Drill bit with plural set and single set blade configuration

- Smith International, Inc.

Disclosed within is a drill bit with a plural set of blades having redundant cutter elements and single sets of blades having unique cutter element arrangements. The redundant cutter elements have equivalent longitudinal and axial spacing as corresponding cutter elements. The distance from a longitudinal axis of the bit to a redundant cutter element is equivalent to the distance from the longitudinal axis to the corresponding cutter element.

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Description

CROSS-REFERENCE TO RELATED APPLICATIONS

Not Applicable.

STATEMENT REGARDING FEDERALLY SPONSORED RESEARCH OR DEVELOPMENT

Not Applicable.

BACKGROUND

Embodiments of the present invention relate generally to drill bits and, more particularly, to fixed-cutter bits designed to shift orientation of the bit axis in a predetermined direction as it drills.

Drill bits, in general, are well known in the art. The bit is attached to the lower end of the drill string and is typically rotated by rotating the drill string at the surface or by a down hole motor, or by both methods. The bit is typically cleaned and cooled during drilling by the flow of drilling fluid out of one or more nozzles on the bit face. The fluid is pumped down the drill string, flows across the bit face, removing cuttings and cooling the bit, and then flows back to the surface through the annulus between the drill string and the borehole wall.

The cost of drilling a borehole is proportional to the length of time it takes to drill the borehole to the desired depth and location. The drilling time, in turn, is greatly affected by the number of times the drill bit must be changed in order to reach the targeted depth or formation. This is the case because each time the bit is changed the entire drill string, which may be miles long, must be retrieved from the borehole, section by section. Once the drill string has been retrieved and the new bit installed, the new bit must be lowered to the bottom of the borehole on the drill string, which again must be constructed section by section. This process, known as a “trip” of the drill string, requires considerable time, effort and expense. Accordingly, it is always desirable to minimize the number of trips that must be made in a given well.

In recent years a majority of bits have been designed using hard polycrystalline diamond compacts (PDC) as cutting or shearing elements. The cutting elements or cutters are mounted on a rotary bit and oriented so that each PDC engages the rock face at a desired angle. The PDC bit has become an industry standard for cutting formations of grossly varying hardnesses. The cutting elements used in such bits are formed of extremely hard materials and include a layer of polycrystalline diamond material. In the typical PDC bit, each cutter element or assembly comprises an elongate and generally cylindrical support member which is received and secured in a pocket formed in the surface of the bit body. A cutter element typically has a hard cutting layer of polycrystalline diamond or other superabrasive material such as cubic boron nitride, thermally stable diamond, polycrystalline cubic boron nitride, or ultrahard tungsten carbide (meaning a tungsten carbide material having a wear-resistance that is greater than the wear-resistance of the material forming the substrate) as well as mixtures or combinations of these materials. The cutting layer is exposed on one end of its support member, which is typically formed of tungsten carbide. As used herein, reference to a “PDC” bit or “PDC” cutting element includes superabrasive materials such as polycrystalline diamond, cubic boron nitride, thermally stable diamond, polycrystalline cubic boron nitride, or ultrahard tungsten carbide.

The configuration or layout of the PDC cutters on a bit face varies widely, depending on a number of factors. One of these is the formation itself, as different cutting element layouts cut the various strata differently. In running a bit, the driller may also consider weight on bit, the weight and type of drilling fluid, and the available or achievable operating regime. Additionally, a desirable characteristic of the bit is that it be “stable” and resist vibration, the most severe type or mode of which is “whirl,” which is a term used to describe the phenomenon wherein a drill bit rotates about an axis that is offset from the geometric center of the drill bit. Whirling subjects the cutting elements on the bit to increased loading, which may cause the premature wearing or destruction of the cutting elements and a loss of penetration rate. Alternatively, U.S. Pat. Nos. 5,109,935 and 5,010,789 disclose techniques for reducing whirl by compensating for imbalance in a controlled manner, the contents of which are hereby incorporated by reference. In general, optimization of cutter placement and orientation and overall design of the bit have been the objectives of extensive research efforts.

Directional and horizontal drilling have also been the subject of much research. Directional and horizontal drilling involves deviation of the borehole from vertical. Frequently, this drilling program results in boreholes whose remote ends are approximately horizontal. Advancements in measurement while drilling (MWD) technology have made it possible to track the position and orientation of the wellbore very closely. At the same time, more extensive and more accurate information about the location of the target formation is now available to drillers as a result of improved logging techniques and methods, such as geosteering. These increases in available information have raised the expectations for drilling performance. For example, a driller today may target a relatively narrow, horizontal oil-bearing stratum, and may wish to maintain the borehole within the stratum once the borehole has entered the stratum. In more complex scenarios, highly specialized “design drilling” techniques are preferred, with highly tortuous well paths having multiple directional changes of two or more bends lying in different planes.

A common way to control the direction in which the bit is drilling is to steer using a turbine, downhole motor with a bent sub and/or housing. As shown in FIG. 1, a simplified version of a downhole steering system according to the prior art comprises a rig 1, drill string 2 having a motor 6 with or without a bent sub 4, and drill bit 8. The motor 6, with or without a bent sub 4, forms part of the bottom hole assembly (BHA). These BHA components are attached to the lower end of the drill string 2 adjacent the bit 8. When not rotating, the bent sub 4 causes the bit face to be canted with respect to the tool axis. The motor is capable of converting fluid pressure from drilling fluid pumped down the drill string into rotational energy at the bit. This presents the option of rotating the bit without rotating the drill string. When a downhole motor is used with a bent housing and the drill string is not rotated, the rotating action of the motor normally causes the bit to drill a hole that is deviated in the direction of the bend in the housing. When the drill string is rotated, the borehole normally maintains direction, regardless of whether a downhole motor is used, as the bent housing rotates along with the drill string and thus no longer orients the bit in a particular direction. Hence, a bent housing and downhole motor are effective for deviating a borehole.

When a well is substantially deviated by several degrees from vertical and has a substantial inclination, such as by more than 30 degrees, the factors influencing drilling and steering change as compared to those of a vertical well. This change in factors reduces operational efficiency for a number of reasons.

First, operational parameters such as weight on bit (WOB) and RPM have a large influence on the bit's rate of penetration, as well as its ability to achieve and maintain the required well bore trajectory. As the well's inclination increases and approaches horizontal, it becomes much more difficult to apply weight on bit effectively, as the well bottom is no longer aligned with the force of gravity. Furthermore, the increasing bend in the drill string means that downward force applied to the string at the surface is less likely to be translated into WOB, and is more likely to increase loading that can cause the buckling or deforming of the drill string. Thus, attempting to steer with a downhole motor and a bent sub normally reduces the achievable rate of penetration (ROP) of the operation, and makes tool phase control very difficult.

Second, using the motor to change the azimuth or inclination of the well bore without rotating the drill string, a process commonly referred to as “sliding,” means that the drilling fluid in most of the length of the annulus is not subject to the rotational shear that it would experience if the drill string were rotating. Drilling fluids tend to be thixotropic, so the loss of this shear adversely affects the ability of the fluid to carry cuttings out of the hole. Thus, in deviated holes that are being drilled with the downhole motor alone, cuttings tend to settle on the bottom or low side of the hole. This increases borehole drag, making weight-on-bit transmission to the bit very difficult and causing problems with tool phase control and prediction. This difficulty makes the sliding operation very inefficient and time consuming

Third, drilling with the downhole motor alone during sliding deprives the driller of the advantage of a significant source of rotational energy, namely the surface equipment that would otherwise rotate the drill string and reduce borehole drag and torque. The drill string, which is connected to the surface rotation equipment, is not rotated during drilling with a downhole motor during sliding. Additionally, drilling with the motor alone means that a large fraction of the fluid energy is consumed in the form of a pressure drop across the motor in order to provide the rotational energy that would otherwise be provided by equipment at the surface. Thus, when surface equipment is used to rotate the drill string and the bit, significantly more power is available downhole and drilling is faster. This power can be used to rotate the bit or to provide more hydraulic energy at the bit face, for better cleaning and faster drilling.

In addition to the directional drilling described in the discussion of FIG. 1, it is also desirable to have a drill bit that is capable of returning to a vertical drilling orientation (without the aid of an external steering mechanism such as turbine or bent sub) should the bit inadvertently deviate from vertical. The ability of a bit to return to a vertical path after deviating from such a path is known in the art as “dropping”. In order to effect dropping, such a drill bit must also have the capability of drilling or penetrating the earth in a direction that is not parallel with the longitudinal axis of the bit. It is therefore desirable to have cutting elements on the side of the bit to allow for such cutting action.

As shown in the schematic view of FIG. 2, a drillstring assembly 50, consisting of a drill string 53 and a bit 51, is shown drilling a borehole 55 that has deviated from vertical. Drillstring assembly 50 has a weight vector 52 that consists of an axial component 54 and a normal component 56. Unlike the directional drilling operations described above, such deviations from vertical are sometimes unintentional, and it is desirable in many instances to return drilling assembly 50 to a vertical orientation while drilling. In such a case, it necessary for drill bit 51 to drill in a direction that is not parallel to axial vector 54. This is accomplished by removing material from a side wall 57, rather than a bottom portion 53, of borehole 55. As explained in more detail below, the ability to remove material from side wall 57 is enhanced when bit 51 generates increased forces parallel to normal component 56 during operation.

Drill bits with asymmetric blade designs have been used to generate forces during rotation that are not parallel to axial vector 54. The asymmetric blade designs typically include “active” regions of cutters, which extend a certain distance from the center axis and the end (or face) of the bit, as well as “passive” regions of cutters, in which the cutters are slightly recessed from the active cutter positions. The generation of these off-axis forces enhance the dropping tendencies of the bit by increasing the loading on the side of the bit and reducing the tendencies of the bit to whirl. However, the asymmetric design of the blades can sometimes decrease the durability of the blades as a result of the increased loading placed on the active cutters and the fact that the passive cutters generally do not actively drill the formation until there has been significant wear on the active cutters.

For all of these reasons, it is desirable to provide a bit that remains stable during operation and allows for off-axis drilling by exerting a force against the side of the borehole. It is further desired to provide such a device that exhibits high durability characteristics by providing a large number of cutters that actively remove material from the borehole during operation.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 shows a conventional drilling system;

FIG. 2 is a schematic view of a prior art drill bit on a drill string;

FIG. 3 is a perspective view of a prior art drill bit;

FIG. 4 is a section view of the prior art bit of FIG. 3;

FIG. 5 is an end view of one embodiment of a drill bit made in accordance with the disclosure herein;

FIG. 6 is a partial section view of the drill bit of FIG. 5;

FIG. 7 is a partial section view of the drill bit of FIG. 5;

FIG. 8 is an end view of an alternative embodiment of a drill bit;

FIG. 9 is an end view of another alternative embodiment of a drill bit; and

FIG. 10 is an end view of another alternative embodiment of a drill bit.

DETAILED DESCRIPTION OF PREFERRED EMBODIMENTS

A known drill bit is shown in FIG. 3. Bit 10 is a fixed cutter bit, sometimes referred to as a drag bit, and is preferably a PDC bit adapted for drilling through formations of rock to form a borehole. Bit 10 generally includes a bit body having a shank 13, and a threaded connection or pin 16 for connecting bit 10 to a drill string that is employed to rotate the bit for drilling the borehole. Bit 10 further includes a central axis 11 and a cutting structure on the face 14 of the drill bit. The cutting structure includes various PDC cutter elements 40 with a backing portion 38 on a plurality of blades 37 extending radially from the center of the cutting face 36. Also shown in FIG. 3 are gage pads 12 and gage trimmers 61, the outer surface of which are at the diameter of the bit and establish the size of the bit. Thus, a 12″ bit will have gage pads 12 and gage trimmers 61 at approximately 6″ from the center of the bit.

Referring now to FIG. 4, a profile of bit 10 is shown as it would appear with all cutter elements 40 shown overlapping in rotated profile. As shown in this figure, blades 37 include blade profiles 39. The drill bit body 10 includes a face region 14 and a gage pad region 12 for the drill bit. The action of cutters 40 drills the borehole while the drill bit body 10 rotates. Downwardly extending flow passages 21 have nozzles or ports 22 disposed at their lowermost ends. Bit 10 includes six such flow passages 21 and nozzles 22. The flow passages 21 are in fluid communication with central bore 17. Together, passages 21 and nozzles 22 serve to distribute drilling fluid around the cutter elements 40 for flushing drilled formation from the bottom of the borehole and away from the cutting faces 44 of cutter elements 40 during drilling. Amongst several other functions, the drilling fluid also serves to cool the cutter elements 40 during drilling.

Blade profiles 39 and bit face 20 may be said to be divided into three different regions 24, 26, and 28. The central region of the bit face 20 is identified by reference numeral 24 and is concave in this example. Adjacent central region 24 is the shoulder or the upturned curve region 26. Next to shoulder 26 is the gage region 28 which is the portion of the bit face 20 which defines the diameter or gage of the borehole being drilled by bit 10. Cutter elements 40 are disposed along each of blades 37 in regions 24, 26 and 28.

Referring now to FIG. 5, an end view of one embodiment of a bit 110 is shown with a cutting face 114 disposed around a longitudinal or bit axis 111. A plurality of blades 137-142 project from cutting face 114 and extend radially outward from axis 111. Blades 137-142 comprise a plurality of cutter elements 150 of varying radial and axial positions, as more fully described below. Bit 110 further includes a plurality of nozzles 122 that distribute drilling fluid as described above. The specific locations of the cutter elements 150 are shown in bit 110 for purpose of example only, and other embodiments may have different arrangements of cutter elements, including, for example, blades that are more curved than those shown in FIG. 5.

Referring now to FIG. 6, a partial section view of bit 110 taken at blade 137 shows the orientation of cutter elements 150 arranged on blade 137. In addition, a central bore 115 is shown extending from a pin end 116 in fluid communication with a fluid passage 121 and nozzle 122. As shown in FIG. 6, the center of each cutter element 150 is at a radial position that is a predetermined distance from longitudinal axis 111. In addition, each cutter element 150 is located at an axial position that is a predetermined distance from a reference plane “A” that is perpendicular to longitudinal axis 111. For example, a specific cutter element 153 is located a distance X1 from longitudinal axis 111 and a distance Y1 from plane A, while cutter element 151 is located a distance X2 from longitudinal axis 111 and Y2 from plane A.

Referring back now to FIG. 5, for each cutter element 150 on blade 138, there is a corresponding cutter element 150 on blade 137 that is located at the same relative radial and axial positions. For example, cutter element 153 on blade 137 has a cutting face that is located at the same relative radial and axial position as cutter element 154 on blade 138. More specifically, both cutter elements 153 and 154 are located the same radial distance from longitudinal axis 111. In addition, both cutter elements 153 and 154 are located the same axial distance from a plane that is perpendicular to longitudinal axis 111 (such as plane A in FIG. 6). Similarly, cutter elements 151 and 152 are also equidistant from longitudinal axis 111 and equidistant from a plane that is perpendicular to longitudinal axis 111. Thus, when viewed in rotated profile, the profile of the cutting faces of cutting elements 151 and 152 would be precisely aligned. If the two cutting face profiles are in exactly the same position, they may be referred to as “redundant” cutter elements.

In addition, as explained more fully below, a redundant cutting face profile may also be recessed 0.020 inches to 0.060 inches from a corresponding cutting face profile. For example, in other embodiments, elements 152 and 154 may be slightly retracted or recessed from the locations of cutter elements 151 and 153, respectively. In certain embodiments, the position of the cutter elements on one blade can be recessed in a direction that is perpendicular to the face of cutter element. Referring now to FIG. 7, a section view of cutter element 152 taken along line 7-7 in FIG. 5 reveals cutter element 152 affixed to blade 138. Cutter element 152 includes a cutting face 160 disposed on a backing element 155.

In certain embodiments, cutter element 152 can be recessed relative to the position of cutter element 151. For example, referring still to FIG. 7, cutter element 152 can be recessed approximately 0.020 inches to 0.030 inches in the direction represented by an arrow “B”, which is parallel to a planar front surface 161 of cutting face 160. Retraction in the direction represented by arrow “B” is commonly referred to as retraction along the “normal line” of the cutter element. In still other embodiments, cutter element 152 can be recessed in a direction parallel to longitudinal axis 111, so that the distance from plane A (shown in FIG. 6) is approximately 0.020 inches to 0.060 inches less than the corresponding distance for cutter element 151. In such embodiments, the recessed cutter elements will be slightly closer to the pin end 116.

Referring back now to FIG. 5, as previously stated, for each cutter element 150 on blade 138, there is a corresponding cutter element 150 on blade 137 that is located at the same relative radial and axial positions and has the same size and shape as the cutter element on blade 138. The additional blades 139-42, however, each have an arrangement of cutter elements that is unique, i.e. the arrangement of cutter elements on each additional blade 139-142 is different than the arrangement of cutter elements on any other blade 137-142. More specifically, the radial and axial position of at least one cutter element on a specific blade 139-142 is not equivalent to the radial and axial position of any cutter element on any other blade 137-142. As commonly described in the field, each of the blades 139-142 are “single set” blades (i.e., blades which comprise an arrangement of cutter elements that is different than every other blade on the bit).

The inclusion of several single set blades enhances the durability of the bit by providing a large number of cutters that actively remove formation material to form the wellbore. By providing a large number of active cutters, the amount of work that is performed by the each cutter is minimized and the stresses placed on each active cutter are also reduced. This reduces the likelihood of a mechanical failure for the active cutters and enhances the durability of the bit.

In contrast, blades 137 and 138 are “plural set” blades; i.e., each cutter element on trailing blade 138 is redundant to a corresponding cutter element preceding blade 137. Blade 138 is considered the trailing blade because it follows blade 137 as bit 110 rotates counter-clockwise during drilling. It should be noted that in a plural set of blades, the preceding blade may comprise cutter elements in positions additional to those found on the trailing blade, but the reverse is not true. Therefore, each cutter element on trailing blade 138 has a corresponding cutter element on blade 137 that has generally equivalent radial and axial spacing. The arrangement of cutter elements on the trailing blade of a plural set of blades is therefore redundant to the arrangement of cutter elements on the preceding blade.

During rotation of the bit, each redundant cutter element follows in essentially the same path as the corresponding cutter element on the preceding adjacent blade. The corresponding element on the preceding blade clears away formation material, allowing the redundant element to follow in the path cleared by the preceding element. As a result, during rotation the redundant cutter element is subjected to less resistance from the earthen material and less wear than the preceding element. The decrease in resistance reduces the stresses placed on the redundant element and can improve the durability of the element by reducing the likelihood of mechanical failures such as fatigue cracking.

The incorporation of a plural set of blades 137 and 138 in combination with single set blades 139-142 creates an asymmetric configuration that will generate an imbalance force perpendicular to longitudinal axis 111 as bit 110 rotates. This imbalance force will help to push bit 110 against the side wall of the borehole during operation, which will stabilize bit 110 and reduce the tendency of bit 110 to whirl, thereby reducing the likelihood of a mechanical failure of bit 110 or the drillstring.

Generating a force that pushes bit 110 against the sidewall of the borehole can also improve the ability of the bit to drill in a direction that is not parallel with the longitudinal axis. When bit 110 is pushed against the sidewall of the borehole, gage trimmers 61 can engage the sidewall and remove formation material. This allows bit 110 to penetrate the formation and travel in a direction that is not parallel to the longitudinal axis of bit 110.

While FIG. 5 depicts an embodiment with one pair of plural set blades and four single set blades, other embodiments may include a different number of total blades or different numbers of blades in the single and plural sets. One example of an alternative embodiment is shown in FIG. 8. In this embodiment, a bit 210 includes a plurality of blades 237-242 and nozzles 222 distributed about a longitudinal axis 211. Similar to the previously described embodiment, a plurality of cutter elements 250 are distributed on the blades 237-252. In this embodiment, however, blades 238 and 239 include an arrangement of cutter elements that is redundant to the arrangement of cutter elements on blade 237, such that blades 237-239 form a plural set. In contrast, blades 240-242 each include a unique arrangement of cutter elements resulting in blades 240-242 forming single set blades.

Still another embodiment is shown in FIG. 9. In this embodiment, a bit 310 includes a plurality of blades 337-344 and nozzles 322 distributed about a longitudinal axis 311. A plurality of cutter elements 350 are distributed on the blades 337-344. In this embodiment, blade 338 comprises an arrangement of cutter elements that is redundant to the arrangement of cutter elements on blade 337. In addition, blade 340 comprises an arrangement of cutter elements that is redundant to the arrangement of cutter elements on blade 339, but not redundant to that of blade 337 or 338. Bit 310 therefore has two separate plural sets of blades (blades 337-338 and blades 339-340). Blades 341-344 each have a unique set of cutter elements and form four separate single sets of blades.

Yet another embodiment is shown in FIG. 10. In this embodiment, a bit 410 includes a plurality of blades 437-440 and nozzles 422 distributed about a longitudinal axis 411. A plurality of cutter elements 450 are distributed on the blades 437-440. In this embodiment, blade 438 comprises an arrangement of cutter elements that is redundant to the arrangement of cutter elements on blade 437. However, blades 439 and 440 each comprise a unique arrangement of cutter elements. Bit 410 therefore has a pair of blades 437-438 that form a plural set of cutter elements and a pair of blades 339-340 that are each a single set of cutter elements.

While various preferred embodiments have been showed and described, modifications thereof can be made by one skilled in the art without departing from the spirit and teachings herein. The embodiments herein are exemplary only, and are not limiting. Many variations and modifications of the system and apparatus disclosed herein are possible and within the scope of the invention. For example, other embodiments may comprise drill bits with different blade and cutter arrangements or different numbers of blades. Accordingly, the scope of protection is not limited by the description set out above, but is only limited by the claims which follow, that scope including all equivalents of the subject matter of the claims.

Claims

1. A drill bit for drilling a borehole comprising:

a bit body with a first end, a second end and a longitudinal bit axis;
a first blade disposed on said first end of said bit body;
a first arrangement of cutter elements disposed on said first blade;
a second blade disposed on said first end of said bit body;
a second arrangement of cutter elements disposed on said second blade, wherein said second arrangement is redundant to said first arrangement;
a third blade disposed on said first end of said bit body, wherein said third blade comprises a third arrangement of cutter elements and said third arrangement is unique; and
a fourth blade disposed on said first end of said bit body, wherein said fourth blade comprises a fourth arrangement of cutter elements and said fourth arrangement is unique.

2. The drill bit of claim 1 wherein each cutter element on the second blade is the same distance from the longitudinal bit axis as a corresponding cutter element on the first blade.

3. The drill bit of claim 1 wherein each cutter element on the second blade is the same distance from a plane perpendicular to the longitudinal bit axis as a corresponding cutter element disposed on the first blade.

4. The drill bit of claim 1 wherein:

each cutter element comprises a generally planar face; and
a cutter element on the second blade is recessed from the position of the corresponding cutter element on the first blade approximately 0.020 inches to 0.060 inches along a line parallel to the generally planar face.

5. The drill bit of claim of claim 1 wherein each cutter element disposed on the second blade is approximately 0.020 inches to 0.060 inches closer to the second end than a corresponding cutter element disposed on the first blade.

6. The drill bit of claim 1 wherein the second blade is adjacent to the first blade.

7. The drill bit of claim 1 further comprising:

a fifth blade disposed on said first end of said bit body; and
a fifth arrangement of cutter elements disposed on said fifth blade, wherein said fifth arrangement of cutter elements is unique and the first blade is adjacent to the second blade.

8. The drill bit of claim 7 wherein the first blade is adjacent to the second blade and the fifth blade.

9. The drill bit of claim 1 further comprising:

a fifth blade disposed on said first end of said bit body;
a fifth arrangement of cutter elements disposed on said fifth blade, wherein said first arrangement and said second arrangement of cutter elements is redundant to said fifth arrangement.

10. The drill bit of claim 1, further comprising:

a fifth blade disposed on said first end of said bit body;
a sixth blade disposed on said first end of said bit body;
a fifth arrangement of cutter elements disposed on said fifth blade, wherein said fifth arrangement of cutter elements is unique; and
a sixth arrangement of cutter elements disposed on said sixth blade, wherein said sixth arrangement of cutter elements is unique.

11. The drill bit of claim 10, further comprising:

a seventh blade disposed on said first end of said bit body;
a seventh arrangement of cutter elements disposed on said seventh blade, wherein said seventh arrangement of cutter elements is unique.

12. The drill bit of claim 1, further comprising:

a fifth blade disposed on said first end of said bit body;
a sixth blade disposed on said first end of said bit body;
a fifth arrangement of cutter elements disposed on said fifth blade, wherein said first arrangement and said second arrangement of cutter elements is redundant to said fifth arrangement; and
a sixth arrangement of cutter elements disposed on said sixth blade, wherein said sixth arrangement of cutter elements is unique.

13. The drill bit of claim 12, further comprising:

a seventh blade disposed on said first end of said bit body;
a seventh arrangement of cutter elements disposed on said seventh blade, wherein said seventh arrangement of cutter elements is unique.

14. The drill bit of claim 1, further comprising:

a fifth blade disposed on said first end of said bit body;
a sixth blade disposed on said first end of said bit body
a fifth arrangement of cutter elements disposed on said fifth blade; and
a sixth arrangement of cutter elements disposed on said sixth blade, wherein said fifth arrangement of cutter elements is redundant to said sixth arrangement.

15. The drill bit of claim 14, further comprising:

a seventh blade disposed on said first end of said bit body;
a seventh arrangement of cutter elements disposed on said seventh blade, wherein said seventh arrangement of cutter elements is unique.

16. A drill bit for drilling a borehole comprising:

a bit body comprising a first end, a second end, and a longitudinal axis;
a first blade disposed on the first end;
a second blade disposed on the first end;
at least two additional blades disposed on the first end; and
an arrangement of cutter elements disposed on said blades, wherein:
said cutter elements are spaced radially from the longitudinal axis and axially from a plane perpendicular to the longitudinal axis;
said first blade has a first arrangement of cutter elements;
said second blade has a second arrangement of cutter elements;
the second arrangement is generally equivalent to at least a portion of the first arrangement; and
each of the additional blades has an arrangement of cutter elements that is different than the arrangement of cutter elements on any other additional blade.

17. The drill bit of claim 16 wherein the first blade and the second blade form a plural set of blades and each additional blade forms a single set.

18. The drill bit of claim 16 wherein:

each cutter element disposed on the second blade is the same distance from the longitudinal axis as a corresponding cutter element disposed on the first blade.

19. The drill bit of claim 16 wherein each cutter element disposed on the second blade is the same distance from a plane perpendicular to the longitudinal axis as a corresponding cutter element disposed on the first blade.

20. The drill bit of claim 16 wherein:

each cutter element comprises a generally planar face; and
a cutter element on the second blade is recessed from the position of the corresponding cutter element on the first blade approximately 0.020 inches to 0.060 inches in a direction parallel to the generally planar face.

21. The drill bit of claim of claim 16 wherein each cutter element disposed on the second blade is approximately 0.020 inches to 0.060 inches closer to the second end than a corresponding cutter element disposed on the first blade.

22. A drill bit for drilling a borehole comprising:

a bit body comprising a first end, a second end, and a longitudinal axis;
a plurality of blades disposed on the first end; and
a plurality of cutter elements disposed on the blades, the cutter elements spaced radially from the longitudinal axis and axially from a plane perpendicular to the longitudinal axis, wherein: each blade has an arrangement of cutter elements; a first blade and a second blade comprise a first plural set of cutter elements; and a third blade comprises a first single set of cutter elements; and a fourth blade comprises a second single set of cutter elements.

23. The drill bit of claim 22 wherein:

each cutter element disposed on the second blade is the same distance from the longitudinal axis as a corresponding cutter element disposed on the first blade.

24. The drill bit of claim 22 wherein each cutter element disposed on the second blade is the same distance from the plane as a corresponding cutter element disposed on the first blade.

25. The drill bit of claim 22 wherein:

each cutter element comprises a generally planar face; and
a cutter element on the second blade is recessed from the position of the corresponding cutter element on the first blade approximately 0.020 inches to 0.060 inches in a direction parallel to the generally planar face.

26. The drill bit of claim of claim 22 wherein each cutter element disposed on the second blade is approximately 0.020 inches to 0.060 inches farther from a plane perpendicular to the longitudinal axis than a corresponding cutter element disposed on the first blade.

27. The drill bit of claim 22 wherein:

a fifth blade and a sixth blade comprise a second plural set of cutter elements, wherein said second plural set is not redundant to said first plural set.

28. The drill bit of claim 27 wherein:

a seventh blade comprises a third single set of cutter elements; and
an eighth blade comprises a fourth single set of cutter elements.

29. A drill bit for drilling a borehole comprising:

a bit body having a plurality of blades disposed thereon;
a longitudinal axis;
a plurality of cutter elements disposed on the blades, wherein each cutter element has a position that is a radial distance from the longitudinal axis and an axial distance from a plane that is perpendicular to the longitudinal axis, wherein:
a first blade has a first arrangement of cutter elements;
a second blade has a second arrangement of cutter elements, wherein the position of each cutter element in the second arrangement is equivalent to the position of a cutter element in the second arrangement;
a third blade, wherein the position of a cutter element on the third blade is not equivalent to the position of a cutter element on any other blade; and
a fourth blade, wherein the position of a cutter element on the fourth blade is not equivalent to the position of a cutter element on any other blade.

Patent History

Publication number: 20070278014
Type: Application
Filed: May 30, 2006
Publication Date: Dec 6, 2007
Applicant: Smith International, Inc. (Houston, TX)
Inventor: Peter T. Cariveau (South Jordan, UT)
Application Number: 11/443,406

Classifications

Current U.S. Class: Rolling Cutter Bit Or Rolling Cutter Bit Element (175/331); Nonsymmetrical Bit (175/398)
International Classification: E21B 10/00 (20060101);