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. 10/135,201, filed Apr. 30, 2002 now U.S. Pat. No. 6,971,459, hereby incorporated by reference. 

   TECHNICAL FIELD 
   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. 
   BACKGROUND OF THE INVENTION 
   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. 
   SUMMARY OF THE INVENTION 
   It is therefore an object of the present invention to provide a drill bit 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 full 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. 

   
     BRIEF DESCRIPTION OF THE DRAWINGS 
       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. 
   

   DETAILED DESCRIPTION 
   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. 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 . To facilitate proper operation, 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. In the embodiment shown, to attach the wedges  29  to the plungers  32 , a bore  8  is formed in the large end of each wedge, as shown in  FIG. 5 ; with an annular groove  9  formed therein. As shown in  FIG. 15 , 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. 5 , 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 harming 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 . To prevent harmful effects from high static pressures encountered down hole during operation, 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. 
   In addition, since any reciprocating movement of plungers  32  will produce a displacement of fluid in chambers  46 , complementary bores  46 ′ extend upward to intersect and provide fluid communication with corresponding radial bores  4 , as shown in  FIG. 1 . 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. Thus, as 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 . Thus, 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 . 
   As seen in  FIGS. 1 and 15 , 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 . As shown in  FIGS. 1 and 15  of embodiment  100 , 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. As shown in  FIG. 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 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 . Thus, 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. 
   In order to prevent orifices  54  from becoming clogged by foreign material which might be present in drilling fluid passing through throat  15 , 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 . Thus, 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 . Notice that the apertures  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 through pockets  3  can cause erosion damage to the sealing surface of plungers  32 . To prevent such erosion damage, 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 . 
   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 . To further enhance this washing action, 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,  1-¼  to  1-½  inch inside diameter of sleeve  26  seems to produce sufficient fluid velocity for effective washing action. To prevent undue erosion of sleeve  26 , preferably, sleeve  26  should be made of case hardened steel, or some harder material. 
   As shown in  FIGS. 1 ,  2 , and  15 , 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 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 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. Also, a plurality of cutting elements  18 , usually the PDC type, 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. 
   As seen in  FIG. 1 , 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 . 
   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. 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 . Thus, 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. 
   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 each pocket  3  into each corresponding slot  27 . As shown, two such vents  80  may be employed for each pocket  3 . 
   In testing, it has been learned that forces generated by cutters  18  in the bit face, combined with forces generated by gauge 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 the gauge cutters  85  or to the bit face cutters  18 . Therefore, as seen in  FIG. 1 , upper fixed stabilizing surfaces  12 , such as gauge pads, are formed on body  1  or provided on a separate body member attached to the stabilizing system. As an example, 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 . 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 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 . 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 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. 
   As seen in  FIG. 16 , 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. In 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. A shown in  FIGS. 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 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. 
   In a usual operation, 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 . However, neither the fluid pressure in throat  15  nor the fluid pressure outside of stabilizer  100  will have any effect on 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. Also, as the outer surface of wedges  29 , or the borehole wall, slowly wear due to friction against the wall of the pilot hole; the thrust of springs  34  will continually force plungers  32  and wedges  29  downward and outward to maintain the outer face of wedges  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 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 . 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 of wedges  29  and the wall of the pilot hole. In addition, 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 . 
   As shown in  FIG. 2  and in  FIGS. 6 through 14 , 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 . Notice that 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. For example, 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. 
   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 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. 
   Hence, in the ridge and cutter arrangement of the present invention, 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. As rotation begins with weight-on-bit applied, 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. As rotation continues, 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. Notice that, as the lower nose end of 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 . 
   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 the cutters  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 the ridges  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, 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 . 
   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 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 . 
   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.