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Publication numberUS3180440 A
Publication typeGrant
Publication dateApr 27, 1965
Filing dateDec 31, 1962
Priority dateDec 31, 1962
Publication numberUS 3180440 A, US 3180440A, US-A-3180440, US3180440 A, US3180440A
InventorsBridwell Harold C
Original AssigneeJersey Prod Res Co
Export CitationBiBTeX, EndNote, RefMan
External Links: USPTO, USPTO Assignment, Espacenet
Drag bit
US 3180440 A
Abstract  available in
Images(1)
Previous page
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Claims  available in
Description  (OCR text may contain errors)

April 27, 1965 H. c. BRIDWELL 3,180,440

DRAG BIT Filed Dec. 31, 1962 Harold C. Bridwell INVENTOR BY E Qul ATTORNEY United States Patent 3,180,446 DRAG BIT Harold C. Bridwell, Tulsa, Olden, assignor to Jersey Production Research Company, a corporation of Delaware Filed Dec. 31, 1962, Ser. No. 248,728

7 Claims. (Cl. 175393) The present invention relates to rotary drill bits and is particularly concerned with an improved drag bit for drilling oil wells, gas wells and similar boreholes.

Many of the difficulties encountered with drag bits used in the mining and petroleum industries are due to failure of the blades at the gage surfaces. Experience has shown that gage wear is generally severe with such bits, in part because of continued impact of the blades against the borehole wall and the entrapment and regrinding of cuttings between the gage surfaces and adjacent formation. Such wear results in a reduction in bit diameter and promotes the formation of a rounded contour at the lower end of the tool. The reduced bit diameter normally produces a corresponding change in the diameter of the borehole which may necessitate reaming of the hole before the next bit can be lowered into place. Wedging of the bit in the borehole may occur as a result of the rounded blade contour unless bit weight is controlled and penetration rates are kept low. Efforts to avoid these and related problems attributed to gage wear by increasing blade thickness and employing tungsten carbide or a similar abrasion-resistant material on the gage surfaces have been only partially successful and hence the use of drag bits has generally been restricted to relatively soft, non-abrasive formations.

It is therefore an object of the present invention to provide an improved drag bit which will wear less rapidly at the gage surfaces than drag bits available in the past. Another object is to reduce gage Wear caused by impact of the blades against the borehole Wall and the accumulation and regrinding of cuttings between the gage surfaces and formation. A further object is to alleviate the necessity for reaming the borehole and unduly restricting bit weight during drag bit drilling operations. Still other objects will become apparent as the invention is described in greater detail hereafter.

In accordance with the invention, it has now been found that many of the diiliculties due to gage wear encountered with drag bits available in the past can be alleviated by providing laterally-projecting surfaces or pads in front of the blades and mounting nozzles in the pads near the gage edges. Studies have shown that such pads contact the borehole wall in advance of the blades and thus reduce impact loading. The mounting of nozzles in the pads near the gage edges of the blades so that the fiuid discharged impinges against the formation near the lower gage corner of each blade minimizes the entrapment and regrinding of cuttings between the blades and formation and providesmuch more effective cleaning near the gage edges than is generally obtained with conventional tools. Due to the reduced impact and better entrainment of cuttings adjacent the blades, the rate at which gage wear occurs is significantly reduced and hence the difiiculties outlined above are to a large extent avoided.

The nature and objects of the invention can best be understood by referring to the following detail descrip- 3,18%,4dh Patented Apr. 2?, 1965 tion of a preferred embodiment of the improved drag bit and to the accompanying drawing, in which:

FIGURE 1 is a vertical elevation, partially in section, of a drag bit provided with pads containing nozzles mounted in front of the blades near the gage edges;

FIGURE 2 is a vertical elevation of the bit shown in FIGURE 1 rotated about the longitudinal axis; and,

FIGURE 3 is a bottom view of the bit shown in FIGURES 1 and 2 of the drawing.

The bit depicted in FIGURE 1 of the drawing includes a hollow body member 11 constructed of steel, cast iron or similar material. The body member is of generally cylindrical shape and includes a standard ARI. tool joint box 12 near the upper end to permit its connection to the lower end of a rotary drill string. Other connecting means may be used in lieu of an A.P.I. tool joint if desired. The lower portion of the body member is provided with lateral projections or pads 13 and 14, only one of which appears in FIGURE 1. Each pad projects outwardly from the body member through a horizontal angle of from about 15 to about 90 and extends vertically from a point near the bottom of the body to a point about midway between the bottom and the lower end of the tool joint. Pads extending through an angle between about 15 and about 45 are generally preferred. The leading faces of the pads, indicated by reference numerals 15 and 16, preferably extend radially from the body as shown in FIGURE 3 in order to prevent wedging of cuttings between the pads and the borehole wall. The upper end of each pad may slope backwardly to produce a spiral configuration if desired. The pads may be cast or machined as integral parts of the body, may be produced separately and then welded in place as shown, or may be fabricated with and attached as parts of the blades of the bit.

The gage surfaces of the pads on the bit shown are hard surfaced with tungsten carbide or a similar abrasionresistant material indicated by reference numerals 17 and 18 in order to reduce gage wear. The tungsten carbide or other hard metal may be applied to the pads with a torch or may be bonded in place by infiltration or a similar technique. Inserts 19 of sintered hard metal carbide or similar material are embedded in the gage surfaces to further increase resistance to abrasion.

Blades 20 and 21 are connected to and depend from body member 11 adjacent the pads. As indicated in FIGURES 2 and 3 of the drawing, each blade is mounted at the rear of a pad and projects outwardly to the gage surface of the pad. The blades shown are cast or machined to fit closely against the body and pads and are welded in place. Alternatively, each blade and the corresponding pad may be fabricated as an integral unit and the entire structure may then be welded or otherwise mounted in the proper position on the body member. The blades shown are stepped across the bottom and are thus provided with lower cutting edges 22 and 23, intervening cutting edges 24 and 25, and upper cutting edges 26 and 27. This results in the maintaining of a stepped core below the body which assists in centering the bit in the bore hole and generally promotes smoother operation. The rear surface of each blade is preferably tapered above each cutting edge in order to reduce the blade area in contact with the formation at the bottom of the borehole and thus permit higher drilling rates than might otherwise be obtained.

The' leading faces of the blades on the bit shown in the drawing are hard surfaced with a binder metal 28 containing particles 29 of tungsten carbide, a tungsten carbide alloy, or a similar abrasion-resistant material preferably having a Rockwell A hardness in excess of about 85. A variety of metallic binders may be employed, including copper-nickel I alloys, copper-nickel-tin alloys, copper-nickel-manganese alloys, iron-carbon alloys, ironnickel-manganese alloys, S-monel and the like. Powdered tungsten carbide or similar hard metal granules may-be added to the matrix metal to increase its strength and abrasion resistance. The hard metal particles on the faces of the blades shown are irregularly-shaped particles or chips of tungsten carbide or the like ranging between about 4; and about inch in size. The gage edges are hard surfaced with similar material and in addition contain cubes of sintered tungsten carbide 30 embedded in a regular pattern on the lower portions of the blades in order to further increase abrasion resistance. Embedded diamonds may also be employed on the gage edges. 7 I

Nozzles 31 and 32 are mounted in the lower surfaces of the pads in front of the blades. Each nozzle is located I ma passageway 33 which extends from the interior 34 of the body to an opening in the pad near the gage edge. of the adjacent'blade. These passageways are preferably lined with tubes 35 of tungsten carbide or the like in order to reduce erosion by thedrilling fluid. The nozzles are made of similar erosion-resistant material and may be either welded in place as shown or secured by means of snap rings, pins or other members which fit into recesses in the body adjacent the outer surfaces of the nozzles. The use of replaceable nozzles held in place by snap rings or the like permits nozzle changes inthe field and'i s therefore preferred. The nozzlev axes extend in a substantially vertical direction toward points a short distance in front of the blades near the lower gage corners. Fluid parallel to the face and gage surfaces of. the blades and impinges against the. formation adjacent the outer step of each blade. v

The bit shown inthe drawing may be utilized with a "conventional rotary drill string and ordinary surface equipment. The bit is connected to the lower edge of the drill string and lowered into the borehole in the usual manner. Drilling fluid is circulated downwardly through the string and returned through the annulus between the drill string and the borehole wall. Once circulation has been established, drilling is commenced by rotating the string from the surface. During normal operation, the bit runs smoothly in the borehole. The large area presented to the borehole wall by each of the pads limits the lateral drilling action of the blades and prevents the drilling of an oversized hole. The pads also assist in minimizing jetting effect of the fluid against the outer section at the.

bottom of the borehole where drilling is normally most difficult also improves the cutting action of the hard metal particles on the face of the blades and improves the drilling rate. 1 a

Due to the presence of dipping strata at the bottom of theborehole or for other reasons, one blade of the bit will sometimes tend to penetrate more deeply into the formation than does the other and the bit will therefore tend to pivot about the more deeply embeded blade. This normally leads to a sharp impact between the face or gage edge of the opposing blade and the borehole wall.

discharged from the nozzles thus passes substantially Fracturing of the hard surfacing material on the face or gage edge of the blade may result; The pads in front of the blades on the bit of theinvention avoid this. As

the bit tends-to pivot about one blade, the pad on the vopposite side of the body contacts the borehole wall before contact is'made by the gage edge of the opposing blade. Once the pad strikes the wall, the embedded blade is dislodged and normal rotation of the bit continues. High impact loadings which are likely to damage the face and gage surfaces of the blades on a conventional drag bit are thus avoided.

It will be apparent from the foregoing that the pads and nozzlel arrangement described serve to stabilize the bit, reduce gage wearyminimize fracturing of the gage surfaces due .to high impact loadings, permit. more effective cleaning of cuttings from beneath the bit, and provide smoother operation than can generally be obtained with conventional drag bits. ,The invention has been described in terms of a two-way drag bit provided with diametrically opposed pads but is equally applicable to three-way and four-way drag bits. It may also be applied to bits provided with extensible blades. Various modifications and modes of construction utilizing pads containing nozzles mounted in front of the blades near the gage edges will be apparent to those skilled in the art.

.What is claimed is: V A

1. A rotary drag bit comprising a hollow body provided with means for connectingsaid bit to the lower end of a drill string, said body including a plurality of laterally projecting pads extending part way about thebody at spaced intervals and extending longitudinally from points near the bottomjof said body to intermediate points thereon; blades connected to and depending from said body behind said pads, said blades including gage edges'lat: erally. coextensive. with ,said pads; and a plurality of nozzles mounted in said pads in front of said blades, said nozzles communicating with the interior of said body and each nozzle being mounted 'in a substantially vertical position in front of a blade near the gage sur: face thereof. a

2. A bit as defined by claim 1 wherein each of said pads extends from about 15 to about 90 about said body. 3. A bit as defined by claim 1 wherein each of said pads has a leading face extending from said body in a substantially radial direction.

' 4. A rotary drill bit comprising a hollow body member provided with means for connecting said member to the a lower end of a drill string, said body member including a plurality of laterally projecting pads extending through horizontal angles of from about 15 to about at spaced intervals about thebody and extending vertically from points near the lower end of said body tov points near the middle of said body and each of said pads containing a passageway for conveying fluid from within said bodyto an outlet near the outer surface of said pad; blades connected to and depending from said body at the rear of said'pads, said blades including gage edges extending outwardly adjacent the outer surfaces of said pads; and a nozzle located in the outlet in eachof said pads, said nozzle being mounted in a substantially verti cal position whereby fluid may be directed downwardly in front of a blade near the gage surface thereof.

7 5. A bit as defined by claim 4 wherein said passageways member and pads containing passageways extending from the interior of said member to outlets in the lower surfaces of said pads near the outer edges thereof; nozzles located within the outlets of said passageways in said pads, the axes of said nozzles extending downwardly toward the outer part ofthe formation beneath said bit; and a plurality of blades attached to and depending from said body member and pads, said blades including gage surfaces extending outwardly adjacent to the outer sur- 2,239,106 4/41 Krall "175 -393 X Pew 175-393 X Baurngartner 175407 Cannon et a1.- 175393 Rowley 175-393 X Mandre'll 175-340 -Rowley et a1. 175-408 Bridwell et a1. 175408 OTHER REFERENCES World Gil, p. 139, January 1963, TN860 041.

CHARLES E. OCONNELL, Primary Examiner.

Patent Citations
Cited PatentFiling datePublication dateApplicantTitle
US2239106 *Jan 28, 1939Apr 22, 1941W M MercerWell drill
US2300805 *Jan 13, 1941Nov 3, 1942Pew Thomas WDrilling bit
US2696973 *Feb 9, 1951Dec 14, 1954Francis R BrittonNonsticking drill bit
US3059708 *Aug 7, 1959Oct 23, 1962Jersey Prod Res CoAbrasion resistant stepped blade rotary drill bit
US3112803 *Jan 2, 1962Dec 3, 1963Jersey Prod Res CoDiamond drill bit
US3115200 *Aug 28, 1957Dec 24, 1963Reed Roller Bit CoDrill bit nozzle assembly
US3120285 *Feb 1, 1961Feb 4, 1964Jersey Prod Res CoStabilized drill bit
US3120286 *Jan 4, 1962Feb 4, 1964Jersey Prod Res CoStabilized drag bit
Referenced by
Citing PatentFiling datePublication dateApplicantTitle
US3696875 *Nov 17, 1969Oct 10, 1972Petroles Cie FrancaiseDiamond-studded drilling tool
US3938599 *Mar 27, 1974Feb 17, 1976Hycalog, Inc.Rotary drill bit
US4129952 *Oct 27, 1977Dec 19, 1978Caterpillar Tractor Co.Wear strips for earthmoving buckets
US4303136 *May 4, 1979Dec 1, 1981Smith International, Inc.Fluid passage formed by diamond insert studs for drag bits
US4440247 *Apr 29, 1982Apr 3, 1984Sartor Raymond WRotary earth drilling bit
US5103922 *Oct 30, 1990Apr 14, 1992Smith International, Inc.Fishtail expendable diamond drag bit
US5829539 *Feb 13, 1997Nov 3, 1998Camco Drilling Group LimitedRotary drill bit with hardfaced fluid passages and method of manufacturing
US6390211Jun 21, 1999May 21, 2002Baker Hughes IncorporatedVariable orientation nozzles for earth boring drill bits, drill bits so equipped, and methods of orienting
US7703555Aug 30, 2006Apr 27, 2010Baker Hughes IncorporatedDrilling tools having hardfacing with nickel-based matrix materials and hard particles
US7997359Sep 27, 2007Aug 16, 2011Baker Hughes IncorporatedAbrasive wear-resistant hardfacing materials, drill bits and drilling tools including abrasive wear-resistant hardfacing materials
US8104550 *Jan 31, 2012Baker Hughes IncorporatedMethods for applying wear-resistant material to exterior surfaces of earth-boring tools and resulting structures
US8388723Feb 8, 2010Mar 5, 2013Baker Hughes IncorporatedAbrasive wear-resistant materials, methods for applying such materials to earth-boring tools, and methods of securing a cutting element to an earth-boring tool using such materials
US8758462Jan 8, 2009Jun 24, 2014Baker Hughes IncorporatedMethods for applying abrasive wear-resistant materials to earth-boring tools and methods for securing cutting elements to earth-boring tools
US9200485Feb 9, 2011Dec 1, 2015Baker Hughes IncorporatedMethods for applying abrasive wear-resistant materials to a surface of a drill bit
US20070056777 *Aug 30, 2006Mar 15, 2007Overstreet James LComposite materials including nickel-based matrix materials and hard particles, tools including such materials, and methods of using such materials
US20080073125 *Sep 27, 2007Mar 27, 2008Eason Jimmy WAbrasive wear resistant hardfacing materials, drill bits and drilling tools including abrasive wear resistant hardfacing materials, and methods for applying abrasive wear resistant hardfacing materials to drill bits and drilling tools
US20080083568 *Sep 28, 2007Apr 10, 2008Overstreet James LMethods for applying wear-resistant material to exterior surfaces of earth-boring tools and resulting structures
US20100000798 *Jun 23, 2009Jan 7, 2010Patel Suresh GMethod to reduce carbide erosion of pdc cutter
US20100101867 *Oct 27, 2008Apr 29, 2010Olivier SindtSelf-stabilized and anti-whirl drill bits and bottom-hole assemblies and systems for using the same
US20100132265 *Feb 8, 2010Jun 3, 2010Baker Hughes IncorporatedAbrasive wear-resistant materials, methods for applying such materials to earth-boring tools, and methods of securing a cutting element to an earth-boring tool using such materials
US20110138695 *Jun 16, 2011Baker Hughes IncorporatedMethods for applying abrasive wear resistant materials to a surface of a drill bit
WO2010049674A1 *Oct 26, 2009May 6, 2010Schlumberger Holdings LimitedSelf-stabilized and anti-whirl drill bits and bottom-hole assemblies and systems for using the same
WO2010049677A1 *Oct 26, 2009May 6, 2010Schlumberger Holdings Limited (Shl)Anti-whirl drill bits, wellsite systems, and methods of using the same
Classifications
U.S. Classification175/393, 175/426, 175/408
International ClassificationE21B10/00, E21B10/54, E21B10/60, E21B10/56, E21B10/46
Cooperative ClassificationE21B10/54, E21B10/602, E21B10/56
European ClassificationE21B10/60B, E21B10/56, E21B10/54