For a more detailed description of the preferred embodiments, reference will now be made to the accompanying drawings, wherein:
The following discussion is directed to various embodiments. Although one or more of these embodiments may be preferred, the embodiments disclosed should not be interpreted, or otherwise used, as limiting the scope of the disclosure, including the claims. In addition, one skilled in the art will understand that the following description has broad application, and the discussion of any embodiment is meant only to be exemplary of that embodiment, and not intended to intimate that the scope of the disclosure, including the claims, is limited to that embodiment.
Certain terms are used throughout the following description and claims to refer to particular features or components. As one skilled in the art will appreciate, different persons may refer to the same feature or component by different names. This document does not intend to distinguish between components or features that differ in name but not function. The drawing figures are not necessarily to scale. Certain features and components herein may be shown exaggerated in scale or in somewhat schematic form and some details of conventional elements may not be shown in interest of clarity and conciseness.
In the following discussion and in the claims, the terms “including” and “comprising” are used in an open-ended fashion, and thus should be interpreted to mean “including, but not limited to . . . .” Also, the term “couple” or “couples” is intended to mean either an indirect or direct connection. Thus, if a first device couples to a second device, that connection may be through a direct connection, or through an indirect connection via other devices and connections.
Referring to
As best seen in
Referring now to
In this embodiment, blades 150, 160, 170, 180, 190, 200 are integrally formed as part of, and extend from, bit body 112 and bit face 120. Further, blades 150, 160, 170, 180, 190, 200 extend radially outward along bit face 120 and then axially along a portion of the periphery of bit 110. Blades 150, 160, 170, 180, 190 and 200 are separated by drilling fluid flow courses 119. As used herein, the terms “axial” and “axially” generally mean along or parallel to the bit axis (e.g., bit axis 111), while the terms “radial” and “radially” generally mean perpendicular to the bit axis. For instance, an axial distance refers to a distance measured parallel to the bit axis, and a radial distance means a distance measured perpendicular from the bit axis.
Referring still to
Bit 110 further includes gage pads 151, 161, 171, 181, 191, 201 of substantially equal axial length in this embodiment. Gage pads 151, 161, 171, 181, 191, 201 are generally disposed about the outer circumference of bit 110 at angularly spaced apart locations. Specifically, each gage pad 151, 161, 171, 181, 191, 201 intersect and extends from one of the blades 150, 160, 170, 180, 190 and 200, respectively. Gage pads 151, 161, 171, 181, 191, 201 are each integrally formed as part of the bit body 112.
Each gage pad 151, 161, 171, 181, 191, 201 includes a radially outer formation or gage-facing surface 130 and a generally forward-facing surface 131 which intersect in an edge 132, which may be radiused, beveled or otherwise rounded. Each gage-facing surface 130 includes at least a portion that extends in a direction generally parallel to axis 111. As used herein, the phrase “gage-facing surface” refers to the radially outer surface of a gage pad that generally faces the formation. It should be appreciated that in some embodiments, portions of one or more gage-facing surface 130 may be angled, and thus slant away from the borehole sidewall. Also, in select embodiments, one or more forward-facing surface 131 may likewise be angled relative to bit axis 111 (both as viewed perpendicular to axis 111 or as viewed along axis 111). Thus, gage-facing surface 130 need not be perfectly parallel to the formation, but rather, may be oriented at an acute angel relative to the formation. Surface 131 is termed “forward-facing” to distinguish it from gage-facing surface 130, which generally faces the borehole sidewall. A gage trimmer 154, 164, 174, 184, 194, 204 is mounted to each gage pad 151, 161, 171, 181, 191, 201, respectively. In particular, in this embodiment, one gage trimmer 154, 164, 174, 184, 194, 204 extends from the gage-facing surface 130 of each gage pad 151, 161, 171, 181, 191, 201, respectively. However, in other embodiments, none or more than one gage trimmer may be provided on one or more of the gage pads.
Referring specifically to
Referring still to
In general, the geometry, orientation, and placement of the plurality of blades on a fixed cutter bit can be varied relative to each other to enhance the ability of the bit to drill off-axis. In some cases, directional drilling capabilities can be enhanced by employing blades with non-uniform or non-identical configurations. Bits incorporating such non-uniform blade designs are disclosed in U.S. Pat. Nos. 5,937,958 and 6,308,970, each of which is hereby incorporated herein by reference in its entirety. As will be explained in more detail below, in the embodiments of bit 110 disclosed herein, the radial location and orientation of gage pads 151, 161, 171, 181, 191, 201 are configured to offer the potential for bit 110 to drill off-axis.
Referring now to
In this embodiment, pin end 114 and full bit circumference 133 are centered relative to bit axis 111. However, gage pad circumference 134 is not centered relative to bit axis 111. Rather, gage pad circumference 134 is concentric with, and centered relative to, a gage pad axis 211 that is substantially parallel to, but offset from (i.e., not collinear), bit axis 111. In this sense, gage pad circumference 134 may be described as being offset from full bit circumference 133. In other words, full bit circumference 133 defining the full gage diameter is not concentric with gage pad circumference 134. Gage pad axis 211 may also be referred to herein as an “offset axis” since it is generally parallel with, but offset from, bit axis 111.
Referring still to
The amount or degree of radial offset from full bit circumference 133 of gage-facing surface 130 of each gage pad 151, 161, 171, 181, 191, 201 may be described by offset distances Do-151, Do-161, Do-171, Do-181, Do-191, Do-201, respectively, measured between the particular gage-facing surface 130 and the full bit circumference 133 generally perpendicular to the particular gage-facing surface 130. Thus, as used herein, the phrase “offset distance” may be used to refer to the distance between a gage-facing surface of a gage pad and the full bit circumference as measured perpendicular to the gage-facing surface. It should be appreciated that the radial offset distance of a particular gage-facing surface (e.g., gage-facing surface 130) may not be constant along its entire circumferential length. Thus, as used herein, the “offset distance” of a gage-facing surface refers to the maximum offset distance for the particular gage-facing surface relative to the full bit circumference. Still further, it should be appreciated that a gage-facing surface (e.g., gage-facing surface 130) disposed substantially at the full bit circumference (e.g., full bit circumference 133) has an offset distance of zero.
Referring still to
Although certain gage-facing surfaces 130 do not extend to full bit circumference 133, the radially outermost cutting edge of each gage trimmer 154, 164, 174, 184, 194, 204 does extend from its respective gage pad 151, 161, 171, 181, 191, 201, respectively, to full bit circumference 133. In other words, the outermost cutting tips of each gage trimmer 154, 164, 174, 184, 194, 204 circumscribes full bit circumference 133 even though the formation-facing surface 130 from which it extends is offset from full bit circumference 133. Consequently, the distance that each gage trimmer 154, 164, 174, 184, 194, 204 extends from its gage pad 151, 161, 171, 181, 191, 201, respectively, will depend on the position of gage facing surface 130 to which it is mounted. For example, formation-facing surfaces 130 of blades 170, 180 are disposed further from full bit circumference 133 than formation-facing surfaces 130 of blades 150 and 160. Consequently, gage trimmers 174, 184 associated with blades 170, 180, respectively, extend farther from their respective gage-facing surface 130 than gage trimmers 154, 164 associated with blades 150, 160, respectively.
In general, each gage-trimmer (e.g., gage-trimmer 154, 164, 174, 184, 194, 204) extends from its gage pad (e.g., gage pad 151, 161, 171, 181, 191, 201) to an extension height measured perpendicularly from the gage-facing surface to the outermost point of the gage-trimmer. As previously described, in this embodiment, each gage-trimmer 154, 164, 174, 184, 194, 204 extends from gage-facing surface 130 of gage pads 151, 161, 171, 181, 191, 201, respectively, to full bit circumference 133. Thus, in this embodiment, the extension height of each gage-trimmer 154, 164, 174, 184, 194, 204 is substantially the same as the offset distance Do-151, Do-161, Do-171, Do-181, Do-191, Do-201, respectively.
The differences in the extension heights of gage trimmers 154, 164, 174, 184, 194, 204 impact their ability to penetrate or shear the formation during drilling operations. In general, the greater the extension height of a cutter element or gage trimmer, the greater the potential depth of penetration of the cutter element or gage trimmer into the formation. For instance, gage trimmer gage trimmer 174 of blade 170 has a greater extension height than gage-trimmer 204 of blade 200, and thus, has the potential to penetrate deeper into the formation than gage-trimmer 204 before gage pad 201, 171, respectively, contact the formation. In general, once a gage-trimmer has penetrated the formation to a depth substantially equal to its extension height, the gage pad to which it is mounted will begin to contact, slide, and scrape across the formation, thereby reducing the ability of the gage trimmer to further penetrate or shear the earthen formation. Without being limited by this or any particular theory, such reduction in the gage-trimmers ability to further penetrate the formation results because the forces exerted on the formation become distributed over the entire surface area of gage-facing surface (e.g., gage-facing surface 130) of the gage pad (e.g., gage pad 151) rather than being purely concentrated at the tips of the gage trimmer. Consequently, the force per unit area exerted on the formation is reduced, thereby reducing the ability of the gage trimmer to penetrate or shear the formation material. Thus, gage trimmers with greater extension heights tend to penetrate further into the formation, and hence shear the formation more effectively, as compared to gage trimmers with smaller extension heights.
In the embodiment shown in
In this manner, embodiments of bit 110 include gage trimmers 154, 164, 174, 184, 194, 204 having different extension heights and different formation penetrating capabilities. In general, the greater the extension height of the gage trimmer, the greater its formation engaging and cutting ability. Thus, by selectively controlling the extension height of gage trimmers 154, 164, 174, 184, 194, 204, the formation penetrating ability and cutting effectiveness of each gage trimmer 154, 164, 174, 184, 194, 204 may be varied and controlled.
Referring briefly to
Without being limited by this or any particular theory, for a drill bit without gage cutter relief (e.g., a drill bit without gage-trimmers extending from the gage-facing surface), the radial, restoring forces urging the drill bit back to the vertical orientation may not be sufficient to activate side cutting of the borehole sidewall and allow the bit to return to the vertical drilling direction. Instead, such restoring forces will be distributed across the relatively large surface area of the gage-facing surfaces, thereby reducing the force per unit area acting on the borehole sidewall. However, embodiments described herein (e.g., embodiments of bit 110) include gage trimmers (e.g., gage trimmers 164, 174, 184, 194, 204) that extend from their respective gage pad (e.g., gage pads 161, 171, 181, 191, 201). In such embodiments, the radial, restoring forces, acting on the bit are, at least initially, concentrated at the tips of the gage-trimmers, each having a relatively small surface area. The force per unit area exerted on the formation by such gage-trimmers may exceed the formation strength, and thus, begin to shear the borehole sidewall and activate side cutting in the direction of the radial, restoring force. Consequently, embodiments of bit 110 offer the potential for drilling and formation penetration in a direction that is not parallel with the longitudinal axis 111 of bit 110. More specifically, embodiments of bit 110 offer the potential for a drill bit that tends to return to a vertical upon deviation therefrom. It should also be appreciated that in addition to the weight vector of the drill string acting on the drill bit, a bending moment in the drill string may also urge the drill bit into the lower side of the borehole in the direction of zero deviation from vertical.
The nature of a PDC cutting structure layout (e.g., blades and cutter elements) typically results in an asymmetric distribution of forces about the bit. In some cases, such asymmetric forces can lead to force imbalances that may result in bit vibrations, or possibly bit whirl. As previously described, vibrations and bit whirl can lead to unpredictable, and potentially damaging, forces acting on the cutter elements and gage-trimmers, particularly, during side cutting and directional drilling operations. However, asymmetric gage pad circumference 134 and non-uniform extension heights of gage-trimmers 154, 164, 174, 184, 194, 204 of bit 110 offer the potential to resist vibration and whirl. More specifically, the positioning and orientation of each gage-facing surface 130 and each gage trimmers 154, 164, 174, 184, 194, 204 may be selected to control the loading of each gage-trimmer 154, 164, 174, 184, 194, 204. In particular, the circumferential position and radial position of each gage-facing surface 130 (i.e., offset distances Do-151, Do-161, Do-171, Do-181, Do-191, Do-201), as well as the extension height of each gage-trimmer 154, 164, 174, 184, 194, 204 may be designed and configured to minimize the imbalance forces generated by cutting structure 115. For instance, in an embodiment, the circumferential position of each gage pad 151, 161, 171, 181, 191, 201 relative to full gage circumference 133, the offset distances Do-151, Do-161, Do-171, Do-181, Do-191, Do-201 of each gage-facing surface 130, and the extension heights 154, 164, 174, 184, 194, 204 of each gage-trimmer 154, 164, 174, 184, 194, 204 may be selected to counteract the anticipated imbalance forces generated by cutting structure 115. Such a bit with minimized net imbalanced forces offers the potential for reduced vibrations and whirl, and hence, more durability. In another embodiment, the circumferential position of each gage pad 151, 161, 171, 181, 191, 201 relative to full gage circumference 133, the offset distances Do-151, Do-161, Do-171, Do-181, Do-191, Do-201 of each gage-facing surface 130, and the extension heights 154, 164, 174, 184, 194, 204 of each gage-trimmer 154, 164, 174, 184, 194, 204 may be selected to enhance side cutting tendencies of cutting structure 115.
Various techniques may be employed to manufacture the embodiment of
While specific embodiments have been shown and described, modifications thereof can be made by one skilled in the art without departing from the scope or teaching herein. The embodiments described herein are exemplary only and are not limiting. For example, embodiments described herein may be applied to any bit layout including, without limitation, single set bit designs where each cutter element has unique radial position along the rotated cutting profile, plural set bit designs where each cutter element has a redundant cutter element in the same radial position provided on a different blade when viewed in rotated profile, forward spiral bit designs, reverse spiral bit designs, or combinations thereof. In addition, embodiments described herein may also be applied to straight blade configurations or helix blade configurations. Many other variations and modifications of the system and apparatus are possible. For instance, in the embodiments described herein, a variety of features including, without limitation, the number of blades (e.g., primary blades, secondary blades, etc.), the spacing between cutter elements, cutter element geometry and orientation (e.g., backrake, siderake, etc.), cutter element locations, cutter element extension heights, cutter element material properties, or combinations thereof may be varied among one or more primary cutter elements and/or one or more backup cutter elements. Accordingly, the scope of protection is not limited to the embodiments described herein, but is only limited by the claims that follow, the scope of which shall include all equivalents of the subject matter of the claims.
This application claims benefit of U.S. provisional application Ser. No. 60/808,873 filed May 26, 2006, and entitled “Drill Bit With Gage Pad Configuration To Enhance Off-Axis Drilling Capability,” which is hereby incorporated herein by reference in its entirety.
Number | Date | Country | |
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60808873 | May 2006 | US |