GB2426533A - Stable rotary drill bit - Google Patents
Stable rotary drill bit Download PDFInfo
- Publication number
- GB2426533A GB2426533A GB0609742A GB0609742A GB2426533A GB 2426533 A GB2426533 A GB 2426533A GB 0609742 A GB0609742 A GB 0609742A GB 0609742 A GB0609742 A GB 0609742A GB 2426533 A GB2426533 A GB 2426533A
- Authority
- GB
- United Kingdom
- Prior art keywords
- blades
- drill bit
- additional
- cutting
- outer region
- Prior art date
- Legal status (The legal status is an assumption and is not a legal conclusion. Google has not performed a legal analysis and makes no representation as to the accuracy of the status listed.)
- Granted
Links
- 239000010432 diamond Substances 0.000 claims description 16
- 229910003460 diamond Inorganic materials 0.000 claims description 15
- 239000000463 material Substances 0.000 claims description 9
- 239000013078 crystal Substances 0.000 claims description 4
- 239000011248 coating agent Substances 0.000 claims description 3
- 238000000576 coating method Methods 0.000 claims description 3
- 238000005552 hardfacing Methods 0.000 claims description 2
- 230000015572 biosynthetic process Effects 0.000 description 15
- 238000005755 formation reaction Methods 0.000 description 15
- 238000005553 drilling Methods 0.000 description 10
- 239000012530 fluid Substances 0.000 description 5
- 230000004048 modification Effects 0.000 description 2
- 238000012986 modification Methods 0.000 description 2
- 230000035515 penetration Effects 0.000 description 2
- 239000011435 rock Substances 0.000 description 2
- 239000000758 substrate Substances 0.000 description 2
- UONOETXJSWQNOL-UHFFFAOYSA-N tungsten carbide Chemical compound [W+]#[C-] UONOETXJSWQNOL-UHFFFAOYSA-N 0.000 description 2
- 230000004075 alteration Effects 0.000 description 1
- 230000015556 catabolic process Effects 0.000 description 1
- 238000006731 degradation reaction Methods 0.000 description 1
- 230000001419 dependent effect Effects 0.000 description 1
- 238000010586 diagram Methods 0.000 description 1
- 230000000977 initiatory effect Effects 0.000 description 1
- 238000011068 loading method Methods 0.000 description 1
Classifications
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH OR ROCK DRILLING; MINING
- E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B10/00—Drill bits
- E21B10/42—Rotary drag type drill bits with teeth, blades or like cutting elements, e.g. fork-type bits, fish tail bits
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH OR ROCK DRILLING; MINING
- E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B10/00—Drill bits
- E21B10/42—Rotary drag type drill bits with teeth, blades or like cutting elements, e.g. fork-type bits, fish tail bits
- E21B10/43—Rotary drag type drill bits with teeth, blades or like cutting elements, e.g. fork-type bits, fish tail bits characterised by the arrangement of teeth or other cutting elements
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH OR ROCK DRILLING; MINING
- E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B10/00—Drill bits
- E21B10/46—Drill bits characterised by wear resisting parts, e.g. diamond inserts
- E21B10/54—Drill bits characterised by wear resisting parts, e.g. diamond inserts the bit being of the rotary drag type, e.g. fork-type bits
Landscapes
- Engineering & Computer Science (AREA)
- Life Sciences & Earth Sciences (AREA)
- Geology (AREA)
- Mining & Mineral Resources (AREA)
- Mechanical Engineering (AREA)
- Physics & Mathematics (AREA)
- Environmental & Geological Engineering (AREA)
- Fluid Mechanics (AREA)
- General Life Sciences & Earth Sciences (AREA)
- Geochemistry & Mineralogy (AREA)
- Earth Drilling (AREA)
- Processing Of Stones Or Stones Resemblance Materials (AREA)
Abstract
A drill bit (10) comprises a bit body having a plurality of upstanding main blades (18) formed with a plurality cutting elements mounted thereon. The cutting profile of the bit includes a nose portion, an inner cone region located radially inwards of the nose portion and an outer region located radially outwards of the nose portion. The bit further has at least one additional blade (30). The additional blade carrying cutting elements located radially inwards of the outer region of the cutting profile, but being substantially free of cutting elements located in the outer region of the cutting profile. The additional blades are located to balance lateral forces.
Description
2426533
1
"Stable Rotary Drill Bit"
This invention relates to a rotary drill bit that is vibrationally stable, and in 5 particular to a rotary drill bit suitable for use in the formation of subterranean well bores.
The cost of drilling a borehole in the subsurface formations of the Earth is dependent on the length of time taken to drill the borehole to the desired depth. 10 The time spent drilling is in turn determined by the rate of penetration and the number of times the drill bit has to be changed in order to achieve the target depth.
A known form of drill bit for use in the formation of subterranean well bores 15 comprises a bit body having formed thereon a series of upstanding blades. Each blade is provided with a series of cutting elements. The cutting elements each typically comprise a substrate of, for example, tungsten carbide to which is bonded a table of a superhard material, for example in the form of polycrystalline diamond. Between the blades are formed flow channels to which drilling fluid is 20 supplied in use, the drilling fluid serving to clean and cool the cutting elements and to carry away material removed by the drill bit.
In use, the drill bit is rotated about its axis while an axially directed load is applied thereto. As a result, material is gouged, scraped or abraded from the 25 formation in which the bore hole is being formed, the material being carried away, as hereinbefore described, by the drilling fluid.
The cutting elements naturally wear away in use due to the varying abrasive nature of the subsurface rock formations. In practice however, the expected 30 economic life of the known drill bits is often degraded due to the cutters being chipped or broken.
In these cases, the known drill bits are known to suffer from lateral and torsional vibrations, and these vibrations cause the known drill bit to deviate from its desired smooth path through the formation. This results in the application of large loadings to the cutting elements mounted on the bit which may cause damage thereto, which results in greatly accelerated degradation of the cutting elements. This is particularly apparent when drilling rock formations with bits of relatively large diameter. Obviously this is undesirable and it is an object of the invention to provide a drill bit of improved stability.
According to the present invention there is provided a drill bit comprising a bit body having a plurality of upstanding main blades formed thereon, the blades having a plurality cutting elements mounted thereon, the blades being shaped such that a cutting profile of the bit includes a nose portion, an inner cone region located radially inwards of the nose portion and an outer region located radially outwards of the nose portion, the bit further comprising at least one additional blade, the additional blade carrying cutters located radially inwards of the outer region, but being substantially free of cutters located in the outer region.
Such an arrangement is advantageous in that the number of cutters located in the cone region, relative to the number of cutters on the outer region, can be increased, and these additional cutters create a restoring force to prevent the drill bit moving off its center of rotation while drilling. This can be used to achieve an improvement in bit stability, reducing lateral vibration thereof.
The outer regions of the additional blades are conveniently of increased blade height as compared to the outer regions of the main blades. As a result, during drilling, the outer regions of the additional blades can bear against the surface of the formation being drilled, thereby limiting the depth of cut achievable by the cutting elements, and this can be used to limit lateral and torsional vibration
3
Although applicable to drill bits of relatively small diameter, the invention is particularly applicable to large diameter drill bits, for example bits of diameter falling within the range of approximately 12 1/4" to 26".
The cutting elements preferably comprise polycrystalline diamond compact cutters, but other arrangements are possible, for example the cutting elements could comprise diamond crystals, or polycrystalline diamonds, mounted upon or embedded in the blades.
The outer surface of the outer regions of the additional blades may be rendered of improved resistance to wear. This could be achieved for example by mounting suitably shaped and positioned, non-cutting, polycrystalline diamond compact 15 elements thereon. Alternatively, or additionally, a hard facing material coating may be applied thereto.
The invention will further be described, by way of example, with reference to the 20 accompanying drawings.
Figure 1 is a diagrammatic view of a typical known drill rig and a section through a portion of the Earth where a borehole is being drilled.
25 Figure 2 is an end view of a drill bit in accordance with one embodiment of the invention.
Figure 3 is a perspective view of the drill bit of Figure 2.
30
Figure 4 is a side view of the drill bit of Figure 2.
4
Figure 5 is a diagram illustrating the cutting profile of the bit of Figure 2.
Figure 6 is a view similar to Figure 2 of an alternative embodiment of a drill bit of 5 the invention.
Figure 7 is a sectional view along the line 7-7 of Figure 6.
10 Referring first to Figure 1, a drilling system 1, is shown and comprises a drill rig 2, with a drill string 3, and a drill bit 6, located within borehole 5. The drill bit 6 may be rotated from the surface by rotation of the drill string. Alternatively or additionally the drill bit 6, may be rotated by a downhole motor or turbine 4.
15 Referring to Figures 2 to 5 there is shown a drill bit comprising a bit body 10
having a front face 12 and a connection region 14 designed to allow the bit to be connected to other downhole components, in use, to allow the bit to be driven for rotation about its centerline 16 and to allow an axially directed load to be applied thereto.
20
Mounted on the bit body 10 are a number of upstanding main blades 18, the main blades 18 upstanding from the front face 12 of the bit body 10. The main blades 18 include a first plurality of blades 18a which extend from the center line 16, of the bit to the gauge region 20 thereof, and a second plurality of blades 18b which
25 stop short of the center line 16, of the bit. These upstanding main blades 18 may be integrally formed on the bit body, or alternately, may be formed separately and later attached to the bit body 10. The gauge regions 20 of the main blades 18 are of substantially uniform gauge length, the gauge regions 20 all being located at the same axial position on the bit.
30
5
As can be seen most clearly in Figures 4 and 5, the main blades 18 are shaped to define a bit profile 21 including a nose portion 22 of annular shape located at the axially most remote part of the bit from the connection region. Radially inward of the nose portion 22 is a cone region 24, and radially outward of the nose 5 portion 22 is an outer region 26.
The main blades 18 each carry a series of cutting elements 28. Each cutting element 28 is in the form of a polycrystalline diamond compact comprising a table of polycrystalline diamond which is bonded to a substrate of less hard 10 material, typically tungsten carbide. The cutting elements 28 are located on parts of the blades 18 in the cone region 24, at the nose portion 22 and in the outer region 26.
Back-up cutting elements 28a are provided immediately behind, and at the same 15 general radial position as at least some of the cutting elements 28, in a known manner.
In addition to the main blades 18, the bit body 10 is further provided with a 20 plurality of additional blades 30. As illustrated, each additional blade 30 is located immediately behind an associated one of the main blades 18b, the additional blades 30 being substantially equally spaced apart around the bit body 10. Each additional blade 30 includes a part located in the cone region 24, a part located at the nose portion 22 and a part located in the outer region 26, and 25 includes a gauge region aligned with the gauge regions 20 of the main blades 18.
Between the main blades 18a, 18b and the additional blades 30 are formed a series of flow channels 32 to which drilling fluid is supplied, in use, through passages (not shown) located internally of the bit and through nozzles 34. The
6
fluid serves to clean and cool the cutting elements, and also serves to carry away from the bit formation material which, in use, is removed by the cutting elements.
5 Like the main blades 18, the additional blades 30 are also adapted to carry a series of cutting elements 28. The cutting elements 28 carried by the additional blades 30 are located radially inwards of the outer region 26, being located only in the cone region 24 and the nose portion 22, while the outer region 26 is free of cutting elements 28. The provision of the cutters 28 only in the cone region 24 10 and nose portion 22 of the additional blades 30 serves to enhance the stability of the bit. This is because, in order to reduce lateral vibrations, it is important for the lateral forces generated by the cutting elements to be balanced. Where the bit is of large diameter, as in the arrangement illustrated, this is usually difficult as the torque generated by the radially outer cutting elements is high compared to 15 the torque generated by the inner cutting elements. The location of the cutting elements on the additional blades 30 only at relatively small radial distances from the axis enables this part of the bit to carry a disproportionately large number of cutting elements, and thereby allows such balancing to be achieved more easily.
20 The parts of the additional blades 30 in the outer regions 26 are, as mentioned hereinbefore, devoid of cutters, and will be referred to hereinafter as cutter devoid surfaces 36. In addition to being devoid of cutters, the cutter devoid surfaces are designed to be of larger blade height than the corresponding parts of the main blades 18 with the result that engagement of the cutter devoid surfaces 36 with the 25 formation being drilled, in use, limits the depth of cut achievable by the bit.
In use, the bit is located downhole and is driven for rotation about its axis 16. An axially directed load sometimes referred to as weight-on-bit is applied to the bit. 30 The combination of the rotary motion and the weight-on-bit causes the cutters 28
7
to gouge, scrape or abrade material from the formation, thereby extending the borehole. Changes in the applied weight-on-bit or changes in the formation being drilled can give rise to changes in the depth of cut and this, in turn, can cause torsional vibrations to occur. With the bit described hereinbefore, the maximum 5 depth of cut is limited by the engagement of the cutter devoid surfaces 36 with the formation being drilled. As a result, variations in depth of cut are reduced and the severity of torsional vibrations can be limited, or the initiation of such vibrations can be avoided.
10 As the cutter devoid surfaces 36 will, in use, bear against the formation being drilled, at least for some of the time, the surfaces 36 may be subject to wear. In order to limit such wear, a wear resistant coating may be applied thereto. Alternatively, a series of wear resistant inserts, for example in the form of suitably shaped polycrystalline diamond compacts, may be mounted upon the 15 surfaces 36.
Figures 6 and 7 illustrate an alternative embodiment, which, in many respects, is the same as that illustrated in Figures 2 to 5. The biggest difference between the two embodiments is in the number of blades provided, the Figure 6 embodiment 20 includes four main blades 18a, four main blades 18b and four additional blades 30. Figure 7 illustrates the profile of the additional blades 30, the profile of the corresponding parts of the main blades 18 being represented by the dotted line 38, thereby illustrating the difference in blade heights of the blades 18, 30. Specifically, the cutter devoid surfaces 36 of the additional blades 30 are at a 25 greater blade height than the corresponding parts of the main blades 18.
It will be appreciated that a range of modifications and alterations may be made to the arrangements described hereinbefore without departing from the scope of the invention. For example, rather than using polycrystalline diamond compacts as 30 the cutting elements, it may be possible to use diamond crystals or polycrystalline
8
diamond mounted upon or embedded in the blades 18,30. Further, alternative means may be used to render the cutter devoid surfaces of good wear resistance. A further possibility may be to shape the cutter devoid surfaces so as to match the actual shape of the bottom hole surface created by the cutter elements 28, at the 5 desired rate of penetration. As a result, the Ml surface area of each cutter devoid surface can be arranged to engage the formation being drilled.
Whereas the present invention has been described in particular relation to the drawings attached hereto, it should be understood that other and further 10 modifications apart from those shown or suggested herein, may be made within the scope and spirit of the present invention.
9
Claims (14)
1. A drill bit comprising a bit body having a plurality of upstanding main 5 blades formed thereon, the main blades having a plurality cutting elements mounted thereon, the main blades being shaped such that a cutting profile of the bit includes a nose portion, an inner cone region located radially inwards of the nose portion and an outer region located radially outwards of the nose portion, the bit further comprising at least one additional blade, the additional blade carrying 10 cutting elements located radially inwards of the outer region of the cutting profile, but being substantially free of cutting elements located in the outer region of the cutting profile, wherein the cutting elements provided on the main blades and on the additional blades are located such that the lateral forces generated by the cutting elements, in use, are substantially balanced.
15
2. A drill bit according to Claim 1, wherein a part of the additional blade located in the outer region of the cutting profile is of increased blade height as compared to parts of the main blades located in the outer region of the cutting profile.
20
3. A drill bit according to Claim 1 or Claim 2, wherein the bit has a diameter falling within the range of about 12 1/4" to 26".
4. A drill bit according to any of the preceding claims, wherein the cutting 25 elements comprise polycrystalline diamond compact cutters.
5. A drill bit according to any of Claims 1 to 3, wherein the cutting elements comprise diamond crystals mounted upon or embedded in the main and additional blades.
30
10
6. A drill bit according to any of Claims 1 to 3, wherein the cutting elements comprise polycrystalline diamond crystals mounted upon or embedded in the main and additional blades.
5
7. A drill bit according to any of the preceding claims, wherein an outer surface of a part of the additional blade located in the outer region of the cutting profile is rendered of improved resistance to wear.
10
8. A drill bit according to Claim 7, wherein the said part of the additional blade located in the outer region is rendered of improved resistance to wear by having suitably shaped and positioned, non-cutting, polycrystalline diamond compact elements mounted thereon.
15
9. A drill bit according to Claim 7, wherein the said part of the additional blade located in the outer region is rendered of improved resistance to wear by having a hard facing material coating applied thereto.
10. A drill bit according to Claim 7, wherein the said part of the additional blade 20 is rendered of improved resistance to wear by having TSP tiles or diamond impregnated inserts mounted thereoa
11. A drill bit according to any of the preceding claims, wherein the plurality of main blades comprise a first plurality of blades which extend inwardly to a
25 centerline of the bit body, and a second plurality of blades which stop short of the centerline of the bit body.
12. A drill bit according to any of the preceding claims, wherein a plurality of the additional blades are provided, the additional blades being substantially
30 equally spaced around the bit body.
11
13. A drill bit according to any of the preceding claims, wherein the main blades and the additional blades each have a gauge region, the gauge regions being of substantially uniform length and being aligned with one another.
14. A drill bit substantially as hereinbefore described with reference to the accompanying drawings.
Applications Claiming Priority (1)
| Application Number | Priority Date | Filing Date | Title |
|---|---|---|---|
| GBGB0510010.2A GB0510010D0 (en) | 2005-05-17 | 2005-05-17 | Rotary drill bit |
Publications (3)
| Publication Number | Publication Date |
|---|---|
| GB0609742D0 GB0609742D0 (en) | 2006-06-28 |
| GB2426533A true GB2426533A (en) | 2006-11-29 |
| GB2426533B GB2426533B (en) | 2010-07-21 |
Family
ID=34708279
Family Applications (2)
| Application Number | Title | Priority Date | Filing Date |
|---|---|---|---|
| GBGB0510010.2A Ceased GB0510010D0 (en) | 2005-05-17 | 2005-05-17 | Rotary drill bit |
| GB0609742A Active GB2426533B (en) | 2005-05-17 | 2006-05-17 | Stable rotary drill bit |
Family Applications Before (1)
| Application Number | Title | Priority Date | Filing Date |
|---|---|---|---|
| GBGB0510010.2A Ceased GB0510010D0 (en) | 2005-05-17 | 2005-05-17 | Rotary drill bit |
Country Status (2)
| Country | Link |
|---|---|
| US (1) | US20060260845A1 (en) |
| GB (2) | GB0510010D0 (en) |
Cited By (1)
| Publication number | Priority date | Publication date | Assignee | Title |
|---|---|---|---|---|
| EP2705208A4 (en) * | 2011-05-05 | 2015-11-25 | Baker Hughes Inc | Earth-boring tools and methods of forming such earth-boring tools |
Families Citing this family (20)
| Publication number | Priority date | Publication date | Assignee | Title |
|---|---|---|---|---|
| US20070261890A1 (en) * | 2006-05-10 | 2007-11-15 | Smith International, Inc. | Fixed Cutter Bit With Centrally Positioned Backup Cutter Elements |
| CA2605196C (en) | 2006-10-02 | 2011-01-04 | Smith International, Inc. | Drag bits with dropping tendencies and methods for making the same |
| US7703557B2 (en) * | 2007-06-11 | 2010-04-27 | Smith International, Inc. | Fixed cutter bit with backup cutter elements on primary blades |
| US8915166B2 (en) * | 2007-07-27 | 2014-12-23 | Varel International Ind., L.P. | Single mold milling process |
| US8869919B2 (en) | 2007-09-06 | 2014-10-28 | Smith International, Inc. | Drag bit with utility blades |
| US7926596B2 (en) * | 2007-09-06 | 2011-04-19 | Smith International, Inc. | Drag bit with utility blades |
| US9016407B2 (en) | 2007-12-07 | 2015-04-28 | Smith International, Inc. | Drill bit cutting structure and methods to maximize depth-of-cut for weight on bit applied |
| US8100202B2 (en) | 2008-04-01 | 2012-01-24 | Smith International, Inc. | Fixed cutter bit with backup cutter elements on secondary blades |
| CA2773336C (en) * | 2009-04-02 | 2017-08-22 | Newtech Drilling Products, Llc | Drill bit for earth boring |
| WO2011038383A2 (en) * | 2009-09-28 | 2011-03-31 | Bake Hughes Incorporated | Earth-boring tools, methods of making earth-boring tools and methods of drilling with earth-boring tools |
| US8327957B2 (en) * | 2010-06-24 | 2012-12-11 | Baker Hughes Incorporated | Downhole cutting tool having center beveled mill blade |
| US9464490B2 (en) * | 2012-05-03 | 2016-10-11 | Smith International, Inc. | Gage cutter protection for drilling bits |
| EP2890863A4 (en) | 2012-08-31 | 2016-07-20 | Halliburton Energy Services Inc | System and method for analyzing downhole drilling parameters using an opto-analytical device |
| WO2014035427A1 (en) | 2012-08-31 | 2014-03-06 | Halliburton Energy Services, Inc. | System and method for measuring gaps using an opto-analytical device |
| WO2014035426A1 (en) | 2012-08-31 | 2014-03-06 | Halliburton Energy Services, Inc. | System and method for detecting vibrations using an opto-analytical device |
| US9957792B2 (en) | 2012-08-31 | 2018-05-01 | Halliburton Energy Services, Inc. | System and method for analyzing cuttings using an opto-analytical device |
| US9945181B2 (en) | 2012-08-31 | 2018-04-17 | Halliburton Energy Services, Inc. | System and method for detecting drilling events using an opto-analytical device |
| CA2883525C (en) | 2012-08-31 | 2018-10-23 | Halliburton Energy Services, Inc. | System and method for measuring temperature using an opto-analytical device |
| CA2883250C (en) | 2012-08-31 | 2019-02-26 | Halliburton Energy Services, Inc. | System and method for determining torsion using an opto-analytical device |
| US10125550B2 (en) * | 2013-09-11 | 2018-11-13 | Smith International, Inc. | Orientation of cutting element at first radial position to cut core |
Citations (2)
| Publication number | Priority date | Publication date | Assignee | Title |
|---|---|---|---|---|
| US4602691A (en) * | 1984-06-07 | 1986-07-29 | Hughes Tool Company | Diamond drill bit with varied cutting elements |
| US6349780B1 (en) * | 2000-08-11 | 2002-02-26 | Baker Hughes Incorporated | Drill bit with selectively-aggressive gage pads |
Family Cites Families (8)
| Publication number | Priority date | Publication date | Assignee | Title |
|---|---|---|---|---|
| US5042596A (en) * | 1989-02-21 | 1991-08-27 | Amoco Corporation | Imbalance compensated drill bit |
| US5010789A (en) * | 1989-02-21 | 1991-04-30 | Amoco Corporation | Method of making imbalanced compensated drill bit |
| US4982802A (en) * | 1989-11-22 | 1991-01-08 | Amoco Corporation | Method for stabilizing a rotary drill string and drill bit |
| US5178222A (en) * | 1991-07-11 | 1993-01-12 | Baker Hughes Incorporated | Drill bit having enhanced stability |
| US5163524A (en) * | 1991-10-31 | 1992-11-17 | Camco Drilling Group Ltd. | Rotary drill bits |
| GB2296272B (en) * | 1994-12-20 | 1998-03-18 | Smith International | Self-centering polycrystalline diamond drill bit |
| US5967245A (en) * | 1996-06-21 | 1999-10-19 | Smith International, Inc. | Rolling cone bit having gage and nestled gage cutter elements having enhancements in materials and geometry to optimize borehole corner cutting duty |
| US6575256B1 (en) * | 2000-01-11 | 2003-06-10 | Baker Hughes Incorporated | Drill bit with lateral movement mitigation and method of subterranean drilling |
-
2005
- 2005-05-17 GB GBGB0510010.2A patent/GB0510010D0/en not_active Ceased
-
2006
- 2006-05-10 US US11/382,571 patent/US20060260845A1/en not_active Abandoned
- 2006-05-17 GB GB0609742A patent/GB2426533B/en active Active
Patent Citations (2)
| Publication number | Priority date | Publication date | Assignee | Title |
|---|---|---|---|---|
| US4602691A (en) * | 1984-06-07 | 1986-07-29 | Hughes Tool Company | Diamond drill bit with varied cutting elements |
| US6349780B1 (en) * | 2000-08-11 | 2002-02-26 | Baker Hughes Incorporated | Drill bit with selectively-aggressive gage pads |
Cited By (1)
| Publication number | Priority date | Publication date | Assignee | Title |
|---|---|---|---|---|
| EP2705208A4 (en) * | 2011-05-05 | 2015-11-25 | Baker Hughes Inc | Earth-boring tools and methods of forming such earth-boring tools |
Also Published As
| Publication number | Publication date |
|---|---|
| GB0510010D0 (en) | 2005-06-22 |
| GB2426533B (en) | 2010-07-21 |
| GB0609742D0 (en) | 2006-06-28 |
| US20060260845A1 (en) | 2006-11-23 |
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