DRILL BIT WITH DISTRIBUTED FORCE PROFILE
A method of making a drill bit for drilling subterranean formations includes forming a first blade having a shape and configuration defined by one or more first parameters and forming a second blade having a shape and configuration defined by one or more second parameters. One of the first parameters is different than one of the second parameters.
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This application claims priority under 35 U.S.C. §119(e) to U.S. Provisional Patent Application Ser. No. 61/496,755, filed Jun. 14, 2011, entitled DRILL BIT WITH DISTRIBUTED FORCE PROFILE, and which is hereby incorporated by reference in its entirety.
BACKGROUNDBoreholes in earth formations for the purpose of producing fluids and gasses from earth formations such as for use in the production of oil or other hydrocarbons, or for the purpose of depositing fluids into earth formations, are usually drilled with a drill string that includes a tubular member having a drilling assembly (also referred to as the bottomhole assembly or “BHA”) that includes a drill bit attached to the bottom end thereof. The drill bit is rotated to disintegrate the earth formations to drill the borehole. The BHA also includes devices and sensors for providing information about a variety of parameters relating to the drilling operations and the formation surrounding the borehole. To drill the borehole, fluid pumps are turned on to supply drilling fluid or mud to the drill string. The fluid passes through a passage in the drill bit to the bottom of the borehole and circulates to the surface via the annulus between the drill string and the borehole wall.
As in most endeavors, in the drilling industry it is desirable to drill in an efficient manner. It is known that a drill bit can more efficiently penetrate into a formation when lateral vibrations are reduced. A type of lateral vibration referred to as “bit whirl” or “backward whirl,” is used to describe the center of a drill bit rotating about the center of a borehole in the direction opposite of the rotation of the drill bit and drill string as a whole. This type of vibration has been shown to cause premature wear and damage to the bit. If the center of the drill bit is rotating about the center of the borehole in the same direction and, on average, the same speed as the rotation of the drill bit and string as a whole, the motion is referred to as “forward synchronous whirl.” This type of motion is desirable and is known to cause less damage to the drill bit. A bit that could reduce backward whirl and promote forward synchronous whirl would be well received in the industry.
One type of rotary drill bit is the fixed-cutter bit, often referred to as a “drag” bit. These bits generally include an array of cutting elements coupled to a face region (blade) of the bit body. The bit typically includes several blades distributed generally around a central axis of the bit. A hard, abrasive material, such as mutually bonded particles of polycrystalline diamond, may be provided on a substantially circular end surface of each cutting element to provide a cutting surface. Such cutting elements are often referred to as “polycrystalline diamond compact” (PDC) cutters. In operation, a fixed-cutter drill bit is placed in a borehole such that the cutting elements are in contact with the earth formation to be drilled. As the drill bit is rotated, the cutting elements scrape across and shear away the surface of the underlying formation.
BRIEF DESCRIPTIONAccording to one embodiment, method of making a drill bit for drilling subterranean formations is disclosed. The method includes: forming a first blade having a shape and configuration defined by one or more first parameters; and forming a second blade, the second blade having a shape and configuration defined by one or more second parameters. In this embodiment, one of the first parameters is different than one of the second parameters.
According to another embodiment, a downhole drill bit that includes a body and a first blade formed on the body and including a plurality of cutters coupled thereto, the first blade having a shape and configuration defined by one or more first parameters is disclosed. The bit of this embodiment also includes a second blade formed on the body and including a plurality of cutters coupled thereto, the second blade having a shape and configuration defined by one or more second parameters on of which is different than one of the first parameters.
The following descriptions should not be considered limiting in any way. With reference to the accompanying drawings, like elements are numbered alike:
A detailed description of one or more embodiments of the disclosed apparatus and method are presented herein by way of exemplification and not limitation with reference to the Figures.
Referring now to
The bit body 12 is secured to the steel shank 20 by way of a threaded connection 22 and a weld 24 extending around the drill bit 10 on an exterior surface thereof along an interface between the bit body 12 and the steel shank 20. The steel shank 20 includes an API threaded connection portion 28 for attaching the drill bit 10 to a drill string (not shown).
The bit body 12 includes wings or blades 30, which are separated by external channels or conduits also known as junk slots 32. Internal fluid passageways 42 extend between the face 18 of the bit body 12 and a longitudinal bore 40, which extends through the steel shank 20 and partially through the bit body 12. Nozzle inserts (not shown) may be provided at the face 18 of the bit body 12 within the internal fluid passageways 42.
A plurality of PDC cutters 34 may be provided on the face 18 of the bit body 12. In more detail, the PDC cutters 34 may be provided along the blades 30 within pockets 36 formed in the face 18 of the bit body 12, and may be supported from behind by buttresses 38, which may be integrally formed with the crown 14 of the bit body 12.
During drilling operations, the drill bit 10 is positioned at the bottom of a borehole and rotated while drilling fluid is pumped to the face 18 of the bit body 12 through the longitudinal bore 40 and the internal fluid passageways 42. As the PDC cutters 34 shear or scrape away the underlying earth formation, the formation cuttings mix with and are suspended within the drilling fluid and pass through the junk slots 32 and the annular space between the borehole and the drill string to the surface of the earth formation.
In typical drill bits, each blade 30 includes the same or similar configuration. According to embodiments of the present invention, one or more parameters that describe at least one of the blades is different from one or more of the parameters that describe another blade. The parameters can include, for example, the back rakes of the cutters 34, the density of the cutters 34, the number of cutters 34 on the blade 30, the size of the cutters 34, the exposure profile of the cutters 34, and the chamfer sizes on the cutters 34. In one embodiment, parameters can also include an indication of whether a gage cutter is provided on or adjacent the blade 30. In another embodiment the parameters can includes whether or not the blade 30 goes to the center of the bit and the distance between the blade 30 and one or more adjacent blades (e.g., blade density around the bit).
Regardless of the particular parameter that is varied, embodiments of the present invention can include a drill bit 10 that experiences different forces at different locations around it as it is rotated in a borehole. In particular, in one embodiment, a first blade experiences a maximal force while rotated and contacting the formation and all other blades experience, to varying degrees, lesser forces. In one embodiment, these forces are lateral forces experienced in a plane perpendicular to the axis of rotation of the bit. Of course, while forces generally are discussed below, it shall be understood that other factors such a forces could be utilized.
In the following discussion, certain conventions will be adhered to. In particular, a first blade 30a of the drill bit 10 has a first leading edge 50a. This first leading edge 50a shall generally define a 0° location on the drill bit 10. The angular displacement from the 0° location increases in the clockwise direction. Each of the other blades 30b-30d also includes leading edges 50b-50d, respectively. The leading edges 50a-50d are so named in this convention because the drill bit 10 is assumed to rotate counter-clockwise. Of course, other conventions could be utilized. For example, in the event that the bit 11 rotates in the clockwise direction, the trailing edge 51b of the first blade 30a could generally define the 0° location and angular displacement from the 0° location would increase in the counter-clockwise direction.
In the illustrated embodiment, the force experienced at the 0° location is at a maximal value 62. As the angular displacement is increased (e.g., moving clockwise around the bit in
The graph shown in
Referring again to
Two concepts in drill bit 10 design deserve further explanation. The first is referred to as the “exposure profile.” In general, the exposure profile is defined by the amount of cutter exposure of each cutter.
Another example of a blade parameter that is illustrated in
The amount of back rake of cutters 34 on a blade can also be a parameter of the blade.
As shown above, each blade 30 can have several parameters that describe both its shape and the orientation and exposure of cutters 34 in the blade 30. Typically, each blade 30 in prior art bits had the same parameters. According to embodiments disclosed herein, one blade 30 of a bit has one or more parameters that differ from another blade 30 in the bit.
Referring again to
It is assumed that the bit carrying the blade 30 generally travels in a downward direction 74. As such, the bottom of the blade 30 (e.g, the location of the cone cutters 72) is the part of the blade 30 where its face is generally perpendicular to the forward direction and the side of the blade 30 (e.g. the location of the shoulder cutters 70) is the part of the blade 30 where its face is generally parallel to the forward direction 74. It shall be understood that as the orientation of the bit carrying the blade 30 changes, the downward direction 74 will also change to allow, for example, drilling in a direction that is not directly downward from the surface of the earth. The blade 30 can also include one or more gage cutters 76 located generally above the shoulder cutters 70.
In
The above observations can lead to various bit configurations. For example, these observations may indicate that it can be beneficial to vary the back rake of the cutters across the blades of the bit such that the back rake is generally proportional to the force profile illustrated by the design curve 61 of
It shall further be understood that while the above description is directed to bits having blades, the teachings herein could be applied to drag bits that do not include blades. In such a case, forces/torques around the face of the bit could be calculated and used to design and/or improve the dynamic behavior (whirl resistance). In such a case, the bit can be divided into portions.
While the invention has been described with reference to an exemplary embodiment or embodiments, it will be understood by those skilled in the art that various changes may be made and equivalents may be substituted for elements thereof without departing from the scope of the invention. In addition, many modifications may be made to adapt a particular situation or material to the teachings of the invention without departing from the essential scope thereof. Therefore, it is intended that the invention not be limited to the particular embodiment disclosed as the best mode contemplated for carrying out this invention, but that the invention will include all embodiments falling within the scope of the claims. Also, in the drawings and the description, there have been disclosed exemplary embodiments of the invention and, although specific terms may have been employed, they are unless otherwise stated used in a generic and descriptive sense only and not for purposes of limitation, the scope of the invention therefore not being so limited. Moreover, the use of the terms first, second, etc. do not denote any order or importance, but rather the terms first, second, etc. are used to distinguish one element from another. Furthermore, the use of the terms a, an, etc. do not denote a limitation of quantity, but rather denote the presence of at least one of the referenced item.
Claims
1. A method of making a drill bit for drilling subterranean formations, comprising:
- forming a first blade, the first blade having a shape and configuration defined by one or more first parameters; and
- forming a second blade, the second blade having a shape and configuration defined by one or more second parameters;
- wherein one of the first parameters is different than one of the second parameters.
2. The method of claim 1, wherein the one of the first parameters is a back rake profile of cutters on the first blade and the one of the second parameters is a back rake profile of cutters on the second blade.
3. The method of claim 1, wherein the one of the first parameters is a density of cone cutters on the first blade and the one of the second parameters is a density of cone cutters on the second blade.
4. The method of claim 1, wherein the one of the first parameters is a density of shoulder cutters on the first blade and the one of the second parameters is a density of shoulder cutters of the second blade.
5. The method of claim 1, wherein the one of the first parameters is an exposure profile of cutters on the first blade and the one of the second parameters is an exposure profile of cutters on the second blade.
6. The method of claim 1, wherein the first blade is formed such that it experiences higher force while being rotated in a borehole than the second blade.
7. The method of claim 1, further comprising
- forming a third blade having a shape and configuration defined by one or more third parameters.
8. The method of claim 7, wherein the first blade is formed such that it experiences higher force while being rotated in a borehole than the second blade and the third blade.
9. The method of claim 8, wherein the third blade is formed such that it experiences higher force while being rotated in a borehole than the second blade and such that, measured in the clockwise direction around the bit, is further away from the first blade than the second blade is from the first blade.
10. A downhole drill bit comprising:
- a body;
- a first blade formed on the body and including a plurality of cutters coupled thereto, the first blade having a shape and configuration defined by one or more first parameters; and
- a second blade formed on the body and including a plurality of cutters coupled thereto, the second blade having a shape and configuration defined by one or more second parameters, one of the second parameters being different than one of the first parameters.
11. The downhole drill bit of claim 10, wherein the one of the first parameters is a back rake profile of the cutters coupled to the first blade and the one of the second parameters is a back rake profile of the cutters coupled to the second blade.
12. The downhole drill bit of claim 10, wherein the cutters are cone cutters and wherein the one of the first parameters is a density of the cone cutters coupled to the first blade and the one of the second parameters is a density of the cone cutters coupled to the second blade.
13. The downhole drill bit of claim 10, wherein the cutters are shoulder cutters and wherein the one of the first parameters is a density of the shoulder cutters coupled to the first blade and the one of the second parameters is a density of the shoulder cutters coupled to the second blade.
14. The downhole drill bit of claim 10, wherein the one of the first parameters is an exposure profile of the cutters coupled to the first blade and the one of the second parameters is an exposure profile the cutters coupled to the second blade.
15. A method of making a drill bit for drilling subterranean formations, comprising:
- forming a first portion of the drill bit, the first portion having a shape and configuration defined by one or more first parameters; and
- forming a second portion of the drill bit, the second portion having a shape and configuration defined by one or more second parameters;
- wherein one of the first parameters is different than one of the second parameters.
16. The method of claim 15, wherein the first portion is formed such that it experiences higher force while being rotated in a borehole than the second portion.
17. The method of claim 15, further comprising
- forming a third portion having a shape and configuration defined by one or more third parameters.
18. The method of claim 17, wherein the first portion is formed such that it experiences higher force while being rotated in a borehole than the second portion and the third portion.
19. The method of claim 18, wherein the third portion is formed such that it experiences higher force while being rotated in a borehole than the second portion and such that, measured in the clockwise direction around the bit, is further away from the first portion than the second portion is from the first portion.
Type: Application
Filed: Jun 14, 2012
Publication Date: Jan 10, 2013
Applicant: BAKER HUGHES INCORPORATED (Houston, TX)
Inventors: Lance A. Endres (Spring, TX), Gregory Carlton Prevost (Spring, TX), Tyler Rhes Reynolds (Aberdeen)
Application Number: 13/517,774
International Classification: E21B 10/62 (20060101); B21K 5/04 (20060101);