US20110155473A1 - Stabilizing system and methods for a drill bit - Google Patents
Stabilizing system and methods for a drill bit Download PDFInfo
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- US20110155473A1 US20110155473A1 US12/698,693 US69869310A US2011155473A1 US 20110155473 A1 US20110155473 A1 US 20110155473A1 US 69869310 A US69869310 A US 69869310A US 2011155473 A1 US2011155473 A1 US 2011155473A1
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- stabilizing
- drill bit
- during use
- fluid
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- 238000000034 method Methods 0.000 title description 11
- 238000005553 drilling Methods 0.000 claims abstract description 47
- 239000012530 fluid Substances 0.000 claims description 77
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- 238000007789 sealing Methods 0.000 claims description 14
- 230000006641 stabilisation Effects 0.000 claims description 10
- 238000011105 stabilization Methods 0.000 claims description 10
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Images
Classifications
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH DRILLING; MINING
- E21B—EARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B17/00—Drilling rods or pipes; Flexible drill strings; Kellies; Drill collars; Sucker rods; Cables; Casings; Tubings
- E21B17/10—Wear protectors; Centralising devices, e.g. stabilisers
- E21B17/1014—Flexible or expansible centering means, e.g. with pistons pressing against the wall of the well
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH DRILLING; MINING
- E21B—EARTH DRILLING, e.g. DEEP 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 DRILLING; MINING
- E21B—EARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B10/00—Drill bits
- E21B10/60—Drill bits characterised by conduits or nozzles for drilling fluids
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH DRILLING; MINING
- E21B—EARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B10/00—Drill bits
- E21B10/62—Drill bits characterised by parts, e.g. cutting elements, which are detachable or adjustable
Definitions
- This invention relates generally to drill bit and drill bit stabilizing systems and methods for use in borehole forming operations wherein a drill bit is connected to a drill string and rotated while drilling fluid flows down the drill string to the drill bit for circulating cuttings up the borehole as the hole is drilled. More particularly, the invention relates to stabilizing systems and methods for stabilization of a drill bit so as to minimize vibration and possible damage to the drill bit or other structures.
- the present invention includes improved means so as to overcome the deficiencies and problems mentioned above.
- the structure of the present invention may be generally similar to that shown in prior U.S. Pat. No. 4,842,083; except that the various improvements have been provided, both as to the methods and stabilizing system of the invention.
- the invention is directed to a drill bit stabilizing system comprising a body member having an axis, and at least one recess formed in the body member for housing at least one stabilizing member when in a first retracted position.
- the at least one stabilizing member is biased to a second extended operating position.
- the body member further comprises at least one fixed stabilizing surface positioned in axially spaced relationship to the at least one moveable stabilizing member
- the invention is directed to a drill bit stabilizing system comprising a body member and at least one stabilizing member, being moveable from an extended operating position to a retracted position within the body member.
- the at least one stabilizing member comprises outer contact faces adapted to engage the wall of a bore hole when in an operating position, and an inner slide surface adapted to slidingly engage a corresponding slide surface formed in the body member.
- the inner slide surface comprises at least one relief groove to facilitate the reduction of the surface area of the surface and thereby provide a predetermined increase in the contact pressure per square inch between the inner slide surface and corresponding slide surface associated with the body member.
- the slideable, wedge shaped stabilizing members are entirely spring actuated and the at least one stabilizing member comprises a plunger portion provided in a spring chamber formed in the body member.
- the spring chamber comprises an amount of incompressible fluid therein, and a fluid displacement system in fluid communication with the spring chamber to provide pressure equalization upon movement of the plunger within the spring chamber.
- the invention is also directed to a drill bit for forming a bore hole wherein the drill bit is attached to a rotary drill string having an axial passageway through which drilling fluid flows to the bit face
- the bit comprises a plurality of wear ridges and a plurality of cutters in association with the bit face, the plurality of wear ridges characterized in providing an initial support surface for the weight applied to the bit during a drilling operation.
- the plurality of wear ridges initially extend outwardly from the bit face to a greater extent than the plurality of cutting elements.
- the drill bit is rotated along with the drill string to initiate a drilling operation or in an existing fall gauge hole to form a pilot hole.
- the plurality of wear ridges will allow rotation of the drill bit and drill string for a period of time before engagement of the plurality of cutting elements.
- FIG. 1 is a longitudinal, partially sectioned view of the preferred embodiment
- FIG. 2 is a straight-on bottom view of the embodiment
- FIG. 3 is a cross sectional view taken along line 3 - 3 of FIG. 1 ;
- FIG. 4 is an enlarged partial side view taken along line 4 - 4 of FIG. 1 ;
- FIG. 5 is a multi-view illustration of the item shown in FIG. 4 ;
- FIG. 6 is a flattened partial side view taken along line 6 - 6 of FIG. 2 ;
- FIGS. 7 through 14 are partial sectional views of various portions of items shown in FIG. 2 ;
- FIG. 15 is an enlarged partial sectional view of FIG. 1 ;
- FIG. 16 is a schematic, part sectional view of a drilling operation with the present invention included therewith.
- the embodiment comprises an improved stabilizer and drill bit, generally indicated by the numeral 100 .
- the invention in one aspect is generally directed to a drill bit stabilizer having a main body of generally cylindrical configuration and a pin end opposed to a lower drilling end.
- the system is attachable to or includes a drill bit for making a borehole when rotation occurs.
- a throat is formed longitudinally through the main body of the stabilizer for passage of drilling fluid from a drill string, through the body, and through nozzles of the bit.
- the drilling fluid exits the bit and returns up the borehole annulus.
- a plurality of circumferentially arranged wedge shaped pockets or recesses are formed about the main body from the outer surface of the main body inward to slideably receive corresponding wedge shaped stabilizing members.
- the stabilizing members are spring actuated.
- the stabilizing members are each therefore reciprocatingly received in a slideable manner, as they are spring actuated within each respective pocket.
- Each of the stabilizing members has an outer face which can be retracted into alignment with the outer surface of the main body, and which can be extended outwardly from the surface of the main body and into abutment with the wall of a borehole. Flushing orifices are provided to allow a limited volume of drilling fluid to flow from the throat through the pockets so as to prevent jamming of the stabilizing members by detritus material.
- the before mentioned spring means are incorporated into the main body in a manner such that each of the stabilizing members is forced to move in an angular direction downwardly and outwardly of the main body.
- the spring means forces the stabilizing members towards the extended configuration and, as the face of the stabilizing member, or the borehole wall, is worn, the face of the member is further extended to maintain abutment with the borehole wall.
- Frictional means is provided to lock, or block, the stabilizing members in any one of a range of extended positions.
- the frictional means is the friction between the sliding surfaces of the wedge shaped stabilizing members and the corresponding surfaces of the pockets within which the wedges are received.
- the stabilizer comprises a main body 1 made of a suitable material such as steel.
- the main body 1 is generally cylindrical in shape and the upper end thereof is threaded in the conventional manner or is otherwise provide with a known means for attachment to the end of a drill pipe or “drill string”.
- the main body 1 has a central fluid passage or throat 15 extending from the top end, axially along the central axis towards the lower end.
- the lower marginal end of the main body 1 may be an integral part of a drill bit 110 , as shown in FIG. 1 , or it may be a separate member suitably attachable to a drill bit with the throat 15 arranged to provide a flow of fluid therethrough to the drill bit, as described in my previous U.S. Pat. No. 4,842,083, of which this invention is a continuation in part.
- the embodiment 100 includes a plurality of moveable and radial stabilizing wedges 29 installed in complementary radial pockets 3 formed into the main body 1 in spaced relationship respective to the throat 15 .
- the pockets 3 with the respective wedges 29 installed therein, are symmetrically arranged circumferentially about the central longitudinal axis of the main body 1 , as shown in FIGS. 1 and 3 .
- the embodiment 100 of FIGS. 1 and 3 includes three such pockets 3 and three corresponding wedges 29 ; however, any suitable number may be employed.
- the pockets 3 are each shaped and arranged to provide a mated slide surface 45 which is inclined downward and outward relative to the central axis of the main body 1 .
- the upper end surface 45 ′ of each pocket 3 is generally perpendicular to the inclined slide surface 45 , as seen in FIG. 15 .
- Each wedge 29 is correspondingly shaped and arranged so that the outer surface of each wedge 29 is flush or aligned with the outer surface of the main body 1 when the wedges 29 are fully seated into the pockets 3 .
- Each wedge has an inner slide surface 44 which is mated to and arranged to slide against the slide surface 45 .
- the outer faces of the wedges 29 are provided with suitably thick wear resistant tungsten carbide surfaces 36 formed onto the outer faces of the wedges 29 so that the wear resistant surfaces 36 are flush or aligned with the outer faces of the wedges 29 , thereby making the outer faces of the wedges 29 wear resistant.
- the wedges 29 may alternatively be made entirely of a wear resistant material, such as ceramic, or may be made wear resistant by other known expedients, such as applying PDC diamond to the faces.
- Corresponding plungers 32 are attached to the upper end of each wedge 29 and extend upward and inward parallel to the slide surface 45 of each pocket 3 .
- the coupling between the wedge 29 and corresponding plungers 32 is preferably non-rigid or has some flexibility to allow some movement between these members. Such a connection will avoid the formation of a high stress point at this location.
- a bore 8 is formed in the large end of each wedge, as shown in FIG. 5 ; with an annular groove 9 formed therein.
- the lower ends of plungers 32 are formed to correspond to bores 8 and have grooves formed thereon to match with grooves 9 . As shown in FIG.
- an access hole 10 is drilled tangent to groove 9 in each wedge 29 to allow insertion of metal balls 48 , of metal such as stainless steel, so the matching grooves are filled with metal balls to thereby attach the wedges 29 to the plungers 32 , as seen in FIG. 15 .
- the access holes 10 are tapped to receive plugs to retain the metal balls in place.
- Complementary bores 46 ′ which do not communicate with the throat 15 , are provided to receive each plunger 32 .
- Each bore 46 ′ has an enlarged section to form a spring chamber 46 and to accommodate seal bushing 33 .
- the seal bushings 33 are installed in fixed relationship within the lower marginal end of spring chambers 46 and reciprocatingly receive the plungers 32 in sealed relationship therewith by means of the illustrated o-rings 31 .
- Wipers 43 are also added to prevent debris from banning the o-rings 31 during reciprocating movements of the plungers 32 .
- the seal bushings 33 are sealed to the spring chambers 46 by o-rings 49 and are affixed therein by locking rings 35 , or by other suitable known means.
- Springs 34 such as Belleville washers, and preferably of the stacked disk type, are received about each plunger 32 between the seal bushing 33 and the upper end of spring chambers 46 .
- the springs 34 are thus respectively confined and sealed within the chambers 46 at a location between the upper end of chamber 46 and seal bushing 33 .
- the spring chambers 46 must be filled with an incompressible fluid, such as hydraulic oil, which is sealed therein by plugs 51 ; and all air or gas bubbles should be removed.
- a moveable sealing member 5 such as a free traveling piston is installed in each bore 4 and moveably sealed therein by an O-ring 6 so as to keep fluid within chamber 46 , bore 46 ′ and the inner portion of bore 4 .
- the moveable sealing member 5 could be of a different character, such as a sealed diaphragm or the like, while accommodating fluid displacement.
- plunger 32 moves in or out during operation, corresponding moveable sealing member 5 , such as a piston, freely moves in or out to accommodate the change in fluid volume within chamber 46 ,
- a retaining ring 7 is installed in bore 4 to keep piston 5 from inadvertently traveling too far outward in bore 4 .
- the in or out travel of plunger 32 and wedge 29 is not hindered nor affected by static down hole pressure nor by fluid pressure within throat 15 .
- a suitable flange 11 is formed on each plunger 32 to provide contact with springs 34 ; and to abut against the seal bushings 33 so as to limit the outward travel of each plunger 32 at the appropriate distance.
- the springs 34 are arranged to press against the flanges 11 and thereby bias the plungers 32 , and the wedges 29 attached thereto, outward. As will be explained later herein, the wedges 29 and plungers 32 are to be retracted inward by other force means, such as by thrust of the wedges 29 against the rim of the pilot hole formed by the bit 110 .
- flushing orifices 54 are positioned to provide fluid communication between throat 15 and each pocket 3 and are sized and arranged to provide an effectual flow of fluid through each pocket 3 so as to prevent detritus material from packing or jamming around the wedges 29 .
- orifice 54 may be in the form of a disk made of abrasion resistant material, such as tungsten carbide, having an aperture 40 approximately 0.100 inch to 0.125 inch in diameter.
- aperture 40 is preferably tapered and flared outward downstream so as to minimize the velocity of fluid exiting therethrough.
- Orifice 54 is retained in a suitably formed port 30 by means of a hollow screw 41 and sealed therein by an o-ring 42 .
- Each port 30 intersects throat 15 and provides fluid communication therethrough between throat 15 and each corresponding orifice 54 .
- flushing fluid such as drilling fluid passing under pressure within throat 15 , can pass outward through each orifice 54 , outward through each pocket 3 and around each wedge 29 so as to remove detritus material or debris which might otherwise pack around the wedges 29 and jam proper movement thereof.
- a strainer sleeve 26 is installed in throat 15 adjacent ports 30 , as shown in FIGS. 1 and 15 .
- the outer surfaces of strainer sleeve 26 are formed so that the upper and lower end portions fit closely within throat 15 , but the intermediate portion is smaller in diameter so that a small but adequate annular space 28 is provide between the sleeve 26 and the wall of throat 15 adjacent to the ports 30 .
- the inner surface of sleeve 26 is cylindrical.
- a plurality, preferably up to 200, strainer holes 37 are drilled in sleeve 26 within the region of annular space 28 , but sufficiently above the vicinity of ports 30 , as shown in FIG. 15 .
- the holes 37 are positioned above and away from ports 30 so as to prevent erosion of the holes 37 due to the swirl of fluid entering ports 30 .
- drilling fluid is permitted to pass from throat 15 through holes 37 , through annular space 28 , through ports 30 and through orifices 54 into pockets 3 .
- the strainer holes 37 are approximately 0.050 inch to 0.070 inch in diameter so as to be smaller than the apertures 40 . Thus, foreign material large enough to clog orifices 54 cannot pass through strainer sleeve 26 when passing through throat 15 .
- the annular space 28 is, preferably, made no wider than 0.070 inch so that it too prevents clogging of orifices 54 .
- the apertures 40 are sized to provide a flow rate through each of approximately 10 gpm to 15 gpm at the usual operating pressures.
- a clearance notch 50 is formed on the inner, upper end of each wedge 29 , as shown in FIGS. 5 and 15 ; and ports 30 and orifices 54 are positioned so that fluid exiting orifices 54 impinges against notches 50 so as to deflect the fluid in a manner that does not erode the surface of plungers 32 .
- throat 15 In normal operation, the main flow of drilling fluid through throat 15 is to the nozzles of the bit 110 , so that foreign material or debris cannot clog the strainer holes 37 because the main flow through throat 15 will wash them away towards the nozzles of the bit 110 .
- throat 15 in the vicinity of sleeve 26 , along with sleeve 26 , is made small enough in diameter so that a relatively high fluid velocity is achieved therethrough during normal operation. For example, when around 300 gpm of drilling fluid is provided, 11 ⁇ 4 to 11 ⁇ 2 inch inside diameter of sleeve 26 seems to produce sufficient fluid velocity for effective washing action.
- sleeve 26 should be made of case hardened steel, or some harder material.
- the bit 110 is equipped with a plurality of nozzles 25 , similar to the arrangement described in my prior U.S. Pat. No. 4,856,601, which are arranged to provide optimum fluid flow restriction and appropriate fluid output velocity.
- the nozzles 25 are installed in corresponding nozzle ports 24 which are formed and arranged to communicate with throat 15 .
- the nozzles 25 are retained in ports 24 by means of threaded retainers 52 and sealed against leak-by means of o-rings 38 .
- Nozzles 25 will usually be made of abrasion resistant material such as tungsten carbide.
- a plurality of flow slots 27 are formed in the face of bit 110 and along the outside of main body 1 to permit the return flow of drilling fluid exiting nozzles 25 during operation and to thereby evacuate drilled cuttings from the bore hole.
- a plurality of cutting elements 18 are installed, positioned and arranged on bit 110 so as to cut rock from the bottom of the borehole as bit 110 is rotated during operation.
- the portion of the main body 1 immediately above the wedges 29 is slightly larger in diameter than the bore hole produced by the drill bit 110 and has installed therein a plurality of secondary gauge cutting elements 85 which are similar to the cutting elements 18 on the face of bit 110 .
- gauge cutters 85 are shown in hidden lines and are artificially rotated into the positions shown so as to illustrate their cutting profile.
- the secondary gauge cutters 85 are positioned and arranged to produce a borehole large enough in diameter for the entire assembly to pass upward therethrough even when the wedges 29 are fully extended, as shown in FIG. 1 .
- the drill bit 110 and the primary gauge cutters thereof forms a pilot hole which is intended to be enlarged by the secondary gauge cutters 85 to the final desired diameter.
- vent holes 80 are formed to extend from the deeper end of each pocket 3 into each corresponding slot 27 . As shown, two such vents 80 may be employed for each pocket 3 .
- upper fixed stabilizing surfaces 12 are formed on body 1 or provided on a separate body member attached to the stabilizing system.
- the fixed stabilizing surfaces 12 could be formed as part of the body member 1 , or could be provided by means of a suitable additional body member having fixed stabilizing surfaces thereon, which is coupled to the main body 1 .
- the fixed stabilizing surfaces 12 are preferably provided in corresponding relationship to each pocket 3 , and in positions axially behind gauge cutters 85 and radial bores 4 , so as to be located at a predetermined axial distance behind wedges 29 .
- the fixed stabilizing surfaces are positioned such that they are spaced from the corresponding moveable stabilizing members an axial length of not more than three times, and preferably not more than twice the gauge diameter of assembly.
- the fixed stabilizing surfaces 12 may also be provided with wear resistant surfaces 14 , which can be integral to or can be installed in the surface of each pad 12 to provide wear resistance.
- Surfaces 14 may be solid tungsten carbide, or may be impregnated or coated with diamond to achieve maximum wear resistance; or, the pads 12 may be made wear resistant by some other expedient method.
- the fixed stabilizing surfaces in conjunction with the moveable stabilizing members provide distinct advantages in operation to avoid detrimental wobble and vibration at the drill bit tip.
- the pads 12 with surfaces 14 provided or installed thereon, are sized and positioned to very nearly coincide with the borehole diameter cut by gauge cutters 85 so that only minimal clearance between the surfaces 14 and the borehole wall is allowed. Notice that the axial distance between wedges 29 and surfaces 14 is relatively short, and configured to prevent axis wobble of the assembly during drilling operation.
- the gauge pads 12 are effectively integral to the body 1 .
- pads 12 could be made as part of a short profile body, commonly called a “sub”, which could be weldable or otherwise attachable to main body 1 so as to be effectively integral thereto. Nevertheless, as shown in FIG. 1 , pads 12 and main body 1 are a single continuous piece in the preferred embodiment.
- a borehole 60 has a drill string 62 and a drill collar 64 therein; with the stabilizer 100 attached to the lower end thereof.
- a drill bit 110 is integrally attached to the lower end of the stabilizer 100 .
- a drilling rig 70 manipulates the drill string 62 .
- the drill string 62 , drill collar 64 , together with the stabilizer 100 and drill bit 110 attached, are inserted in a bore hole 60 and rotated in the conventional manner during a drilling operation.
- drilling fluid flows at 72 into the drill string 62 , through the drill string 62 , through the throat 15 of the present stabilizer 100 , out of the drill bit 110 , back up the bore hole annulus outside the drill string 62 and returned through a blowout preventer 74 in the usual manner.
- flow slots 27 permit passage of the drilling fluid and, thereby, removal of drilled cuttings from the borehole.
- the wedges 29 will run in a pilot hole formed by drill bit 110 and the primary gauge cutters thereof, while the secondary gauge cutters 85 enlarge the bore hole to the desired final diameter.
- drilling fluid flowing through the present stabilizer 100 is at a relatively elevated pressure within throat 15 , because of the usual pressure drop measured across the nozzles 25 of the drill bit 110 .
- neither the fluid pressure in throat 15 nor the fluid pressure outside of stabilizer 1 . 00 will have any effect on the plungers 32 .
- the plungers 32 Due only to the thrust of the springs 34 , the plungers 32 will thrust downward.
- the wedges 29 will thus be caused to move downward and outward along the slide surface 45 until the outer face of the wedges 29 abuts the wall of the pilot hole.
- the wedges 29 thus are held in contact with the wall of the pilot hole so long as sufficient spring tension is maintained.
- the angle of the slide surfaces 44 and 45 is of a selected value so that inward radial force exerted on the outer face of each wedge 29 produces sufficient friction between the mated slide surfaces 44 and 45 to overcome the resultant upward sliding vector force on the wedges 29 , so that the wedges 29 cannot be made to retract by radial force during drilling operation.
- This is called “radial blocking action” which prevents radial movement of the central axis of stabilizer 100 and bit 110 .
- the relative angle and arrangement of the slide surfaces 44 and 45 is such to block any radial inward movement of the wedges 29 at any extended position thereof when an inward radial force is exerted on the wedges 29 . This is so even if such inward radial force is of a magnitude that would overcome the thrust of springs 34 in the absence of the frictional interaction of the slide surfaces 44 and 45 .
- the frictional interaction between surfaces 44 and 45 depends, of course, on the prevailing coefficient of friction. It has been learned that, due to the relatively large area of surface 44 on each wedge 29 , as described in my prior U.S. Pat. No. 4,842,083, the coefficient of friction is sometimes reduced by conditions of the drilling fluid or other materials present during operation. Since the coefficient of friction tends to increase with the amount of contact pressure per square inch, a shallow but relatively wide relief groove 47 , as shown in FIGS. 5 and 15 , is formed longitudinally through the middle of slide surface 44 on each wedge 29 to reduce the effective area of each surface 44 , by one half or more, and thereby increase the contact pressure per square inch between slide surfaces 44 and 45 ; and thus increase the coefficient of friction and frictional interaction between the slide surfaces 44 and 45 .
- the longitudinal groove 47 provides a flow path for drilling fluid traveling back up the borehole annulus to flow under and behind each wedge 29 and thereby aid in removing detritus material from each pocket 3 .
- the face of bit 110 has wear ridges 39 integrally formed thereon immediately trailing and corresponding to the pattern of cutting elements 18 .
- the cutters 18 are deeply installed, and the ridges 39 are so formed, that the tips of cutters 18 initially do not extend beyond the surface profile of the ridges 39 , before any wear occurs on the ridges 39 .
- the ridges 39 of the present invention are similar to the fluid flow isolating ridge 39 of my prior U.S. Pat. No. 4,856,601, however, the ridges 39 of the present invention are much wider and stronger, so as to be able to actually support the weight applied to the bit 110 during typical drilling operation, without wearing too fast.
- the ridges 39 of the present invention will normally be formed of high grade, hardened steel so as to be at least one-half inch wide, or more, and so as to be quite resistant to wear when rotated against the bottom of a bore hole; and wear resistant materials, such as tungsten carbide, may be applied to the ridges 39 to further increase wear resistance. This provides needed stabilization of bit 110 during the start of drilling a borehole.
- the wedges 29 cannot engage the wall of the full gauge hole and cannot provide any stabilization, initially.
- the cutters 18 are allowed to fully engage, or cut into the bottom of the bore hole, the cutting forces will cause chatter or other vibrations that will damage the cutters 18 , especially when the rock or other material being drilled is relatively hard.
- the strong ridges 39 support the normal weight-on-bit and prevent the cutters 18 from engaging until the ridges 39 wear to expose them.
- the ridges 39 will normally abrade the borehole bottom sufficiently to form a matching profile pattern thereon.
- the ridges 39 being held against the matching profile of the borehole bottom by the weight-on-bit, will maintain stability of the bit axis.
- the ridges 39 will slowly wear and allow the cutters 18 to begin to engage the borehole bottom, which will proportionately increase the drilling and penetration.
- each wedge 29 contacts the rim of the pilot hole formed by the bit 110 , the wedges 29 and the respective plungers 32 will be easily pushed upward and inward as the main body 1 and bit 110 continue to rotate, drill and descend while making hole. As drilling continues, a pilot hole will be formed by the bit 110 , which will facilitate full engagement and stabilizing action of the wedges 29 against the wall of the pilot hole.
- the ridges 39 are formed and arranged so that, before the wedges 29 are fully engaged and activated, the ridges 39 continue to bear most of the weight-on-bit. After the wedges 29 are fully engaged and activated, after about two feet of hole is drilled, the ridges 39 continue to wear, usually for two hours or longer, until the ridges 39 no longer bear any of the weight-on-bit; and practically all the weight-on-bit is then borne by the cutters 18 . Thus, the ridges 39 provide temporary stabilization; at least until the wedges 29 are able to fully engage the pilot hole formed by the bit 110 .
- ridges 39 are made of tough steel, which is harder than the materials typical casing plugs are made of, a drill bit and stabilizer assembly made according to the present invention can be used to effectively drill out casing plugs, without experiencing damage to the cutters 18 .
- hard materials such as tungsten carbide, may be applied to the ridges 39 so as to predetermine their wear rate or abrasive characteristics.
- the ridges 39 of the present invention are arranged and intended so as to wear sufficiently, in due course, so that, after drilling has progressed sufficiently, the ridges 39 no longer bear any of the weight-on-bit nor any longer retard the cutting and penetrating action of the cutters 18 .
- axis wobble of the assembly is prevented by virtue of the axial spacing between the wedges 29 and the gauge surfaces 14 and by the limited, or non-existent, clearance between the surfaces 14 and the bore hole wall. Also, in the event that detritus material accumulates in pockets 3 behind the wedges 29 , the detritus material can be forced out of the pockets 3 through vents 80 and into slots 27 upon upward movement of wedges 29 .
- the present invention provides improved means for radial stabilization of a drill bit; such that whirl, chatter and other forms of radial vibration are prevented under a wide range of drilling conditions; and such that the drilling, penetrating and endurance capabilities of a PDC drill bit is maximized.
Abstract
A drill bit stabilizing system comprising a body member having an axis and at least one recess formed in the body member housing at least one stabilizing member when in a first retracted position. The stabilizing member is positionable along a diagonal angle with the axis to a second extended operating position which extends downward and outward relative to the main body to selectively engage the surface of a pilot bore hole wall during a drilling operation so as to stabilize an under gauge drill bit used in association with the stabilizing system. The body member further comprises at least one fixed stabilizing surface positioned in an axially spaced relationship to the at least one moveable stabilizing member. The body member further comprises a gauge cutter positioned above the moveable stabilizing member and below the fixed stabilizing surface to expand the pilot hole to the final gauge.
Description
- This application is a divisional of U.S. patent application Ser. No. 11/164,755 filed Dec. 5, 2005 which is a divisional of co-pending U.S. patent application Ser. No. 10/135,201, filed Apr. 30, 2002, each of which is hereby incorporated by reference.
- This invention relates generally to drill bit and drill bit stabilizing systems and methods for use in borehole forming operations wherein a drill bit is connected to a drill string and rotated while drilling fluid flows down the drill string to the drill bit for circulating cuttings up the borehole as the hole is drilled. More particularly, the invention relates to stabilizing systems and methods for stabilization of a drill bit so as to minimize vibration and possible damage to the drill bit or other structures.
- My prior U.S. Pat. Nos. 4,842,083; 4,856,601; and 4,690,229, which are hereby incorporated by reference, are directed to drilling systems and methods providing distinct advantages. U.S. Pat. No. 4,842,083, entitled “Drill Bit Stabilizer”, is directed to a stabilizing system to stabilize the drill bit and drilling string in a down hole system, and the present invention is directed to improvements in the system and methods described therein. Although the prior system and methods provide the desired stabilization of the drill bit under most circumstances, it has been found to be desirable to minimize the actuating forces required on the wedge shaped stabilizing members in order to affect the frictional blocking action needed for radial stability. Also, it has been found to be desirable to account for high down hole drilling pressures, particularly where the stabilizing members are spring actuated, such that the drilling fluid pressure does not adversely interfere with the spring action of the stabilizing members. Blockages of various orifices or recesses in the system can also cause problems, and the present invention is directed at reducing or eliminating such possible blockages, particularly around the stabilizing members. It has also been found that under certain conditions, the bit may not be properly stabilized by the stabilizing members, such as at the beginning of a drilling operation or where no pilot hole is formed in the borehole. In such situations, it would be desirable to provide stabilization for the bit face until sufficient hole has been drilled to allow the stabilizing members to engage the bore hole wall. Thus, it would be desirable to prevent vibration damage of PDC cutting elements on the bit which can occur during the start of drilling a bore hole, or to prevent harmful axis wobble of the assembly may occur during ongoing drilling operation.
- As will be shown herein, the present invention includes improved means so as to overcome the deficiencies and problems mentioned above.
- It is therefore an object of the present invention to provide a drill hit stabilizing system and methods which overcome the above noted problems.
- The structure of the present invention may be generally similar to that shown in prior U.S. Pat. No. 4,842,083; except that the various improvements have been provided, both as to the methods and stabilizing system of the invention. In one aspect, the invention is directed to a drill bit stabilizing system comprising a body member having an axis, and at least one recess formed in the body member for housing at least one stabilizing member when in a first retracted position. The at least one stabilizing member is biased to a second extended operating position. The body member further comprises at least one fixed stabilizing surface positioned in axially spaced relationship to the at least one moveable stabilizing member, in another aspect, the invention is directed to a drill bit stabilizing system comprising a body member and at least one stabilizing member, being moveable from an extended operating position to a retracted position within the body member. The at least one stabilizing member comprises outer contact faces adapted to engage the wall of a bore hole when in an operating position, and an inner slide surface adapted to slidingly engage a corresponding slide surface formed in the body member. The inner slide surface comprises at least one relief groove to facilitate the reduction of the surface area of the surface and thereby provide a predetermined increase in the contact pressure per square inch between the inner slide surface and corresponding slide surface associated with the body member. In a further aspect, the slideable, wedge shaped stabilizing members are entirely spring actuated and the at least one stabilizing member comprises a plunger portion provided in a spring chamber formed in the body member. The spring chamber comprises an amount of incompressible fluid therein, and a fluid displacement system in fluid communication with the spring chamber to provide pressure equalization upon movement of the plunger within the spring chamber. The invention is also directed to a drill bit for forming a bore hole wherein the drill bit is attached to a rotary drill string having an axial passageway through which drilling fluid flows to the bit face The bit comprises a plurality of wear ridges and a plurality of cutters in association with the bit face, the plurality of wear ridges characterized in providing an initial support surface for the weight applied to the bit during a drilling operation. There is also provided a method of drilling a bore hole using a drill bit rotated in conjunction with a drill string. The method comprises the steps of providing a drill bit having a plurality of wear ridges on the bit face along with a plurality of cutting elements. The plurality of wear ridges initially extend outwardly from the bit face to a greater extent than the plurality of cutting elements. The drill bit is rotated along with the drill string to initiate a drilling operation or in an existing fall gauge hole to form a pilot hole. Upon rotation of the drill bit, the plurality of wear ridges will allow rotation of the drill bit and drill string for a period of time before engagement of the plurality of cutting elements.
- Other objects and advantages of the present invention will be apparent upon consideration of the following specification, with reference to the accompanying drawings in which like numerals correspond to like parts shown in the drawings.
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FIG. 1 is a longitudinal, partially sectioned view of the preferred embodiment; -
FIG. 2 is a straight-on bottom view of the embodiment; -
FIG. 3 is a cross sectional view taken along line 3-3 ofFIG. 1 ; -
FIG. 4 is an enlarged partial side view taken along line 4-4 ofFIG. 1 ; -
FIG. 5 is a multi-view illustration of the item shown inFIG. 4 ; -
FIG. 6 is a flattened partial side view taken along line 6-6 ofFIG. 2 ; -
FIGS. 7 through 14 are partial sectional views of various portions of items shown inFIG. 2 ; -
FIG. 15 is an enlarged partial sectional view ofFIG. 1 ; -
FIG. 16 is a schematic, part sectional view of a drilling operation with the present invention included therewith. - Referring to the figures of the drawings, the embodiment comprises an improved stabilizer and drill bit, generally indicated by the
numeral 100. The invention in one aspect is generally directed to a drill bit stabilizer having a main body of generally cylindrical configuration and a pin end opposed to a lower drilling end. The system is attachable to or includes a drill bit for making a borehole when rotation occurs. A throat is formed longitudinally through the main body of the stabilizer for passage of drilling fluid from a drill string, through the body, and through nozzles of the bit. The drilling fluid exits the bit and returns up the borehole annulus. A plurality of circumferentially arranged wedge shaped pockets or recesses are formed about the main body from the outer surface of the main body inward to slideably receive corresponding wedge shaped stabilizing members. Means are provided by which the stabilizing members are spring actuated. The stabilizing members are each therefore reciprocatingly received in a slideable manner, as they are spring actuated within each respective pocket. Each of the stabilizing members has an outer face which can be retracted into alignment with the outer surface of the main body, and which can be extended outwardly from the surface of the main body and into abutment with the wall of a borehole. Flushing orifices are provided to allow a limited volume of drilling fluid to flow from the throat through the pockets so as to prevent jamming of the stabilizing members by detritus material. - The before mentioned spring means are incorporated into the main body in a manner such that each of the stabilizing members is forced to move in an angular direction downwardly and outwardly of the main body. The spring means forces the stabilizing members towards the extended configuration and, as the face of the stabilizing member, or the borehole wall, is worn, the face of the member is further extended to maintain abutment with the borehole wall. Frictional means is provided to lock, or block, the stabilizing members in any one of a range of extended positions. The frictional means is the friction between the sliding surfaces of the wedge shaped stabilizing members and the corresponding surfaces of the pockets within which the wedges are received.
- More particularly, and with respect to the embodiments shown in the drawings, the stabilizer comprises a
main body 1 made of a suitable material such as steel. Themain body 1 is generally cylindrical in shape and the upper end thereof is threaded in the conventional manner or is otherwise provide with a known means for attachment to the end of a drill pipe or “drill string”. Themain body 1 has a central fluid passage orthroat 15 extending from the top end, axially along the central axis towards the lower end. The lower marginal end of themain body 1 may be an integral part of adrill bit 110, as shown inFIG. 1 , or it may be a separate member suitably attachable to a drill bit with thethroat 15 arranged to provide a flow of fluid therethrough to the drill bit, as described in my previous U.S. Pat. No. 4,842,083, of which this invention is a continuation in part. - The
embodiment 100 includes a plurality of moveable andradial stabilizing wedges 29 installed in complementaryradial pockets 3 formed into themain body 1 in spaced relationship respective to thethroat 15. Thepockets 3, with therespective wedges 29 installed therein, are symmetrically arranged circumferentially about the central longitudinal axis of themain body 1, as shown inFIGS. 1 and 3 . Theembodiment 100 ofFIGS. 1 and 3 includes threesuch pockets 3 and three correspondingwedges 29; however, any suitable number may be employed. - The
pockets 3 are each shaped and arranged to provide a matedslide surface 45 which is inclined downward and outward relative to the central axis of themain body 1. Theupper end surface 45′ of eachpocket 3 is generally perpendicular to theinclined slide surface 45, as seen inFIG. 15 . Eachwedge 29 is correspondingly shaped and arranged so that the outer surface of eachwedge 29 is flush or aligned with the outer surface of themain body 1 when thewedges 29 are fully seated into thepockets 3. Each wedge has aninner slide surface 44 which is mated to and arranged to slide against theslide surface 45. - The outer faces of the
wedges 29 are provided with suitably thick wear resistant tungsten carbide surfaces 36 formed onto the outer faces of thewedges 29 so that the wearresistant surfaces 36 are flush or aligned with the outer faces of thewedges 29, thereby making the outer faces of thewedges 29 wear resistant. Thewedges 29 may alternatively be made entirely of a wear resistant material, such as ceramic, or may be made wear resistant by other known expedients, such as applying PDC diamond to the faces. - Corresponding
plungers 32 are attached to the upper end of eachwedge 29 and extend upward and inward parallel to theslide surface 45 of eachpocket 3. To facilitate proper operation, the coupling between thewedge 29 and correspondingplungers 32 is preferably non-rigid or has some flexibility to allow some movement between these members. Such a connection will avoid the formation of a high stress point at this location. In the embodiment shown, to attach thewedges 29 to theplungers 32, a bore 8 is formed in the large end of each wedge, as shown inFIG. 5 ; with anannular groove 9 formed therein. As shown inFIG. 15 , the lower ends ofplungers 32 are formed to correspond to bores 8 and have grooves formed thereon to match withgrooves 9. As shown inFIG. 5 , anaccess hole 10 is drilled tangent to groove 9 in eachwedge 29 to allow insertion ofmetal balls 48, of metal such as stainless steel, so the matching grooves are filled with metal balls to thereby attach thewedges 29 to theplungers 32, as seen inFIG. 15 . The access holes 10 are tapped to receive plugs to retain the metal balls in place. -
Complementary bores 46′, which do not communicate with thethroat 15, are provided to receive eachplunger 32. Each bore 46′ has an enlarged section to form aspring chamber 46 and to accommodateseal bushing 33. The seal bushings 33 are installed in fixed relationship within the lower marginal end ofspring chambers 46 and reciprocatingly receive theplungers 32 in sealed relationship therewith by means of the illustrated o-rings 31.Wipers 43 are also added to prevent debris from banning the o-rings 31 during reciprocating movements of theplungers 32. The seal bushings 33 are sealed to thespring chambers 46 by o-rings 49 and are affixed therein by locking rings 35, or by other suitable known means.Springs 34, such as Belleville washers, and preferably of the stacked disk type, are received about eachplunger 32 between theseal bushing 33 and the upper end ofspring chambers 46. Thesprings 34 are thus respectively confined and sealed within thechambers 46 at a location between the upper end ofchamber 46 andseal bushing 33. To prevent harmful effects from high static pressures encountered down hole during operation, thespring chambers 46 must be filled with an incompressible fluid, such as hydraulic oil, which is sealed therein byplugs 51; and all air or gas bubbles should be removed. - In addition, since any reciprocating movement of
plungers 32 will produce a displacement of fluid inchambers 46,complementary bores 46′ extend upward to intersect and provide fluid communication with corresponding radial bores 4, as shown inFIG. 1 . A moveable sealing member 5, such as a free traveling piston is installed in eachbore 4 and moveably sealed therein by an O-ring 6 so as to keep fluid withinchamber 46, bore 46′ and the inner portion ofbore 4. The moveable sealing member 5 could be of a different character, such as a sealed diaphragm or the like, while accommodating fluid displacement. Thus, asplunger 32 moves in or out during operation, corresponding moveable sealing member 5, such as a piston, freely moves in or out to accommodate the change in fluid volume withinchamber 46, A retaining ring 7 is installed inbore 4 to keep piston 5 from inadvertently traveling too far outward inbore 4. Thus, the in or out travel ofplunger 32 andwedge 29 is not hindered nor affected by static down hole pressure nor by fluid pressure withinthroat 15. - A
suitable flange 11 is formed on eachplunger 32 to provide contact withsprings 34; and to abut against theseal bushings 33 so as to limit the outward travel of eachplunger 32 at the appropriate distance. Thesprings 34 are arranged to press against theflanges 11 and thereby bias theplungers 32, and thewedges 29 attached thereto, outward. As will be explained later herein, thewedges 29 andplungers 32 are to be retracted inward by other force means, such as by thrust of thewedges 29 against the rim of the pilot hole formed by thebit 110. - As seen in
FIGS. 1 and 15 , flushingorifices 54 are positioned to provide fluid communication betweenthroat 15 and eachpocket 3 and are sized and arranged to provide an effectual flow of fluid through eachpocket 3 so as to prevent detritus material from packing or jamming around thewedges 29. As shown inFIGS. 1 and 15 ofembodiment 100,orifice 54 may be in the form of a disk made of abrasion resistant material, such as tungsten carbide, having anaperture 40 approximately 0.100 inch to 0.125 inch in diameter. As shown inFIG. 15 ,aperture 40 is preferably tapered and flared outward downstream so as to minimize the velocity of fluid exiting therethrough.Orifice 54 is retained in a suitably formedport 30 by means of a hollow screw 41 and sealed therein by an o-ring 42. Eachport 30 intersectsthroat 15 and provides fluid communication therethrough betweenthroat 15 and eachcorresponding orifice 54. Thus, flushing fluid, such as drilling fluid passing under pressure withinthroat 15, can pass outward through eachorifice 54, outward through eachpocket 3 and around eachwedge 29 so as to remove detritus material or debris which might otherwise pack around thewedges 29 and jam proper movement thereof. - In order to prevent
orifices 54 from becoming clogged by foreign material which might be present in drilling fluid passing throughthroat 15, astrainer sleeve 26 is installed inthroat 15adjacent ports 30, as shown inFIGS. 1 and 15 . The outer surfaces ofstrainer sleeve 26 are formed so that the upper and lower end portions fit closely withinthroat 15, but the intermediate portion is smaller in diameter so that a small but adequateannular space 28 is provide between thesleeve 26 and the wall ofthroat 15 adjacent to theports 30. The inner surface ofsleeve 26 is cylindrical. A plurality, preferably up to 200, strainer holes 37 are drilled insleeve 26 within the region ofannular space 28, but sufficiently above the vicinity ofports 30, as shown inFIG. 15 . Theholes 37 are positioned above and away fromports 30 so as to prevent erosion of theholes 37 due to the swirl offluid entering ports 30. Thus, drilling fluid is permitted to pass fromthroat 15 throughholes 37, throughannular space 28, throughports 30 and throughorifices 54 intopockets 3. The strainer holes 37 are approximately 0.050 inch to 0.070 inch in diameter so as to be smaller than theapertures 40. Thus, foreign material large enough to clogorifices 54 cannot pass throughstrainer sleeve 26 when passing throughthroat 15. Theannular space 28 is, preferably, made no wider than 0.070 inch so that it too prevents clogging oforifices 54. Notice that theapertures 40 are sized to provide a flow rate through each of approximately 10 gpm to 15 gpm at the usual operating pressures. - In tests, it has been found that flushing
fluid exiting orifices 54 and passing throughpockets 3 can cause erosion damage to the sealing surface ofplungers 32. To prevent such erosion damage, aclearance notch 50 is formed on the inner, upper end of eachwedge 29, as shown inFIGS. 5 and 15 ; andports 30 andorifices 54 are positioned so that fluid exitingorifices 54 impinges againstnotches 50 so as to deflect the fluid in a manner that does not erode the surface ofplungers 32. - In normal operation, the main flow of drilling fluid through
throat 15 is to the nozzles of thebit 110, so that foreign material or debris cannot clog the strainer holes 37 because the main flow throughthroat 15 will wash them away towards the nozzles of thebit 110. To further enhance this washing action,throat 15, in the vicinity ofsleeve 26, along withsleeve 26, is made small enough in diameter so that a relatively high fluid velocity is achieved therethrough during normal operation. For example, when around 300 gpm of drilling fluid is provided, 1¼ to 1½ inch inside diameter ofsleeve 26 seems to produce sufficient fluid velocity for effective washing action. To prevent undue erosion ofsleeve 26, preferably,sleeve 26 should be made of case hardened steel, or some harder material. - As shown in
FIGS. 1 , 2, and 15, thebit 110 is equipped with a plurality ofnozzles 25, similar to the arrangement described in my prior U.S. Pat. No. 4,856,601, which are arranged to provide optimum fluid flow restriction and appropriate fluid output velocity. Thenozzles 25 are installed in correspondingnozzle ports 24 which are formed and arranged to communicate withthroat 15. Thenozzles 25 are retained inports 24 by means of threadedretainers 52 and sealed against leak-by means of o-rings 38.Nozzles 25 will usually be made of abrasion resistant material such as tungsten carbide. - As shown in
FIGS. 1 , 2 and 3, a plurality offlow slots 27 are formed in the face ofbit 110 and along the outside ofmain body 1 to permit the return flow of drillingfluid exiting nozzles 25 during operation and to thereby evacuate drilled cuttings from the bore hole. Also, a plurality of cuttingelements 18, usually the PDC type, are installed, positioned and arranged onbit 110 so as to cut rock from the bottom of the borehole asbit 110 is rotated during operation. - As seen in
FIG. 1 , the portion of themain body 1 immediately above thewedges 29 is slightly larger in diameter than the bore hole produced by thedrill bit 110 and has installed therein a plurality of secondarygauge cutting elements 85 which are similar to the cuttingelements 18 on the face ofbit 110. - Notice that the
gauge cutters 85 are shown in hidden lines and are artificially rotated into the positions shown so as to illustrate their cutting profile. Thesecondary gauge cutters 85 are positioned and arranged to produce a borehole large enough in diameter for the entire assembly to pass upward therethrough even when thewedges 29 are fully extended, as shown inFIG. 1 . Thus, thedrill bit 110 and the primary gauge cutters thereof forms a pilot hole which is intended to be enlarged by thesecondary gauge cutters 85 to the final desired diameter. - In order to further prevent packing of detritus material behind or under the
wedges 29, vent holes 80 are formed to extend from the deeper end of eachpocket 3 into eachcorresponding slot 27. As shown, twosuch vents 80 may be employed for eachpocket 3. - In testing, it has been learned that forces generated by
cutters 18 in the bit face, combined with forces generated bygauge cutters 85, can tend to cause the axis of the assembly to wobble relative to the axis of the borehole being drilled. Such axis wobble can cause damage to thegauge cutters 85 or to the bit facecutters 18. Therefore, as seen inFIG. 1 , upper fixed stabilizingsurfaces 12, such as gauge pads, are formed onbody 1 or provided on a separate body member attached to the stabilizing system. As an example, the fixed stabilizingsurfaces 12 could be formed as part of thebody member 1, or could be provided by means of a suitable additional body member having fixed stabilizing surfaces thereon, which is coupled to themain body 1. The fixed stabilizingsurfaces 12 are preferably provided in corresponding relationship to eachpocket 3, and in positions axially behindgauge cutters 85 andradial bores 4, so as to be located at a predetermined axial distance behindwedges 29. In an example, the fixed stabilizing surfaces are positioned such that they are spaced from the corresponding moveable stabilizing members an axial length of not more than three times, and preferably not more than twice the gauge diameter of assembly. The fixed stabilizingsurfaces 12 may also be provided with wearresistant surfaces 14, which can be integral to or can be installed in the surface of eachpad 12 to provide wear resistance.Surfaces 14 may be solid tungsten carbide, or may be impregnated or coated with diamond to achieve maximum wear resistance; or, thepads 12 may be made wear resistant by some other expedient method. The fixed stabilizing surfaces in conjunction with the moveable stabilizing members provide distinct advantages in operation to avoid detrimental wobble and vibration at the drill bit tip. - The
pads 12, withsurfaces 14 provided or installed thereon, are sized and positioned to very nearly coincide with the borehole diameter cut bygauge cutters 85 so that only minimal clearance between thesurfaces 14 and the borehole wall is allowed. Notice that the axial distance betweenwedges 29 and surfaces 14 is relatively short, and configured to prevent axis wobble of the assembly during drilling operation. Thegauge pads 12 are effectively integral to thebody 1. Of course,pads 12 could be made as part of a short profile body, commonly called a “sub”, which could be weldable or otherwise attachable tomain body 1 so as to be effectively integral thereto. Nevertheless, as shown inFIG. 1 ,pads 12 andmain body 1 are a single continuous piece in the preferred embodiment. - As seen in
FIG. 16 , aborehole 60 has adrill string 62 and adrill collar 64 therein; with thestabilizer 100 attached to the lower end thereof. Adrill bit 110 is integrally attached to the lower end of thestabilizer 100. Adrilling rig 70 manipulates thedrill string 62. Thedrill string 62,drill collar 64, together with thestabilizer 100 anddrill bit 110 attached, are inserted in abore hole 60 and rotated in the conventional manner during a drilling operation. In operation, drilling fluid flows at 72 into thedrill string 62, through thedrill string 62, through thethroat 15 of thepresent stabilizer 100, out of thedrill bit 110, back up the bore hole annulus outside thedrill string 62 and returned through ablowout preventer 74 in the usual manner. A shown inFIGS. 1 , 2 and 3,flow slots 27 permit passage of the drilling fluid and, thereby, removal of drilled cuttings from the borehole. - In the above mode of operation, the
wedges 29 will run in a pilot hole formed bydrill bit 110 and the primary gauge cutters thereof, while thesecondary gauge cutters 85 enlarge the bore hole to the desired final diameter. - In a usual operation, drilling fluid flowing through the
present stabilizer 100 is at a relatively elevated pressure withinthroat 15, because of the usual pressure drop measured across thenozzles 25 of thedrill bit 110. However, neither the fluid pressure inthroat 15 nor the fluid pressure outside of stabilizer 1.00 will have any effect on theplungers 32. Due only to the thrust of thesprings 34, theplungers 32 will thrust downward. Thewedges 29 will thus be caused to move downward and outward along theslide surface 45 until the outer face of thewedges 29 abuts the wall of the pilot hole. Thewedges 29 thus are held in contact with the wall of the pilot hole so long as sufficient spring tension is maintained. Also, as the outer surface ofwedges 29, or the borehole wall, slowly wear due to friction against the wall of the pilot hole; the thrust ofsprings 34 will continually forceplungers 32 andwedges 29 downward and outward to maintain the outer face ofwedges 29 in constant rotating abutment with the stationary wall of the pilot hole. - The angle of the slide surfaces 44 and 45, with respect to the axis of
main body 1, is of a selected value so that inward radial force exerted on the outer face of eachwedge 29 produces sufficient friction between the mated slide surfaces 44 and 45 to overcome the resultant upward sliding vector force on thewedges 29, so that thewedges 29 cannot be made to retract by radial force during drilling operation. This is called “radial blocking action” which prevents radial movement of the central axis ofstabilizer 100 andbit 110. The relative angle and arrangement of the slide surfaces 44 and 45 is such to block any radial inward movement of thewedges 29 at any extended position thereof when an inward radial force is exerted on thewedges 29. This is so even if such inward radial force is of a magnitude that would overcome the thrust ofsprings 34 in the absence of the frictional interaction of the slide surfaces 44 and 45. - The frictional interaction between
surfaces surface 44 on eachwedge 29, as described in my prior U.S. Pat. No. 4,842,083, the coefficient of friction is sometimes reduced by conditions of the drilling fluid or other materials present during operation. Since the coefficient of friction tends to increase with the amount of contact pressure per square inch, a shallow but relativelywide relief groove 47, as shown inFIGS. 5 and 15 , is formed longitudinally through the middle ofslide surface 44 on eachwedge 29 to reduce the effective area of eachsurface 44, by one half or more, and thereby increase the contact pressure per square inch between slide surfaces 44 and 45; and thus increase the coefficient of friction and frictional interaction between the slide surfaces 44 and 45. This reduces the amount of spring thrust required in order to affect the “blocking action” previously described; and also reduces the outward force and frictional drag between the outer surface, ofwedges 29 and the wall of the pilot hole. In addition, thelongitudinal groove 47 provides a flow path for drilling fluid traveling back up the borehole annulus to flow under and behind eachwedge 29 and thereby aid in removing detritus material from eachpocket 3. - As shown in
FIG. 2 and inFIGS. 6 through 14 , the face ofbit 110 has wearridges 39 integrally formed thereon immediately trailing and corresponding to the pattern of cuttingelements 18. Thecutters 18 are deeply installed, and theridges 39 are so formed, that the tips ofcutters 18 initially do not extend beyond the surface profile of theridges 39, before any wear occurs on theridges 39. Notice that theridges 39 of the present invention are similar to the fluidflow isolating ridge 39 of my prior U.S. Pat. No. 4,856,601, however, theridges 39 of the present invention are much wider and stronger, so as to be able to actually support the weight applied to thebit 110 during typical drilling operation, without wearing too fast. For example, theridges 39 of the present invention will normally be formed of high grade, hardened steel so as to be at least one-half inch wide, or more, and so as to be quite resistant to wear when rotated against the bottom of a bore hole; and wear resistant materials, such as tungsten carbide, may be applied to theridges 39 to further increase wear resistance. This provides needed stabilization ofbit 110 during the start of drilling a borehole. - For instance, when starting to drill a bore hole, either at the surface or at the bottom of a preliminary, full gauge hole drilled with a conventional drill bit, where no pilot hole exists, the
wedges 29 cannot engage the wall of the full gauge hole and cannot provide any stabilization, initially. In such an instance, if thecutters 18 are allowed to fully engage, or cut into the bottom of the bore hole, the cutting forces will cause chatter or other vibrations that will damage thecutters 18, especially when the rock or other material being drilled is relatively hard. - Hence, in the ridge and cutter arrangement of the present invention, the
strong ridges 39 support the normal weight-on-bit and prevent thecutters 18 from engaging until theridges 39 wear to expose them. As rotation begins with weight-on-bit applied, theridges 39 will normally abrade the borehole bottom sufficiently to form a matching profile pattern thereon. Theridges 39, being held against the matching profile of the borehole bottom by the weight-on-bit, will maintain stability of the bit axis. As rotation continues, theridges 39 will slowly wear and allow thecutters 18 to begin to engage the borehole bottom, which will proportionately increase the drilling and penetration. Notice that, as the lower nose end of eachwedge 29 contacts the rim of the pilot hole formed by thebit 110, thewedges 29 and therespective plungers 32 will be easily pushed upward and inward as themain body 1 andbit 110 continue to rotate, drill and descend while making hole. As drilling continues, a pilot hole will be formed by thebit 110, which will facilitate full engagement and stabilizing action of thewedges 29 against the wall of the pilot hole. - The
ridges 39 are formed and arranged so that, before thewedges 29 are fully engaged and activated, theridges 39 continue to bear most of the weight-on-bit. After thewedges 29 are fully engaged and activated, after about two feet of hole is drilled, theridges 39 continue to wear, usually for two hours or longer, until theridges 39 no longer bear any of the weight-on-bit; and practically all the weight-on-bit is then borne by thecutters 18. Thus, theridges 39 provide temporary stabilization; at least until thewedges 29 are able to fully engage the pilot hole formed by thebit 110. - Since the
ridges 39 are made of tough steel, which is harder than the materials typical casing plugs are made of, a drill bit and stabilizer assembly made according to the present invention can be used to effectively drill out casing plugs, without experiencing damage to thecutters 18. This is a distinct benefit, because conventional PDC bits often experience damaged cutters when drilling out casing plugs at the start of drilling oil or gas wells. Of course, hard materials, such as tungsten carbide, may be applied to theridges 39 so as to predetermine their wear rate or abrasive characteristics. - It should be made clear that the
ridges 39 of the present invention are arranged and intended so as to wear sufficiently, in due course, so that, after drilling has progressed sufficiently, theridges 39 no longer bear any of the weight-on-bit nor any longer retard the cutting and penetrating action of thecutters 18. - During ongoing drilling operation, axis wobble of the assembly is prevented by virtue of the axial spacing between the
wedges 29 and the gauge surfaces 14 and by the limited, or non-existent, clearance between thesurfaces 14 and the bore hole wall. Also, in the event that detritus material accumulates inpockets 3 behind thewedges 29, the detritus material can be forced out of thepockets 3 throughvents 80 and intoslots 27 upon upward movement ofwedges 29. - Also, even under extremely high down hole static pressure, the hydraulic force on
plungers 32 will be equalized by the action of pistons 5 freely moving in bores. - Now, it can be seen from the foregoing that the present invention provides improved means for radial stabilization of a drill bit; such that whirl, chatter and other forms of radial vibration are prevented under a wide range of drilling conditions; and such that the drilling, penetrating and endurance capabilities of a PDC drill bit is maximized.
Claims (27)
1-5. (canceled)
6. A drill bit stabilizing system comprising,
a body member having at least one recess formed therein, the recess housing at least one stabilizing member in moveable relationship to the recess, the at least one stabilizing member comprising a plunger portion provided in a spring chamber formed in the body member, the spring chamber comprising a substantially sealed chamber configured to retain a substantially fixed volume of an incompressible fluid therein, wherein the substantially fixed volume of the incompressible fluid is configured to substantially fill the sealed chamber, and a fluid displacement system in fluid communication with the spring chamber to provide pressure equalization upon movement of the plunger within the spring chamber.
7. The drill bit stabilizing system of claim 6 , wherein the fluid displacement system comprises a displacement cylinder in fluid communication with the spring chamber, and a moveable sealing member within the displacement cylinder which is moveable in response to changes in fluid volume within the spring chamber.
8-12. (canceled)
13. The drill bit stabilizing system of claim 6 , wherein the fluid displacement system comprises a moveable sealing member, wherein the movable sealing member is configured to act on the incompressible fluid retained in the spring chamber, and wherein the movable sealing member is configured to be exposed to a region external to the body member to equalize pressure between the region external to the body member and the incompressible fluid retained in the spring chamber.
14. The drill bit stabilizing system of claim 13 , wherein the moveable sealing member comprises a piston.
15. The drill bit stabilizing system of claim 14 , wherein the piston is configured to be disposed within at least a portion of a bore adjacent the spring chamber.
16. The drill bit stabilizing system of claim 13 , wherein the moveable sealing member comprises a sealed diaphragm.
17. The drill bit stabilizing system of claim 6 , wherein the at least one stabilizing member is configured to be selectively biased to an extended position such that at least a portion of the stabilizing member is configured to engage at least a portion of walls of a borehole, and wherein at least a portion of the stabilizing member is moveable to stabilize a drill bit used in association with the stabilizing system.
18. The drill bit stabilizing system of claim 6 , wherein the fluid displacement system is configured to provide pressure equalization upon movement of the plunger within the spring chamber such that, during use, static downhole pressure in an annulus of a bore hole or fluid pressure within a throat associated with the body member, does not substantially inhibit movement of the at lest one stabilizing member.
19. The drill bit stabilizing system of claim 6 , comprising a spring member configured to be positioned inside the spring chamber during use, wherein the spring member is configured to bias the at least one stabilizing member toward the extended position.
20. The drill bit stabilizing system of claim 6 , further comprising a plurality of stacked disk Belleville washers configured to be positioned in the spring chamber during use, wherein the plurality of stacked disk Belleville washers is configured to bias the at least one stabilizing member toward the extended position.
21. The drill bit stabilizing system of claim 6 , further comprising a seal bushing disposed about the plunger during use, wherein the seal bushing is configured to seal at least a portion of the spring chamber configured to interface with the plunger.
22. The drill bit stabilizing system of claim 6 , wherein the substantially fixed volume of incompressible fluid is substantially isolated from drilling fluid during use.
23. The drill bit stabilizing system of claim 22 , wherein an interior of the spring chamber comprises a biasing member disposed therein, wherein the interior of the spring chamber is substantially isolated such that the biasing member is substantially isolated from drilling fluid during use.
24. The drill bit stabilizing system of claim 6 , wherein the body member comprises a vent hole extending from the recess, wherein the stabilizing member is configured to move within the recess during use, and wherein the vent hole inhibits packing of detritus material within the pocket.
25. A drill bit stabilizing system, comprising:
a body member configured to be disposed in a bore hole during use;
a stabilizing member coupled to the body member, wherein the stabilizing member is configured to move between a retracted position and an extended position during use, and wherein at least a portion of the stabilizing member is configured to engage walls of the bore hole in the expanded position;
a substantially sealed chamber configured to retain a substantially fixed volume of incompressible fluid therein, wherein the substantially fixed volume of the incompressible fluid is configured to substantially fill the sealed chamber, and wherein the substantially sealed chamber comprises a sealing member,
wherein at least a portion of the sealing member is configured to be exposed to at least a portion of a fluid pressure of an annulus of the bore hole during use, and wherein the sealing member is configured such that at least a portion the fluid pressure of the annulus of the bore hole is transferred to the substantially fixed volume of incompressible fluid during use, and wherein the substantially sealed chamber is coupled to the stabilizing member such that at least a portion of a fluid pressure of the incompressible fluid retained in the substantially sealed chamber is configured to provide a biasing force configured to facilitate movement of the stabilizing member.
26. The drill bit stabilizing system of claim 25 , wherein the at least a portion of the sealing member is movable.
27. The drill bit stabilizing system of claim 25 , wherein the stabilizing member comprises a plunger configured to extend into the substantially sealed chamber, and wherein at least a portion of a fluid pressure of the incompressible fluid retained in the substantially sealed chamber is configured to act on at least a portion of the plunger to provide the biasing force configured to facilitate movement of the stabilizing member.
28. The drill bit stabilizing system of claim 25 , further comprising a biasing mechanism at least partially disposed within the substantially sealed chamber, wherein the biasing member is configured to provide a biasing force configured to bias the stabilizing member toward the extended position.
29. The drill bit stabilizing system of claim 25 , wherein the substantially fixed volume of incompressible fluid is substantially isolated from drilling fluid during use.
30. The drill bit stabilizing system of claim 25 , wherein the body member comprises a pocket and a vent hole extending from the pocket, wherein the stabilizing member is disposed in the pocket during use, wherein the stabilizing member is configured to move within the pocket between the retracted position and the extended position during use, and wherein the vent hole inhibits packing of detritus material within the pocket.
31. A drill bit stabilization system, comprising:
a body member configured to be disposed in a bore hole during use, wherein an annulus region located between the body member and walls of the bore hole is exposed to a down hole pressure;
a stabilizing member coupled to the body member, wherein the stabilizing member is configured to move between a retracted position and an extended position during use, wherein at least a portion of the stabilizing member is configured to engage walls of the bore hole in the expanded position;
a substantially sealed chamber configured to retain a substantially fixed volume of incompressible fluid therein, wherein the substantially fixed volume of the incompressible fluid is configured to substantially fill the sealed chamber, wherein a first portion of the sealed chamber is configured to be exposed to at least a portion of the down hole pressure, during use, such that a fluid pressure of the substantially fixed volume of incompressible fluid at least partially equalizes with the downhole pressure during use; and
a biasing mechanism configured to bias the stabilizing member in the extended position during use, wherein at least a portion of the biasing mechanism is located within the sealed chamber.
32. The drill bit stabilization system of claim 31 , wherein the substantially fixed volume of the incompressible fluid is substantially isolated from drilling fluid during use.
33. The drill bit stabilization system of claim 31 , wherein the body member comprises a pocket and a vent hole extending from the pocket, wherein the stabilizing member is disposed in the pocket during use, wherein the stabilizing member is configured to move within the pocket between the retracted position and the extended position during use, and wherein the vent hole inhibits packing of detritus material within the pocket.
34. A drill bit stabilizing system, comprising:
a body member configured to be disposed in a bore hole during use, wherein the body member comprises:
a pocket; and
a vent hole extending from the pocket; and
a stabilizing member disposed in the pocket during use, wherein the stabilizing member is configured to move within the pocket between a retracted position and an extended position during use, and wherein at least a portion of the stabilizing member is configured to engage walls of the bore hole in the expanded position;
35. The drill bit stabilizing system of claim 34 , wherein the vent hole inhibits packing of detritus material within the pocket.
Priority Applications (1)
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US12/698,693 US20110155473A1 (en) | 2002-04-30 | 2010-02-02 | Stabilizing system and methods for a drill bit |
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US11/164,755 US7201237B2 (en) | 2002-04-30 | 2005-12-05 | Stabilizing system and methods for a drill bit |
US11/733,498 US7661490B2 (en) | 2002-04-30 | 2007-04-10 | Stabilizing system and methods for a drill bit |
US12/698,693 US20110155473A1 (en) | 2002-04-30 | 2010-02-02 | Stabilizing system and methods for a drill bit |
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US11/733,498 Expired - Fee Related US7661490B2 (en) | 2002-04-30 | 2007-04-10 | Stabilizing system and methods for a drill bit |
US12/698,693 Abandoned US20110155473A1 (en) | 2002-04-30 | 2010-02-02 | Stabilizing system and methods for a drill bit |
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US11/164,755 Expired - Fee Related US7201237B2 (en) | 2002-04-30 | 2005-12-05 | Stabilizing system and methods for a drill bit |
US11/733,498 Expired - Fee Related US7661490B2 (en) | 2002-04-30 | 2007-04-10 | Stabilizing system and methods for a drill bit |
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US10273759B2 (en) | 2015-12-17 | 2019-04-30 | Baker Hughes Incorporated | Self-adjusting earth-boring tools and related systems and methods |
US10280479B2 (en) | 2016-01-20 | 2019-05-07 | Baker Hughes, A Ge Company, Llc | Earth-boring tools and methods for forming earth-boring tools using shape memory materials |
US10487589B2 (en) | 2016-01-20 | 2019-11-26 | Baker Hughes, A Ge Company, Llc | Earth-boring tools, depth-of-cut limiters, and methods of forming or servicing a wellbore |
US10508323B2 (en) | 2016-01-20 | 2019-12-17 | Baker Hughes, A Ge Company, Llc | Method and apparatus for securing bodies using shape memory materials |
US10633929B2 (en) | 2017-07-28 | 2020-04-28 | Baker Hughes, A Ge Company, Llc | Self-adjusting earth-boring tools and related systems |
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Also Published As
Publication number | Publication date |
---|---|
US20030201125A1 (en) | 2003-10-30 |
AU2003221721A1 (en) | 2003-11-17 |
US20060196697A1 (en) | 2006-09-07 |
WO2003093626A1 (en) | 2003-11-13 |
US20080035379A1 (en) | 2008-02-14 |
US6971459B2 (en) | 2005-12-06 |
MY130917A (en) | 2007-07-31 |
US7201237B2 (en) | 2007-04-10 |
US7661490B2 (en) | 2010-02-16 |
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