled steel pipe sections about 30 ft long, and may have an inside diameter of 2¼ or 2½ inches, and an outside diameter of 5 or 6 inches. A drill string may have e.g., 18 or 24 such drill collars at the bottom end. These drill collars may tend to function somewhat like a plumb bob. The drill string may (or may not) include a mud motor, which may be mounted below the drill collars. The mud motor is a kind of hydraulic motor driven by the flowing drilling mud. The rotational speed of the bit itself is then the sum of the rotational speed of the drill string, plus the rotational speed of the mud motor (if any). The drill bit is mounted below the mud motor. Drill bit speeds employed with the drill bits described herein may be in the range of about 100 or 120 r.p.m. to about 150 r.p.m.

Not all of the weight of the drill string bears upon the drill bit. The upper end of the drill string is held back, or held in tension, such that a portion of the weight of the drill collars bears on the drill bit, forcing it forward at the bottom of the well bore. That portion is typically about a third or less, and may be about ¼ or ⅕. That is, where a set of drill collars weighs 36,000 to 50,000 lbs, the string may be held back such that perhaps only about 10,000 to 12,000 lbs bears on the bit.

Turning to FIG. 1a, a drill bit 20 includes a body 22 having a first end 24, a second end 26, and a wall 28 extending between ends 24 and 26. Drill bit 20 may be a drag bit, and may be a diamond drag bit. Common sizes of bit may include 6¼″ (159 mm), 7⅞″ (200 mm), 8½″ (not too common) and 8¾″ (222 mm), 9⅝″ (not as common), 12¼″, and some other much larger sizes. For the purposes of this description, the nominal 200 mm bit may be assumed. First end 24 may be designated as the forward, or leading end of drill bit 20, in the sense of being the end driven forward into the surrounding geological formation 25 that is to be bored during a drilling operation. Second end 26 faces in a generally opposed, or rearward direction to that of first end 24. Second end 26 may include a longitudinally rearwardly protruding portion or member which may be termed a shank 30, that may be externally threaded in a fashion for threading onto a downhole end of a drill string, e.g., it may have a standard tapered external screw thread such as a 3½″, 4″ or 4½ API regular tapered drill pipe thread. Wall 28 may be a peripheral or enclosing wall, and may have a generally circular cylindrical shape. Body 22 may be hollow, having an internal cavity 34 defined within, or bounded by, wall 28 between ends 24 and 26. Shank 30 may have an internal bore 32 providing a fluid communication passageway by which fluids, or quasi-fluids, such as drilling mud DM, may be conducted from a source of supply, down the drill string, and into cavity 34.

First end 24 may include a member 36 which may be in the nature of a plate 38, which itself may have a periphery conforming to the axially forwardmost margin of wall 28. In one embodiment, plate 38 may be a substantially planar, radially extending disc, which may be referred to as a lid 40 that is mounted to wall 28 by such means, for example, as a peripheral weld. It may be that, alternatively, bit body 22 is manufactured as a single piece, such as may be machined from solid, as described hereinbelow in the context of bit 220 of FIGS. 11a and 11b. Howsoever it may be, lid 40 (or the front or leading face portion of the bit body, as may be) may have mounted to it an array 42 of cutting members 44. The cutting members may extend out from lid 40, i.e., they may stand proud of lid 40 more generally, so as to protrude in the forward or axial direction. Array 42 may include such number of cutting members, or blades, as may be suitable. There may be four or more blades. In one embodiment there may be eight blades, in another embodiment six blades.

The cutting members 44 may include cutters, or cutting assemblies, or blades, of different types, however they may be termed. There may be large cutters, or cutting assemblies or blades, 46, and small cutters, or cutting assemblies or blades 48. These may be referred to, respectively, as primary and secondary blades. The cutting assemblies may tend to extend predominantly radially, but offset from the radii to which they are parallel. Cutting assemblies 46 and 48 may be arrayed about the first end of drill bit 20 in a generally alternating manner.

For example, a cutting assembly 46 may have a first end 50 radially proximate to the centerline CL of drill bit 20, at a first radius R₁, for example, and a second end 52 radially distant from centerline at a second distance R₂, for example. R₂ may be larger than R₃ the radially most distant portion of lid 40 (and of wall 28), such that a distal portion 54 of cutting assembly 46 may overhang the edge of lid 40. Distal portion 54 may extend axially rearwardly a first distance L₁, and may stand proud of (i.e., radially outwardly of) wall 28 a radial distance indicated as D₁. Cutting assembly 46 may be offset sideways from an adjacent radius, and may be mounted in a manner that extends generally or substantially parallel to that radius, such that the long axis of cutting assembly 46 does may not intersect the centerline axis of drill bit 20, but be offset from it by an offset distance D₂. It may also be that cutting assembly 46 has a generally rectangular footprint on lid 40, having a length L₂, and a cross-wise thickness T₁. Lid 40 may have a rebate or accommodation 56 formed therein to accommodate the base portion 58 of cutting assembly 46. Cutting assembly 46 may seat in accommodation 56, and be secured therein by a bonding or securing element or feature, such as being brazed or welded in place. To the extent that cutting assembly 46 may have a rake angle, α, it may be that the accommodation 56 may have the form of a slot having one or both sides canted at angle α from the perpendicular (i.e., the perpendicular being parallel to the centerline axis CL). Angle α may be such as to appear to present the blades on a backward slant so that the front face 55 of the blade meets lid 40 at an angle greater than 90 degrees, and the rear face 57 meets lid 40 at an acute angle. That is, the most axially distant portion of the blade is offset in a direction opposite to the direction of rotation of drill bit 20 more generally. The operational direction of rotation defines a forward (counter-clockwise in FIG. 1d) and rearward (clockwise in FIG. 1d) direction of rotation. Blades 46, 48 may be canted rearwardly at an angle of about 5° to 10° to the vertical (the central axis A of the drill bit 20 may be considered to be in a vertical orientation in a desired operating position).

Similarly, cutting assembly 48 may have a first end 60 radially proximate to centerline CL of drill bit 20, at a radius R₄, (which may be the same as R₁, or, as illustrated embodiment, somewhat larger than R₁) for example, and a second end 62 radially distant from centerline at a second distance R₅, for example. R5 may be larger than the radially most distant portion of lid 40 (and of wall 28), such that a distal portion 64 of cutting assembly 48 may overhang the edge of lid 40. Distal portion 64 may extend axially rearwardly a third distance L₃, and may stand proud of (i.e., radially outwardly of) wall 28 a radial distance indicated as D₃, which may be the same as D₁. Cutting assembly 48 may be offset sideways from an adjacent radius, and may be mounted in a manner that extends generally or substantially parallel to that radius, such that the long axis of cutting assembly 46 does may not intersect the centerline axis of drill bit 20, but be offset from it by an offset distance D₄. It may also be that cutting assembly 46 has a generally rectangular footprint on lid 40, having a length L₂, and a cross-wise thickness T₂. T₂ may be the same as T₁. Lid 40 may have a rebate or accommodation 66 formed therein to accommodate the base portion 68 of cutting assembly 48. Accommodation 66 may be a generally rectangular slot. The front and rear faces of cutting assembly 48 are indicated as 65 and 67 respectively. Cutting assembly 48 may seat in accommodation 66, and be secured therein by a bonding or securing element or feature, such as being brazed or welded in place. Cutting assembly 48 (and accommodation 66) may also be slanted backward in the manner described above.

Drill bit 20 may also include one or more flow modification members, or vanes, or flow restrictors, or obstructions, or chokes 80, such as may, in one embodiment, have the form of a skirt member 82 mounted in a location lying axially rearward of the overhanging end of, for example each cutting assembly 48, or which may, possibly, be formed integrally therewith. Skirt member 82 may be relatively narrow at the end adjacent cutter 48. Member 82 may have a first portion or face 84 that extends predominantly axially in line with the underside of the front face of cutting assembly 48, and a second portion or face 86 extending from the rear face of cutting assembly 48, and that extends less predominantly axially than does face 84. That is, face 86 extends in a direction having a significant non-axial component, as indicated by the helical slope on angle beta having an axial component L₈₆, and a circumferential component θ₈₆. It may be seen then, that member 82 diverges in the axially rearward direction such that the axially rearmost end 88 is broader than the lead-in at the axially foremost end.

Shank 30, lid 40 and blades 46, 48 may be manufactured separately from steel using a machine lathe type of construction and then welded into one unit, for example using electric arc welding. Shown in FIG. 1b, is a cylindrical central passage 90 in shank 30 that widens towards the lid 40 and supplies drilling fluid DM to the cutting end of the drill bit 20. Shank 30 is made from circular steel bar stock on a machine lathe. Passage 90 is drilled through shank 30. Shank 30 is a cylindrical body having a central axis CL indicated by the arrow A about which the drill bit 20 rotates.

To summarize, as shown in FIGS. 3 and 6, rectangular slots, or accommodations, 56, 66 are provided in the cutting end of lid 40 for blades 46, 48. Blades 46, 48 are secured in slots 56, 66, for example by welding. Blades 46, 48 and corresponding slots 56, 66 may have a front face 55, 65 that is parallel to but offset rearward from a radius extending outward from the central axis A. The amount of offset may be in the order of 2-4 mm. Blades 46, 48 may be provided with laminated steel backings 59, 69 welded to lid 40 to strengthen blades 46, 48 and to dampen vibration of blades 46, 48.

FIGS. 3 and 4 show lid 40 is shown separately from the shank 30 and blades 46 and 48. Lid 40 has an inside face 92, and an outside face 94, and fittings in the nature of vents or porting, which may include an array 96 of passages, conduits, bores, channels, holes, openings or apertures, however they may be termed, identified as item 98, permitting fluid communication therethrough from one side of the plate to the other, i.e., from the shank end, or side, of lid 40 to the cutting end, or side, of lid 40. These conduits or openings 98 may accommodate insert fittings in the nature of liners, or nozzles or the like, identified as nozzles 100. Nozzles 100 may be inserted in the openings 98. Nozzles 100 may be hardened tubes, such as may be made, for example, of tungsten carbide, and may tend to protect the steel of the lid 40 from excessive wear from drilling fluid. The underside face 92 of lid 40 (FIG. 4) in the area around nozzles 100 is coated with a tungsten carbide material to protect the area from erosion as the drilling fluid is pumped through the nozzles 100. Lid 40 may also be made from circular steel bar stock on a lathe. The under side face 92 of lid 40 may be milled to a diameter suitable for the intended use and the openings 98 are drilled through the lid for the nozzle inserts 100. In some embodiments, nozzles 100 may have a diameter of about ⅜ or 7/16 inches (roughly 10 or 11 mm), and the jets may have a mean velocity of about 150 to 200 ft/s, assuming six nozzles. Alternatively if a higher flow rate of mud at perhaps a lower pressure drop is desired, nozzles up to about 15 mm (roughly ⅝ inches) may be used. Alternatively, too, if a very high pressure drop is desired in the nozzles, and a high jet velocity, nozzles of as little as 7 or 8 mm (roughly 7/32 to 5/16 inches) may be used. It is not necessary that all of the nozzles be the same size.

Typically, there may be as many openings 98 as there are blades 46, 48 and the exit of each opening 98 in the cutting end face 94 may be located at, or adjacent to a radially inward end, be it 50 or 60, of a corresponding blade 46, 48, adjacent to the forward, or leading, face 55, 65 of the blade 46, 48. The openings 98 at a first radius r₁, which may be associated with cutting assemblies 48, may be oriented at an angle ψ to the central axis A. That angle may be greater than about 10 or 15°. For openings near the outside edge, if any, the angle may be as low as 5 deg. For openings 98 that may be closer to the central axis of drill bit 20, at r₂, for example, and such as may be associated with feeding drilling mud to the leading face of cutting assemblies 46, that angle ψ may be greater than 30°. In each case, the nozzle may be angled or directed so that fluid exiting the nozzles 100 flows between adjacent blades 46, 48. That is, the angled nozzle has an axial component of direction through the thickness of the plate, and has a radial component of direction away from centerline CL. It may also have a circumferential component of direction. The greater the angle ψ of an opening 98, the more the fluid is directed between the corresponding blades 46, 48. In some embodiments, it may be that the nearer the opening 98 is to the central axis CL of the drill bit, the greater is the angle of the opening to the central axis. Openings 98 may be drilled through the lid 40 after it has been machined into the general shape shown in FIGS. 3 and 4. Use of a lid 40 may tend to facilitates fabrication of nozzles 100 having a high angle (i.e., large ψ) as opposed to a one piece design, in which it may be more difficult to make a high angle nozzle. Nozzles 100 provide a flow path, or path of fluid communication for drilling fluid pumped through the central passage or bore 32 of the shank 30. The nozzles 100 may be provided in different sizes, such as, for example, 10 mm for the primary blades of cutting assemblies 46 and 7.5 mm for the secondary blades of cutting assemblies 48. The body of drill bit 20, including cavity 34 may tend to function in effect as a distribution manifold whence a supply of fluid, such as drilling mud DM, is conveyed through nozzles 100 and delivered to the junk slots between the various adjacent blade pairs.

Referring to FIGS. 5a to 5d, a blade 46 (or 48) may be made from steel flat bar stock of a suitable width W₄₆, (or W₄₈) thickness t₄₆ (or t₄₈) and length L₄₆ (or L₄₈). Multiple bore or holes 102, the number depending on the required number of cutter teeth, are drilled in the bar stock from which blade 46 (or 48) is to be made, and the body, or major portion, of blade 46 (or 48) is then cut along the line B in FIG. 5c to yield cutter holes, or accommodations, or seats 104. The bores may be blind bores, leaving a solid backing shoulder, abutment or wall 106 Polycrystalline diamond cutters 108 (i.e., the teeth) are inserted in the holes, or seats 104 (32) and soldered in place. Blade 46 may be given a wear coating such as a tungsten carbide or hard metal coating to provide protection from erosion. The cutters 108 are shown in FIGS. 1, 5a to 5c and 6 as fully penetrating the blades, but in practice there will be a small amount of steel left behind the cutters 108, as shown in FIG. 5d.

Referring to FIGS. 5eand 5f, in an alternate embodiment, cutting assemblies 110, 112 may be used in place of cutting assemblies 46, 48. Cutting assemblies 110, 112 may be formed from powdered metal. The powdered metal parts may have substantially the same final shape as assemblies 46 and 48 respectively, and may be mounted in the accommodations in lid 40 in the same manner, as by brazing or welding. When worn out, or broken, or otherwise in need of replacement, cutting assemblies 110 and 112 (and 46 and 48) can be removed, and new (or in some instances possibly refurbished) cutting members or cutting assemblies may be installed in their place. Cutting assemblies 110, 112 may be formed of hard compositions particularly suited for use as cutting blades. Those compositions may include tungsten carbide, nickel carbide or like materials. Further, diamond or tungsten carbide elements may be embedded in the powdered metal parts at the time of fabrication. The powder metal parts may be relatively high compaction density parts, such that they are near net size parts as manufactured, such as may tend not to require further finishing or machining before installation in the accommodations of lid 40. The powder metal parts may be formed in a graphite mold, and sintered to yield near net size parts. The finished assemblies may be inserted in the accommodations in lid 40, and brazed in place. The powdered metals may be provided by companies such as Deloro Stellite. These assemblies, like those of FIGS. 5a to 5d, may be removed and replaced when worn by melting the brazing and extracting the part. These powdered metal blades may have a Rockwell C hardness of more than 45, and may have a hardness of 50, 60 or possibly higher. They may tend to be resistant to wear and erosion from drilling mud and from formation cuttings and fines.

As seen in FIG. 1a, junk slots 120, 122 are formed between each pair of adjacent blades 46, 48 (or 110, 112, as may be). Each blade 46, 48 (or 110, 112) separates adjacent junk slots 120, 122. Junk slots 120, 122 alternate in pairs around the cutting end of drill bit 20. Each pair of junk slots 120, 122 may includes an impeded junk slot, such as slot 122 that may tend to have a higher resistance to fluid flow than the corresponding unimpeded junk slot 120. In each case, there is an intervening blade 46 (or 110, as may be) between the pair of junk slots 120, 122. In operation, the higher resistance to flow in the more impeded junk slot 122 of each pair of junk slots may tend to encourage drilling fluid from junk slot 122 to migrate into the adjacent junk slot 120 having lower resistance to flow. Drilling fluid exiting the nozzles 100 may then tend to be forced, or urged, by the resistance of the junk slots 122 across the intervening blade 46 and between the cutters, or cutting teeth 108 of the intervening blade 46. The drilling fluid passes across the intervening blade through openings created by previous cutters. This may be encouraged offsetting and overlapping the cutters, or cutting teeth 108 in the radial direction on succeeding blades. The amount of offset and overlap may be varied. Increasing overlap may tend to create a more aggressive cutting action (i.e., potentially more removal of material to be cut per revolution of the bit), at the expense of decreasing the size of the flow path between the cutters. Thus, for cutters of radius R_c, the cutters on one blade may be spaced (i.e., radially offset) by R_c/2 and the centers of cutters, while having the same spacing, may be phase shifted on succeeding blades (in the direction of rotation, the following blade) by, for example, a distance of 3R_c/4. When the blades 46, 48 alternate between primary blades 46 and secondary blades 48, the primary blades 46 are the intervening blades.

The higher resistance of the junk slots 122 may be caused by a variety of means. For example, the resistance may be caused by a restriction in the junk slot 122, such as an enlargement or extension of a secondary blade 48 rearward, such as diverging skirt member 82. The extension may sweep circumferentially toward the intervening or primary blade 46 as shown in FIG. 1a, and so tend to choke the axially rearwardly extending portion of the flow path. The extension may be machined from a steel flat bar stock and welded to the outer periphery of the body, 22, including wall 28, shank 30 and lid 40. The extension may be shaped to be continuous with the blade 48. The radially outward surface of the extension may be fluted in conventional fashion for a stabilizer.

As seen in FIG. 1a, the blades 46, 48 extend axially forward of the cutting end 24 to engage an earth (i.e., geological, or rock) formation during drilling. Blades 46,48 may also extend radially outward from the cutting end 24 and may extend axially rearward along the outer periphery of the drill bit body to form stabilizers. The blades 46, 48 may include blades extensions that extend axially rearward for different distances. In one embodiment the blades may alternate between longer extensions of blades 48 and shorter extensions of blades 46. As seen in FIG. 3, the blades 46, 48 and the corresponding slots 120, 122 are also oriented on the cutting end 24 of the drill bit body such that a linear extension of the blade passes behind the central axis in the direction of rotation in operation, as previously described. The linear extension may be part of the blade itself or an extrapolation of a blade that terminates inwardly of the central axis. Such off-center orientation of the blades, where the blades do not all point towards the same center, assists in stabilizing the drill bit.

As the cutters 108 rotate around the central axis A, and cut into an earth formation, they leave gouges in the formation. Cutters 108 on succeeding blades deepen the gouge. Cutters 108 on succeeding blades may overlap, and typically, gouges created by cutters of succeeding blades may lie midway between the gouges of the preceding blades. In the embodiment shown in FIG. 9, the cutters 108 in succeeding blades preferably differentially overlap cutters in preceding blades in the direction of rotation such that a cutter on a succeeding blade overlaps more of one, outer, cutter, on a preceding blade than it overlaps an adjacent, inner, cutter on a preceding cutter. The overlap of the outer cutter may be more than 25% but less than 100%, for example 60-75% of the outer cutter. In FIG. 9, cutters 108 are in a leading or preceding blade in the direction of rotation. Cutters 108 are in the following or succeeding blade 46. The cross-hatched areas 124 indicates the areas being cut by the following blades. The hatched area 126 in the path of the cutters 108 shows where cuttings from the drilling activity of the following blades may slide sideways away from the cutters and be cleared from the cutting area. With the overlap system described here, the cutters of a preceding blade cut a slot in the formation through which fluids can pass during cutting by the cutters of a succeeding blade.

The cutters, which may be cylindrical or conical objects having an axis of rotation, are oriented on the respective blades with their axes of rotation tangential to a circle centered on the central axis A of the drill bit. The cutters 108 are also preferably oriented on the respective blades with their cutting faces parallel to the forward faces of the blades, or may be canted outward from the center of rotation by a side rake of 4°-11°. Inner cutters may have a side rake of 6-11°, while cutters at the gauge may have a side rake of 6°. With the blades behind center and canted rearward, and the cutters on circle, vibration of the blades during use may tend to sweep particles away from the cutting face and help prevent balling. It is preferred to keep the number of cutters 108 on the periphery or gauge of the drill bit to a minimum required to make a good gauge in the hole, with the cutters 108 concentrated on the forward cutting end 24. For example, for given gauge there need only be a single cutter set at the outside edge of each of the primary blades to produce that gauge. There need not be multiple cutters 108 running axially rearward along the outer periphery of the blades.

Once the components are manufactured they are assembled. The lid 40 is welded to the wall 28 and the weld is ground smooth. The blades 46, 48 are set in the rectangular slots 56, 66 in the top of the lid and welded or brazed in place as shown in FIG. 6.

With the design of the drill bit shown in FIGS. 1a-5d, a greater angle can be achieved on the nozzle orientation because the nozzle holes 98 are drilled from the underside of the lid 40 before it is welded to the wall 28. The nozzle orientation may be important to the cleaning characteristics of PDC bits. If the nozzles 100 can be oriented at the correct angle, cleaning may tend to be enhanced, thus the bit may tend to drill faster and cutter wear life may tend to be extended. In addition, with the method of manufacture shown in FIG. 6, the blades 46, 48 may tend to be more easily replaced than otherwise, unlike blades having a matrix body or a one piece steel body bit. When the blade of a one piece steel or matrix body bit is damaged, the bit may be un-repairable, and the entire bit may have to be replaced. To remove one of the blades 46, 48, the weld or braze is cut using a grinder, the blade is heated up and pops out or is easily pulled out. Use of a lid 40 allows more blades to be used.

As shown in FIG. 1a, the blades 46, 48 may be canted back away from the cutting structure. This may tend to improve cleaning and the removal of cutting. The faster cuttings can be moved away from the blades the higher the rate of penetration (ROP) will be. This may tend to discourage or prevents bit balling. Moving the cuttings away from the blades quickly may also tend to prevent regrinding of the cuttings, which might otherwise tend to increase the temperature of the cutters. Increased temperature can cause premature cutter failure.

The flow restrictor 80, which may also tend to act as a stabilizer, may create a pressure differential between the primary and secondary blades 46, 48 tending to encourage more efficient cuttings removal. The flow restrictor may tend actually to urge or force flow across the blades 46 between the cutters 108. That is, the cuttings are forced between the spaces in the cutters 108. This may work better than trying to get all the cuttings to leave the bit face via the junk slot area. The higher resistance may be achieved by other means such as putting the following secondary blades closer to the primary blades that are mounted ahead of them in the direction of rotation. This may tend to create a higher pressure in the narrow passage between the primary and secondary blades. More generally, the concept is to force the cuttings to crossflow between the cutters 108 on every second blade.

Explained somewhat differently, it may be imagined that drill bit 20 and the surrounding geological formation into which drill bit 20 is being driven cooperate to form a set of passages or galleries through which drilling mud is forced to pass, and, in so passing, to carry away material of the geological formation i.e., cuttings that have been dislodged by the teeth of the cutters as drill bit 20 rotates. The size of these passages will be determined by the area swept by the blades. For example, in the longitudinal direction, drill bit 20 will tend to cut a passage of essentially circular cross-section, whose diameter is that corresponding to the outside radius of the portions of blades 46 and 48 (or 110 and 112). The result may tend to be that, when viewed in the axial direction, there will be an annular zone 130 between the outside radius of wall 28 generally, and the outside radius of the cutting members. This annular zone will be divided into a plurality of passages by the blade extensions, and axially extending skirts. Similarly, there will be a swept zone axially forward of plate 38, corresponding to the space between plate 38 and the geological formation, the height, or axial extent, of that zone being determined by the profiles of the cutters. That zone may tend to have the shape, generally, or a circular disc. The zone is subdivided into a series of predominantly radially extending passages by the partitions defined by cutters 46 and 48 (or 110, 112, as may be). Each passage may be thought of as having a leading partition or wall, such as a secondary cutting assembly 48, and a trailing partition or wall, such as may be defined by a primary cutting assembly 46. In the area near the center of the drill bit, there may tend to be an open space. Where the passageway is, in a fluid flow sense, large, the resistance to flow may tend to be lower than in another passageway that is, in a fluid flow sense, small or constricted. It may be understood that the cross section of a flow passage, at any radial location in the second zone will have four sides, namely the back wall of the leading blade (having a length or height H₁), the front wall of the trailing blade (having a length or height H₂), the radial arc between the front and rear walls on the surface of the lid (having an arc length S₁), and an opposed arc in the formation that will be of roughly identical length to the radial arc side. The periphery of this passage at this location is then P=H₁+H₂+2S₁. To the extent that H₁ and H₂ may tend to be substantially equal, for the purposes of approximation this may simplify to 2(H₁+S₁). The hydraulic diameter D_H of any of the passages may be defined as 4A/P where A is the area of the cross section, and P is the perimeter. In this instance A is, roughly, the product H₁×S₁. Similarly, in the axial direction, each flow passage will tend to be four sided, with two sides being defined by the respective outer radii of peripheral wall 28, S₂₈, the corresponding arc between the sweeping blades at their outermost radius S₂₈+epsilon, and two sides being defined by the radial length of the extension, epsilon, i.e., D₁ or D₃, as may be. A similar hydraulic diameter can be defined for these passages. Each radially extending passage portion 132 is in fluid communication with an axially extending portion 134, yielding an overall flow path from the discharge of the drilling mud delivery nozzles 100 to the axially rearward end of the respective axially extending passage portion. To the extent that one passage has an overall mean hydraulic diameter less than another, it may tend to present a higher resistance to overall flow, and therefore a greater tendency for fluid to be urged from that flow path to a path of lesser resistance. The broadening of the extension skirt 82 presents such a flow constriction as may tend to reduce the mean hydraulic diameter of the passage, as a whole, and to increase the overall flow resistance of the passage as compared to the adjacent non-obstructed passage.

At the same time as these two portion passages (radial portion 132 across end face, axial portion 134 along side wall 28) may be thought of as drilling mud conduits, the first portion (i.e., the predominantly radially extending portion 132) has an array of outlet ports communicating with the adjacent passageway between the next two blades, those outlet ports being the portions of the gouged tooth grooves formed in the formation by the teeth of the preceding blade that are not overlapped by the profiles of the teeth of the following blade. In effect, then, the radial portions of the drilling mud flow passages are also flow manifolds, having an array of radially spaced ports through which drilling mud may be urged to pass into the next following slot.

Increased resistance may also be obtained by forming a choking aperture, or throat, such as that indicated at the narrowing location between the skirt of blade assembly 46 and the axially extending portion of blade assembly 46, that throat or gap being identified as ‘G’. Further still, the increased resistance may be obtained by making the high resistance channel shallower, as by building up the radially outermost portion of the front face of lid 40 in the high resistance channel, or by building up sidewall 28 in the region of the second portion of the high resistance channel. The first portion of the high resistance channel, namely the predominantly radially extending portion, may be of comparable, or less, resistance to fluid flow than the corresponding first or radial portion of the lower resistance path, but that the second, or axial portion may be of substantially higher resistance than the corresponding second portion of the lower resistance path, such as may tend to develop a greater tendency for the drilling fluid to want to “leak” from the first portion of the high resistance path to the first portion of the low resistance path through the ports or passageways offered by the offset gouges. In one embodiment, the hydraulic diameter of the narrowest portion, or throat, of the high resistance path may be less than ¾ of the hydraulic diameter of the corresponding portion of the low resistance path. In another embodiment, it may be less than ⅔.

As shown in FIGS. 5d and 7, during blade construction small diameter holes (conduits) 140 may be drilled from the base of the blades 46, 48 (or cast in blades such as 110, 112)and terminate in the tops of the blades 46, 48 below the cutters 108 but in heat conducting proximity to the cutters 108, for example 1-4 millimeters away. “Heat conducting proximity” means sufficiently close to provide a cooling effect to the cutters 108. The hollow conduits 140 may then be filled with a material with high heat conductivity, at least higher than the heat conductivity of the blade material, such as copper. For example, the blade material may have a thermal conductivity of less than 10 W/MK. The material contained within the internal bores may have a thermal conductivity that is greater than 20 W/MK, and may be higher than 50 W/MK. To the extent that the material may be copper, the thermal conductivity may be more than 300 W/MK (as much as 396 W/MK for pure copper). This high conductivity conduit or heat transfer path may provide a route by which heat may more easily be carried away from the PDC cutters 108 and which may aid in dissipating the heat into the body of the surrounding blade more generally. The ends of the heat conducting conduits 140 near the cutters 108 may have small holes, not filled with the high heat conductivity material, drilled through the blade from the cutter to the metal in the conduit. FIG. 10 also shows a backing part 142 of the blade 46 behind the cutter 108, and the hardened cutting surface 144 of the cutter. A softer metal such as brass 146 may be placed between the cutter 108 and the backing part 142 to help reduce cutter vibration, as shown in FIG. 10.

In the past, drill bits have tended to be essentially solid, and quite heavy. This might be expected in the industry, since drill bits are expected to operate under what might generally be considered fairly abusive operating conditions. The present inventors believe that it may be advantageous for the drill bit to be less solid. First, it may be that by employing the hollow fabricated lid-and sidewall or single piece machined bit body construction described herein, it may be possible to provide drilling mud jets, i.e., the nozzles 100, that are inclined at a greater angle, and hence to facilitate mud flow in the direction in the first, or predominantly radial direction, while the flow path within the nozzle remains relatively short, and may tend to approximate an aperture, or vena contracta, rather than a long pipe in which a fully developed, high resistance flow regime may occur. Second, the employment of a hollow bit structure may tend to provide a resonating chamber or vibration chamber, or plenum within the bit. Drilling mud may be considered an incompressible fluid that may tend to transmit pressure waves. As noted above, both duplex and triplex pumps tend to yield a vibrating or pulsating effect drilling fluid, an effect that may be more pronounced when duplex pumps are used. It appears that this vibration may tend to enhance drilling when the drill bit is predominantly a hollow chamber.

Consider the drill bit 220 of FIGS. 11a and 11b. Drill bit 220 includes a body 222 having a first end 224, a second end 226, and a wall 228 extending between ends 224 and 226. Drill bit 220 may be a drag bit, and may be a diamond drag bit. In this embodiment the drill bit body 222 may be a one piece body that may be machined from a solid block, or billet, or bar. First end 224 may be designated as the forward, or leading end of drill bit 220. Second end 226 faces in a generally opposed, or rearward direction to that of first end 224. Second end 226 may include a longitudinally rearwardly protruding portion or member, namely a shank 230. Shank 230 may be externally threaded in a fashion for threading onto a downhole end of a drill string, e.g., it may have a standard tapered external screw thread such as a 3½″, 4″ or 4½″ API regular tapered drill pipe thread. Wall 228 may be a peripheral or enclosing wall, and may have a generally circular cylindrical shape. Body 222 may be hollow, having an internal cavity 234 defined within, or bounded by, wall 228 between ends 224 and 226. Shank 230 may have an internal bore 232 providing a fluid communication passageway by which fluids, or quasi-fluids, such as drilling mud DM, may be conducted from a source of supply, down the drill string, and into cavity 234. First end 224 may include a leading face member 236 corresponding to member 36, described above. Member 236 may have mounted to it an array 242 of cutting members 244, which may be such as the cutting member 46, 48, 110, 112 etc., as described in the foregoing embodiments. There may be four or more blades. In one embodiment there may be eight blades, in another embodiment six blades. In the embodiment of FIGS. 11a and 11b, half of the blades may have axially rearwardly running extensions that run along wall 228 to a point near of at its most axially rearward end. That is, a distal portion may extend axially rearwardly, and may stand proud of (i.e., radially outwardly of) wall 28 by radial distance indicated as D₁.

Shank 230, and body 222 may be made separately and then welded into one unit. The rearward face or wall 246 of body 222 may include a female threaded bore 248. Shank 230 may have a first end 250 for introducing into cavity 234 of body 222, and a second end 252 having the tapered external thread 254 for mating connection with the drill string. First end 250 may have an externally or male threaded waist or mid-section for engagement with threaded bore 248. Second end 252 may include a shoulder 256 to seat against the rearward face of body 222. When seated, the two parts may be welded peripherally, as at 258. The front end, or first end 250 may include an optional forwardly protruding nose, or nipple or stub, 260, which need not be externally threaded, that may be smaller in diameter than the threaded waist. Shank 230 has a central passage 262 through which cutting fluid, such as drilling mud, is delivered to cavity 234 and its various outlets, namely the array of nozzles 270. This passage may have a comparable diameter to the inside of the drill string more generally. The outlet end of the nipple or stub 260, stands rearwardly shy or, i.e., clear of, the inward side of the front wall, by some distance, such as an inch or two. Nozzles 270 may be taken as being substantially the same in number, size, location and orientation, etc., as nozzles 100 described above. As can be seen, drill bit 220 then has an internal chamber, or cavity 234 of significantly greater diameter than the drill string internal bore that is filled by the lubricating fluid, most typically drilling mud. This broadening may tend to be more than a 50% increase in diameter, and in some instances be over a 100% increase in diameter. Inasmuch as there is a pressure drop across the manifold outlet orifices, namely nozzles 270, in operation there may be expected to be a significant pressure differential between chamber 234 and the external cavity of the end of the well bore about drill bit 220.

Wall 228 may have a thickness t₂₂₈, and a span length, L₂₂₈ between the front plate 236 and rear wall 246. Front plate 236 may have a substantial thickness—in one embodiment perhaps 1¼″ to 2″, or perhaps about 1⅝″ Thickness t₂₂₈ may be less than 1″. For example, wall 228 may be in the range of about 5/16″. to about ⅝″ thick, and in one embodiment may be about 3/8″ to 7/16″ thick. The inside diameter phi₂₃₄ of wall 228 may be between about 4″ and 6″, and in one embodiment is about 5¼″. The outside diameter may be between about 4½″ and 7″. Put differently, t₂₂₈ may be less than 1″, and may be less than ⅛ of the outside diameter of wall 228, or, differently, may be less than ⅙ of phi₂₃₄. Taken as a ratio of wall thickness t₂₂₈ to internal chamber diameter phi₂₃₄, in some embodiments the wall thickness may be in the range of about 6% to about 10% of phi₂₃₄, and in one embodiment may be between about 7% to about 8½%. Length L₂₂₈ may be in the range of more than about ½ or ⅔ of the internal diameter phi₂₃₄ of chamber 234, and may be in the range or ¾ or more, and up to about 1½ to about 2 or 2½ times that diameter. The parameter EA₂₂₈/L₂₂₈ may lie in the range of about 2.0×10⁷ to about 8.0×10⁷ lb/inch, and, in one embodiment, may be about 4.5×10⁷ lb/in. (+/−20%), where E is the Young's modulus of the wall material (e.g., steel), A₂₂₈ is the cross-sectional area of wall 228 and L₂₂₈ is the length of wall 228 as indicated. The relationship of wall thickness, t₂₂₈ to wall length L₂₂₈ may be in the range of less than ⅕, and in some embodiments may be less than about 12%, and in some embodiments may be less than about 10%. In one embodiment t₂₂₈ is 5/16″, phi₂₃₄ is 3⅜″, L₂₂₈ is about 3″, R₃ is 4¼″, D₁ is 1″ and R₅ is 6¼″. In other embodiments, t₂₂₈ is ⅜″, phi₂₃₄ is 5^1/4″, L₂₂₈ is in the range of about 4″ to about 6″ or 8″ (and may, specifically be about 4″, 5″ or 6″, R₃ is 6″, D₁ is 1″ and R₅ is 8″. In another embodiment, t₂₂₈ is ^1/2″, phi₂₃₄ is 4^1/4″, L₂₂₈ is in the range of about 6″ or 8″, R₃ is 5¼″, D₁ is 1″ and R5 is 7¼″. In another embodiment, R3 may be 5¼, D1 may be ⅜ inches, wall thickness may be 7/16, plenum length would be 6″. In another embodiment, t₂₂₈ is 7/16″, phi₂₃₄ is 4⅜″, L₂₂₈ is in the range of about 6″ or 8″, R₃ is 5¼″, D₁ is 1⅜″ and R₅ is 7⅞″.

Drill bit 220 may also include one or more flow modification members, or vanes, or flow restrictors, or obstructions, or chokes similar to choke 80, described above. Alternatively, some of the vanes or blades, in some embodiments half of them, being every second blade, may include a rearwardly extending member, such as may be termed a blade or wall or fence or vane 266 that is generally straight, that may run predominantly axially, and that may be roughly the same thickness as the thickness of blades 46 or 48 generally. Vane 262 may extend over a portion, or even substantially the entire length of wall 228 more generally. In some embodiments, vane 266 may be fillet welded along its entire axial length to wall 228, and may function as a stiffener thereof. In other embodiments, a relief 264 may be formed between a portion, e.g., a central portion, of vane 266 and wall 228, such that wall 228 may deflect radially in the space of gap so created. This gap need not be overly large in the radial direction, and may be of the order of 0.020″ or 0.030″, for example. The axial length of the gap, relief 264, may correspond to the inside length of sidewall 228, previously identified as L₂₂₈.

Member 236 has an inside face 272, an outside face 274, and fittings in the nature of vents or porting, which may include an array 276 of passages, conduits, bores, channels, holes, openings or apertures, however they may be termed, identified as item 278, permitting fluid communication therethrough from one side of the plate to the other, i.e., from the shank end, or side, of member 236 to the cutting end, or side, of member 236. These conduits or openings 278 may accommodate insert fittings in the nature of liners, or nozzles or the like, identified as nozzles 270. Nozzles 270 may be inserted in the openings 278. Nozzles 270 may be hardened tubes, such as may be made, for example, of tungsten carbide, and may tend to protect the steel of the member 236 from excessive wear from drilling fluid. The underside face 272 of member 236 in the area around nozzles 270 is coated with a tungsten carbide material to protect the area from erosion as the drilling fluid is pumped through the nozzles 270. Further, the inner end of nozzles 270 may be formed in a re-entrant manner, i.e., the end of the tube protrudes into the body of the chamber somewhat proud of face 272. This distance may be quite modest, e.g., ⅛ or ¼ of an inch. Nozzles 270 may be angled in the same manner as nozzles 100 to urge the cutting fluid in a direction having a radial component, and perhaps quite strongly so.

The bit, be it 20 or 220, in whichever variation or embodiment or combination of the various features described above, may be used in circumstances where the area of the face A_f, multiplied by the gauge pressure of the drilling fluid yields a force that is greater than the nominal hold-down force maintaining bit 220 (or 20) against the bottom of the borehole. That is, where the weight of the drill collars is, for example, 36,000 to 48,000 lbs, and the hold back at the drill table is such as to permit 10,000 to 12,000 of that weight to bear on the drill bit, the internal face area of chamber 234 is about 20 square inches, and the running pressure P₂₂₀ of the bit, (measured at the outlet of the drilling mud pump) may be from about 400-500 psi or more (a range of 800-1000 psi may be used, and possibly up to about 1500 psi), the product of the running pressure multiplied by the face area is 20,000 lbs, and is substantially greater than the 10,000 to 12,000 lbs holding the bit down. In some embodiments it may be about 50% greater, or more. In some operating conditions, the hold down force is less than ⅓ of the weight of the drill collars, and the product of the running pressure and the internal face area is greater than the hold down force. In some operating conditions it may be about ¼ of the hold down force. In some embodiment it is more than 50% greater. In some embodiments the value (EA/L) for the drill string may lie in the range of about 800 to 4000 lbs/inch, where E is young's modulus, A is the cross sectional area of the drill string wall, and L is the length of the drill string. The axial first mode longitudinal natural frequency (W_n=[k/M]^1/2) of the drill string and drill collar combination may lie in the range of about 50 radians/second, or less than about 8 Hz. In one embodiment it may be 3-6 Hz, and in one condition it may be about 4 Hz.

In operation, bit 20, or 220, as may be, is provided for drilling a well bore, which may be an 8 inch bore (the values herein may be adjusted in proportion if otherwise). These bits have an enlarged chamber between the bit face and the shank. The chamber may be a resonating chamber. The chamber may have an internal diameter substantially larger (i.e., 50% greater or more) than the drill string internal diameter, (e.g., in absolute terms, more than 3″ in diameter). The chamber may be surrounded by, or be defined within, a circumferentially extending external wall. The wall thickness may be less than the wall thickness of the drill string pipe, (e.g., in absolute terms less than 1″ thick). Cutting fluid is fed to the bit through the drill string. The cutting fluid enters at the shank and exits at a series of flow nozzles or jets, that may be oriented such that the fluid of the jets may tend to urge cuttings out of the junk slots of the bit, and away from the drill face. The source of the cutting fluid may be pulsating, which may also cause pulsations at the jets. The drill bit, including the circumferential wall of the chamber, may be loaded in axial compression by the hold down force, which, for an approximately 8 inch (i.e., 7 ⅞″ or 200 mm) well bore, may be of the order of 10,000 or 12,000 lbs. The drill bit may also be loaded in torsion by the imposed angular rotation of the drill string, plus any rotation due to a mud motor. At the same time the drill bit body may be subject to a fluctuating, i.e., time varying, pulsations. The pulsations may impose in the circumferential wall one, or two of, or all, of (a) a hoop stress, (b) an axial stress; and (c) a bending stress. The axial stress in the circumferential wall may be a reversing stress (i.e., is sometime in compression and sometimes in tension), and may have a non-zero mean. That is, the mean stress in the axial direction may be compressive. The time varying loading of the chamber walls may be result in a time varying loading being transmitted to the cutter teeth, and hence to the geological formation in which the drilling is to occur.

Various embodiments of the invention have now been described in detail. Since changes in, or additions to, the above-described embodiments may be made without departing from the nature, spirit or scope of the invention, the invention is not to be limited to those details but only by the appended claims.

Claims

1. A drill bit having a central axis of rotation, and a direction of rotation, said drill bit comprising:

a body having a driven end for connection to a drive train operable to rotate said bit, and a cutting end axially distant from said driven end;

said cutting end having an array of cutting members mounted thereto;

said array including members defining at least first and second junk slots therebetween;

said first junk slot being at least part of a first flow path for cutting fluid;

said second junk slot being at least part of a second flow path for cutting fluid;

a first of said cutting members of said array defining a partition between said first and second flow paths;

each of said first and second paths for cutting fluid having an entrance at which to introduce cutting fluid, and an exit at which to discharge cutting fluid; and

at least a portion of said second flow path being constricted as compared to said first flow path.

2. A drill bit as claimed in claim 1 wherein said second flow path includes a constriction having a hydraulic diameter that is less than ¾ of a hydraulic diameter of a corresponding portion of said first flow path.

3. A drill bit as claimed in claim 1 wherein said second flow path includes a first, predominantly radial portion, and a second, predominantly axial portion, and said portion of said flow path that is constricted forms at least part of said predominantly axial portion of said second flow path.

4. A drill bit as claimed in claim 1 wherein:

said first flow path has a first, predominantly radial portion having a first resistance to flow R1, and said a second, predominantly axial portion having a second resistance to flow R2;

said second flow path has a first, predominantly radial portion having a third resistance to flow R3, and said a second, predominantly axial portion having a fourth resistance to flow R4; and

R1/R2 is greater than R3/R4.

5. A drill bit as claimed in claim 1 wherein said first of said cutting members of said array defines a leaky partition between said first and second flow paths.

6. A drill bit as claimed in claim 1 wherein said first of said cutting members extends predominantly radially and has a toothed profile.

7. A drill bit as claimed in claim 1 wherein said first of said cutting members extends predominantly radially and has a first toothed profile, a second of said cutting members extends predominantly radially, and has a second tooth profile, at least one of said first and second toothed profiles including at least one axially protruding asperity radially offset from any asperity of the other of said toothed profiles.

8. A drill bit as claimed in claim 7 wherein said first and second tooth profiles are radially phase shifted.

9. A drill bit as claimed in claim 1 where said array of cutting members includes at least one member formed of sintered powder metal.

10. The drill bit of claim 9 wherein said sintered powder metal cutting member included a polycrystalline diamond insert.

11. The drill bit of claim 1 wherein said second junk slot has a flow restriction mounted therewithin.

12. The drill bit of claim 11 in which the restrictions include a blade extension.

13. The drill bit of claim 11 in which each restriction comprises an extension of a secondary blade.

14. The drill bit of claim 11 in which each restriction of a pair of junk slots sweeps circumferentially under the intervening blade.

15. A drill bit as claimed in claim 1 wherein said drill bit has a hollow head through which cutting fluid may be supplied.

16. The drill bit of claim 15 wherein said hollow end of said drill bit has a lid.

17. The drill bit of claim 16 wherein said lid has porting to permit the transport of cutting fluid therethrough.

18. The drill bit of claim 17 wherein said porting includes ports angled in an orientation having a radial component of direction.

19. The drill bit of claim 1 in which the drill bit body has a rotational axis, and nozzles oriented at an angle greater than 15° to the rotational axis and directed to feed drilling fluid between the members of the array.

20. The drill bit of claim 1 wherein the drill bit body includes a cylindrical sidewall capped by an end lid welded thereto, said end lid being multiply ported whereby said end lid defined a drill fluid delivery manifold.

21. A drill bit for drilling well bores in geological formations, said drill bit comprising a drill bit body, the drill bit body having a first end and a second end, the first end of the drill bit body having a cutting face and cutting members mounted thereto, the second end facing away from the first end and providing a member to which a shank for engagement to a drill string can be mounted, the drill bit body having a peripheral wall extending between the first and second ends, the peripheral wall having a thickness of less than 1 inch, and a chamber defined within said bit body, said chamber having a diameter of at least 3 inches, the chamber having an inlet of a diameter less than 3 inches through which drilling mud may flow into the bit body, and the bit body having ports by which drilling fluid may exit the bit body.

22. The drill bit of claim 21 wherein said chamber is a resonating chamber.

23. The drill bit of claim 21 wherein said bit body has a wall thickness of less than 15% of the diameter of the chamber.

24. The drill bit of claim 21 wherein said wall thickness is up to ½″.

25. The drill bit of claim 24 wherein said wall thickness is at least 5/16″.

26. The drill bit of claim 21 wherein said chamber has an internal cross sectional area Af, said wall has a cross sectional area Aw, and a ratio of Af:Aw lies in the range of greater than 4:1

27. The drill bit of claim 21 wherein said chamber has a length, that length being in the range of at least ⅔ as great as the chamber diameter.

28. The drill bit of claim 21 wherein said chamber has a length, that length being in the range of ¾ to 2 times the diameter of the chamber.

29. The drill bit of claim 21 wherein said drill bit has vane members extending predominantly axially externally of said peripheral wall, and at least one of said vane members is relieved to accommodate radial flexing of said peripheral wall.

30. The combination of the drill bit of claim 21 and the shank, said shank being mounted to the drill bit body, the combination having at least one of the following features:

(a) the shank having a re-entrant nose; and

(b) said ports have nozzles mounted therein, and at least one of said nozzles has a re-entrant end extending into said chamber.

31. A drill string combination comprising:

a pulsating source of drilling fluid;

drill pipe sections for connection together and for connection to said source of drilling fluid;

drill collars for connection to said drill pipe sections;

a drill bit for mounting below said drill collars;

said drill bit having a first end for cutting the well bore, and a second end having a shank for connecting the drill bit to the drill string below the drill collars;

a tensioning device for holding back a portion of the weight of the drill collars;

said drill pipe section having an internal diameter;

said drill bit having a chamber therein between said first and second ends, said chamber having a diameter greater than said drill pipe section;

said chamber being surrounded by a peripheral wall, said peripheral wall having a wall thickness of less than 1″, and said chamber having a length at least ⅔ as great as the diameter of the chamber; and

said chamber having an inlet through which drilling mud can enter said chamber, and an outlet through which drilling mud may be directed to remove cuttings.

32. The drill string combination of claim 31 wherein said combination includes between 30,000 lbs and 50,000 lbs of drill collars.

33. The drill string combination of claim 31 wherein said drill bit includes at least one of the following features:

(a) said wall thickness is in the range of ¼ to ½ inches;

(b) said wall thickness is in the range of 5/16″. to 7/16″;

(c) said wall thickness is in the range of 5% to 15% of said diameter;

(d) said wall thickness is in the range of 6% to 10% of said diameter

(e) said wall has a cross sectional area Aw, and said chamber has a cross-sectional area Af, and Aw lies in the range of less than 25% of Af;

(f) said chamber has a length, and said thickness is less than ⅕ of said length;

(g) said chamber has a length and said thickness is less than 1/10 of said length;

(h) said chamber has a length, and said length is at least ⅔ of said diameter of said chamber; and

(i) said chamber has a length, and said length lies in the range of ¾ to 2 times the diameter of said chamber.

34. The combination of claim 33 wherein said drill bit includes items (b), (d), (g) and (i).

35. A well boring process employing the drill string combination of claim 31, said process including providing a pulsating flow of drilling fluid to said bit while said bit is boring a well.

36. A well boring process employing the drill string combination of claim 31, said process including inducing torsional stress in said bit body and at the same time imposing a time varying stress field in said body that in addition to said torsional stress includes at least one of

(a) a fluctuating hoop stress in said peripheral wall;

(b) a fluctuating axial stress in said peripheral wall; and

(c) a fluctuating bending stress in said peripheral wall.

37. The process of claim 36 wherein said process includes inducing a reversing axial stress in said peripheral wall.

38. The process of claim 36 wherein the chamber has a face area, Af, the drill string includes a weight of drill collars W and the drill string is partially tensioned to impose a hold down force on the drill bit, the hold down force being a portion of W, said process includes pumping the drilling fluid at a pressure P, and the force obtained by multiplying the pressure P by Af is greater than the hold down force.

39. The process of claim 36 wherein said process includes providing pulsatingjets of drilling fluid to urge cuttings away from said drill bit.

40. The process of claim 36 wherein the process includes at least one of the following:

(a) operating pumping equipment to supply drilling fluid at a pressure in the range of 500 to 1500 psi;

(b) operating pumping equipment to produce pulsations in the range of 150 to 300 pulses per minute in the drilling fluid; and

(c) operating rotating equipment to cause said bit to rotate at a rotational speed in the range of 60 to 150 r.p.m.