Abstract:
Position indication in multiplexed downhole well tools. A method of selectively actuating and indicating a position in a well includes selecting at least one well tool from among multiple well tools for actuation by flowing direct current in one direction through a set of conductors in the well, the well tool being deselected for actuation when direct current flows through the set of conductors an opposite direction; and detecting a varying resistance across the set of conductors as the selected well tool is actuated, the variation in resistance providing an indication of a position of a portion of the selected well tool.

Description:
TECHNICAL FIELD 
       [0001]    This disclosure relates generally to equipment utilized and operations performed in conjunction with a subterranean well and, in one example described below, more particularly provides a cutter for use in well tools. 
       BACKGROUND 
       [0002]    Well tools (such as, drill bits and reamers) can include cutters for cutting into formation rock. However, in some situations, cutters can become damaged. Damaged cutters can reduce a rate of penetration through formation rock and can require time-consuming (and, thus, expensive) replacement. Therefore, it will be appreciated that improvements are continually needed in the art of constructing cutters for use in well tools. 
     
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
         [0003]      FIG. 1  is a representative partially cross-sectional view of a well system and associated method which can embody principles of this disclosure. 
           [0004]      FIG. 2  is a representative perspective view of a drill bit which may be used in the system and method of  FIG. 1 , and which can embody the principles of this disclosure. 
           [0005]      FIG. 3  is a representative cross-sectional view of a cutter of a well tool cutting into a formation rock. 
           [0006]      FIGS. 4 &amp; 5  are representative perspective and end views, respectively, of the cutter of  FIG. 3 . 
           [0007]      FIGS. 6-9  are representative cross-sectional views of additional configurations of the cutter. 
           [0008]      FIGS. 10 &amp; 11  are representative side views of additional configurations of the cutter. 
           [0009]      FIGS. 12 &amp; 13  are representative cross-sectional views of additional configurations of the cutter. 
           [0010]      FIGS. 14 &amp; 15  are representative end views of additional configurations of the cutter. 
           [0011]      FIGS. 16-19  are representative cross-sectional views of additional configurations of the cutter. 
           [0012]      FIG. 20  is a representative cross-sectional view of an additional configuration of the cutter cutting into a formation rock. 
           [0013]      FIGS. 21 &amp; 22  are representative cross-sectional views of additional configurations of the cutter. 
           [0014]      FIG. 23  is a representative end view of another configuration of the drill bit. 
           [0015]      FIG. 24  is a representative perspective view of another configuration of the drill bit. 
           [0016]      FIG. 25  is a representative end view of another configuration of the drill bit. 
       
    
    
     DETAILED DESCRIPTION 
       [0017]    Representatively illustrated in  FIG. 1  is a system  10  and associated method which can embody principles of this disclosure. However, it should be clearly understood that the system  10  and method are merely one example of an application of the principles of this disclosure in practice, and a wide variety of other examples are possible. Therefore, the scope of this disclosure is not limited at all to the details of the system  10  and method described herein and/or depicted in the drawings. 
         [0018]    In the  FIG. 1  example, a wellbore  12  is being drilled with a drill string  14 . The drill string  14  includes various well tools  16 ,  18 ,  20 ,  22 ,  24 . In this example, the well tool  16  comprises one or more drill collars, the well tool  18  is a stabilizer, the well tool  20  is a reamer, the well tool  22  is an adapter or crossover, and the well tool  24  is a drill bit. 
         [0019]    Many other well tools could be included in the drill string  14 . Different combinations, arrangements and numbers of well tools can be used in other examples. Therefore, the scope of this disclosure is not limited to any particular type, number, arrangement or combination of well tools. 
         [0020]    The well tool  24  is used as an example in the further description below to demonstrate how the principles of this disclosure can be applied in actual practice. However, it should be clearly understood that the scope of this disclosure is not limited to manufacture of drill bits or any other particular type of well tool. Any well tool which includes one or more cutting structures may potentially benefit from the principles of this disclosure. 
         [0021]      FIG. 2  is a representative perspective view of the drill bit (well tool  24 ) which may be used in the system  10  and method of  FIG. 1 , and which can embody the principles of this disclosure. Of course, the drill bit may be used in other systems and methods, in keeping with the principles of this disclosure. 
         [0022]    In  FIG. 2 , it may be seen that the well tool  24  is of the type known to those skilled in the art as a fixed cutter drill bit. However, other types of drill bits (e.g., coring bits, “impregnated” bits, etc.) can be used in other examples. 
         [0023]    The drill bit depicted in  FIG. 2  includes multiple downwardly and outwardly extending blades  26 . Each blade  26  has mounted thereon multiple cutters  30 , each of which includes a cutting layer  28  embedded in a substrate  32 . 
         [0024]    The cutting layer  28  can comprise a polycrystalline diamond compact (PDC) “insert,” and the substrate  32  can comprise a tungsten carbide material. However, the scope of this disclosure is not limited to any particular materials and/or structures used in the cutters  30 . 
         [0025]      FIG. 3  is a representative cross-sectional view of one of the cutters  30  of the well tool  24  cutting into a formation rock  34 . For clarity of illustration and description, the cutter  30  is depicted in  FIG. 3  apart from a remainder of the well tool  24 . 
         [0026]    In the  FIG. 3  example, the cutter  30  is displacing to the left (as indicated by arrow  36 ) in its normal direction of travel (i.e., in a direction corresponding to how the well tool  24  is configured for use in cutting into the formation rock  34 ). Typically, drill bits designed for use in wells are configured for right-hand or clockwise rotation and so, viewed from a side of a drill bit, a cutter thereof would appear to be displacing to the left. However, the scope of this disclosure is not limited to any particular direction of displacement of the cutter  30 . 
         [0027]    With the cutter  30  displacing to the left as viewed in  FIG. 3 , a force  38  will be applied to a leading face  40  of the cutting layer  28 . The face  40  is termed a “leading” face since, with the cutter  30  displacing in its normal direction of travel, the face  40  contacts and cuts into the formation rock  34 . 
         [0028]    In the  FIG. 3  example, the leading face  40  is angled relative to a vertical (as depicted in  FIG. 3 ) line  42  by an angle β 1  known to those skilled in the art as a back rake angle (typically approximately 10 to 30 degrees). A depth of cut DOC of the cutter  30  is, in this example, equal to a distance by which the cutting layer  28  protrudes from the substrate  32 . 
         [0029]    Note that, opposite the leading face  40  on the cutting layer  28  is a trailing face  44 . In this example, the leading and trailing faces  40 ,  44  comprise circular planar surfaces on the cutting layer  28 , which is in the form of a solid cylinder, and the leading and trailing faces are parallel to each other. However, the scope of this disclosure is not limited to any particular shapes or orientation of the cutting layer  28  and/or leading and trailing faces  40 ,  44 . 
         [0030]    The substrate  32  completely covers the trailing face  44  and partially covers the leading face  40 . In this manner, the substrate  32  can support the cutting layer  28  whether the cutter  30  is displacing in its normal direction (as indicated by arrow  36 ), or in a reverse direction. 
         [0031]    With the cutter  30  displacing as depicted in  FIG. 3 , the substrate  32  in contact with the trailing face  44  will react the force  38  produced by the cutting layer  28  cutting into the formation rock  34  (the substrate in contact with the trailing face will be placed in compression). In addition, if the cutter  30  should inadvertently displace in a reverse direction while contacting the formation rock  34  (such as, due to torsional vibration, stick-slip or whirling of the well tool  24 ), an oppositely directed force produced by such displacement will be reacted by the substrate  32  in contact with the leading face  40  (the substrate in contact with the leading face will be placed in compression). 
         [0032]    Thus, no matter the direction in which the cutter  30  contacts the formation rock  34 , the cutting layer  28  is supported by the substrate  32  in compression. This feature of the cutter  30  can substantially reduce the incidence of chipping or cracking of the cutting layer  28 , and substantially reduce separation of the cutting layer from the substrate  32 . 
         [0033]      FIGS. 4 &amp; 5  are representative perspective and end views, respectively, of the cutter of  FIG. 3 . In these views, the manner in which the cutting layer  28  is embedded in the substrate  32 , and the manner in which the depth of cut DOC is determined by a distance by which the cutting layer extends outward from the substrate can be clearly seen. 
         [0034]    In  FIGS. 3 &amp; 4 , it may be seen that the cutting layer  28  is positioned at approximately a longitudinal middle of the substrate  32 . In other examples, the cutting layer  28  could be positioned more forward or more rearward relative to the substrate  32 . 
         [0035]    In a method of manufacturing the cutter  30 , the cutting layer  28  can be separately formed, and then embedded in a powdered tungsten carbide matrix material appropriately placed in a mold. A jig can be used to position the cutting layer  28  in the mold. The matrix material can then be sintered. 
         [0036]    Suitable tungsten carbide materials include D63™ and PREMIX 300™, marketed by HO Starck of Newton, Mass. USA. Various types of tungsten carbide may be used, including, but not limited to, stoichiometric tungsten carbide particles, cemented tungsten carbide particles, and/or cast tungsten carbide particles. Other matrix materials may be used, as well. 
         [0037]    The matrix material can comprise a blend of matrix powders. A binding agent (such as, copper, nickel, iron, alloys of these, an organic tackifying agent, etc.) can be mixed with the matrix material prior to loading the matrix material into the mold. 
         [0038]    An effective binding agent can be any material that would bind, soften or melt at the sintering temperatures, and not burn off or degrade at those temperatures. High-temperature binding agents can comprise compositions having softening temperatures of about 260° C. (500° F.) and above. As used herein, the term “softening temperature” refers to the temperature above which a material becomes pliable, which is typically less than a melting point of the material. 
         [0039]    Examples of suitable high-temperature binding agents can include copper, nickel, cobalt, iron, molybdenum, chromium, manganese, tin, zinc, lead, silicon, tungsten, boron, phosphorous, gold, silver, palladium, indium, titanium, any mixture thereof, any alloy thereof, and any combination thereof. Non-limiting examples may include copper-phosphorus, copper-phosphorous-silver, copper-manganese-phosphorous, copper-nickel, copper-manganese-nickel, copper-manganese-zinc, copper-manganese-nickel-zinc, copper-nickel-indium, copper-tin-manganese-nickel, copper-tin-manganese-nickel-iron, gold-nickel, gold-palladium-nickel, gold-copper-nickel, silver-copper-zinc-nickel, silver-manganese, silver-copper-zinc-cadmium, silver-copper-tin, cobalt-silicon-chromium-nickel-tungsten, cobalt-silicon-chromium-nickel-tungsten-boron, manganese-nickel-cobalt-boron, nickel-silicon-chromium, nickel-chromium-silicon-manganese, nickel-chromium-silicon, nickel-silicon-boron, nickel-silicon-chromium-boron-iron, nickel-phosphorus, nickel-manganese, and the like. Further, high-temperature binding agents may include diamond catalysts, e.g., iron, cobalt and nickel. 
         [0040]    Certain matrix materials may not require binding agents. Matrix powders comprising iron, nickel, cobalt or copper can bond through solid state diffusion processes during the sintering process. Other matrix materials that have very high melting temperatures (e.g., W, WC, diamond, BN, and other nitrides and carbides) may utilize a binding agent, because the high temperatures which produce solid state diffusion may be uneconomical or undesirable. 
         [0041]    It is not necessary for the matrix material to comprise tungsten carbide. A matrix powder or blend of matrix powders useful here generally lends erosion resistance to a resulting hard composite material, including a high resistance to abrasion and wear. The matrix powder can comprise particles of any erosion resistant materials which can be bonded (e.g., mechanically) with a binder to form a hard composite material. Suitable materials may include, but are not limited to, carbides, nitrides, natural and/or synthetic diamonds, steels, stainless steels, austenitic steels, ferritic steels, martensitic steels, precipitation-hardening steels, duplex stainless steels, iron alloys, nickel alloys, cobalt alloys, chromium alloys, and any combination thereof. 
         [0042]    Binder materials may cooperate with the particulate material(s) present in the matrix powders to form hard composite materials with enhanced erosion resistance. A suitable commercially available binder material is VIRGIN BINDER 453D™ (copper-manganese-nickel-zinc), marketed by Belmont Metals, Inc. 
         [0043]    The binder material may then be placed on top of the mold, and may be optionally covered with a flux layer. A cover or lid may be placed over the mold as necessary. The mold assembly and materials disposed therein may be preheated and then placed in a furnace. 
         [0044]    When the melting point of the binder material is reached, the resulting liquid binder material infiltrates the matrix powder. The mold may then be cooled below a solidus temperature of the binder material to form the hard composite material. Additional details of an example method of forming a hard, erosion and impact resistant tungsten carbide structure can be found in International Application No. PCT/US12/39925, entitled “Manufacture of Well Tools with Matrix Materials.” 
         [0045]    After the cutter  30  is removed from the mold, it can be secured onto a blade  26  (see  FIG. 1 ) by, for example, brazing. Other techniques may be used for securing the cutter  30  to a blade  26  or other structure of the well tool  24 , or for securing the cutter to other types of well tools (such as, the well tool  20 —a reamer). 
         [0046]    Other manufacturing procedures may be used for constructing the cutter  30 . For example, the cutting layer  28  could be press-fit into the substrate  32 , or other mechanical attachment methods or bonding techniques could be used. Thus, the scope of this disclosure is not limited to any particular process for manufacturing the cutter  30 . 
         [0047]      FIGS. 6-9  are representative cross-sectional views of additional configurations of the cutter  30 . These configurations are similar in most respects to the configuration of  FIGS. 3-5 , but differ in some significant respects discussed below. 
         [0048]    In  FIG. 6 , the substrate  32  is angled upward (as viewed in  FIG. 6 ) away from the cutting layer  28 . The angles λ and α can be varied to produce correspondingly varied depths of cut. 
         [0049]    In  FIG. 7 , the substrate is spaced farther from a lower edge of the cutting layer  28  on a leading side of the cutting layer, as compared to on a trailing side of the cutting layer. The spaced distances δ 1  and δ 2  can be varied to produce correspondingly varied depths of cut. 
         [0050]    In  FIG. 8 , a combination of the techniques illustrated in  FIGS. 6 &amp; 7  is used. Each of the distances δ 1  and δ 2 , and angles λ and α, can be varied to produce correspondingly varied depths of cut. 
         [0051]    In  FIG. 9 , a leading end  46  of the substrate  32  is spherically rounded, with a radius R. The spaced distances δ 1  and δ 2  can be varied to produce correspondingly varied depths of cut, as with the configuration of  FIG. 7 . 
         [0052]      FIGS. 10 &amp; 11  are representative side views of additional configurations of the cutter  30 . In these configurations, the substrate  32  is shaped to match, or at least approximate, a path traversed by the cutter  30  as it displaces with the well tool  24 . 
         [0053]    In  FIG. 10 , the substrate  32  is in the shape of an arc. In  FIG. 11 , the substrate  32  is angled between leading and trailing sides of the cutting layer  28 . Such an angled configuration may be used to approximate an arc, to conform to a well tool surface, or for another purpose. 
         [0054]      FIGS. 12 &amp; 13  are representative cross-sectional views of additional configurations of the cutter  30 . In these configurations, a non-planar interface  48  exists between the cutting layer  28  and the substrate  32 . The non-planar interface  48  can help to prevent separation of the cutting layer  28  from the substrate  32 . 
         [0055]    In  FIG. 12 , the non-planar interface  48  is due to grooves formed on a surface of the trailing face  44  of the cutting layer  28 . In  FIG. 13 , non-planar interfaces  48  are formed where the substrate  32  contacts both the leading and trailing faces  40 ,  44  of the cutting layer  28 . 
         [0056]      FIGS. 14 &amp; 15  are representative end views of additional configurations of the cutter  30 . In these configurations, the substrate  32  is in the form of a cylinder having a circular cross-section, but the cutting layer  28  is in the form of a cylinder having an elliptical cross-section (a major radius a being larger than a minor radius b of the elliptical cross-section). 
         [0057]    In  FIG. 14  the major radius a is vertical, and in  FIG. 15  the major radius a is horizontal. These configurations demonstrate that it is not necessary for the cutting layer  28  and substrate  32  to have similar shapes, or for the cutting layer to have any particular orientation relative to the substrate. 
         [0058]      FIGS. 16 &amp; 17  are representative cross-sectional views of additional configurations of the cutter  30 . In these configurations, chamfers  50  are formed on a lower edge of the cutting layer  28 , in order to reduce point loading and resulting chipping of the cutting layer. In  FIG. 16  a single chamfer  50  is used, and in  FIG. 17  multiple chamfers are used. 
         [0059]      FIGS. 18 &amp; 19  are representative cross-sectional views of additional configurations of the cutter  30 . In these configurations, the leading face  40  is not perpendicular to a side face  52  of the cutting layer  28 , thereby producing a cutting edge angle φ that is not a right angle. In  FIG. 18  the cutting edge angle φ is greater than ninety degrees, and in  FIG. 19  the cutting edge angle φ is less than ninety degrees. 
         [0060]      FIG. 20  is a representative cross-sectional view of an additional configuration of the cutter  30  cutting into a formation rock  34 . This configuration demonstrates that the back rake angle β 1  can be produced by techniques other than inclining the cutting layer  28  in the substrate  32 . 
         [0061]    In this example, the substrate  32  is itself inclined to produce the back rake angle β 1 . The depth of cut DOC is determined by the combination of the distance by which the cutting layer  28  protrudes from the substrate  32 , the back rake angle β 1  (in this example, the angle of inclination of the substrate) and the leading angle α. 
         [0062]      FIGS. 21 &amp; 22  are representative cross-sectional views of additional configurations of the cutter  30 . In these configurations, multiple cutting layers  28  are embedded in the substrate  32 . 
         [0063]    In  FIG. 21 , the cutting layers  28  are parallel to each other and spaced apart in the substrate  32 . The cutting layers  28  protrude from the substrate  32  by different respective distances δ 2  and δ 3 , which can be varied to produce a desired depth of cut of the cutter  30 . The configuration of  FIG. 22  is similar to that of  FIG. 21 , but the cutting layers  28  in the  FIG. 22  configuration are not parallel to each other. 
         [0064]      FIG. 23  is a representative end view of another configuration of the drill bit (well tool  24 ). In this configuration, the cutter  30  configuration of  FIG. 10  is used. Multiple cutters  30  are secured to a cutting face  56  of each of three blades  26  of the well tool  24 . 
         [0065]    Note that the cutting layers  28  are positioned at an approximate middle of each of the cutting faces  56  of the blades  26 . The substrate  32 , extending both forward and rearward of the cutting layer  28  of each cutter  30 , helps to stabilize the well tool  24  as it penetrates a formation rock. 
         [0066]      FIG. 24  is a representative perspective view of an upper end of another configuration of the drill bit (well tool  24 ). In this configuration, the cutter  30  configuration of  FIGS. 3-5  is used. As in the configuration of  FIG. 23 , the cutting layers  28  are positioned at approximately a middle of the cutting faces  56  of the blades  26 . 
         [0067]      FIG. 25  is a representative end view of another configuration of the drill bit (well tool  24 ). In this configuration, the cutter  30  configuration of  FIG. 10  is used in a cone cutter portion  54  of the cutting face  56  of each blade  26  of the drill bit. 
         [0068]    In each of the  FIGS. 23-25  configurations of the well tool  24 , the cutters  30  can be configured so that the depth of cut of the cutters is produced as desired. Use of the substrate  32  on the leading side of the cutting layer  28 , as well as on the trailing side of the cutting layer, provides additional flexibility and control over the depth of cut. 
         [0069]    It may now be fully appreciated that the above disclosure provides significant advances to the art of constructing well tools with cutters. In examples described above, the cutters  30  are resistant to chipping and cracking of the cutting layers  28 , and are resistant to separation of the cutting layers from the substrates  32 . In addition, depth of cut can be more precisely controlled by varying certain parameters of the cutters  30 . 
         [0070]    The above disclosure provides to the art a well tool  24 . In one example, the well tool  24  can comprise a cutter  30  including at least one cutting layer  28  and a substrate  32 . The cutting layer  28  has a leading face  40 , and the substrate  32  partially overlies the leading face  40 . 
         [0071]    The cutting layer  28  may be positioned approximately at a longitudinal middle of the substrate  32 . 
         [0072]    A depth of cut DOC of the cutter  30  can be determined by a distance δ 1 - 3  by which the cutting layer  28  protrudes from the substrate  32 . 
         [0073]    The cutter  30  can comprise multiple cutting layers  28  in the substrate  32 . 
         [0074]    The cutting layer  28  may be embedded in the substrate  32 . 
         [0075]    The cutting layer  28  can have a trailing face  44  opposite the leading face  40 , with the substrate  32  at least partially overlying the trailing face  44 . 
         [0076]    At least a portion of an interface  48  between the substrate  32  and the cutting layer  28  may be non-planar. 
         [0077]    The cutting layer  28  can comprise a polycrystalline diamond compact (PDC). In other examples, other materials may be used in the cutting layer  28 . 
         [0078]    The substrate  32  can comprise a tungsten carbide material. In other examples, other materials may be used in the substrate  32 . 
         [0079]    The cutter  30  may be secured on a blade  26  of the well tool  24 . In other examples, the cutter  30  can be secured to other portions of a well tool (such as, to a body or arm of the well tool). 
         [0080]    A method of constructing a well tool  24  is also described above. In one example, the method can comprise: forming a cutter  30  by at least partially embedding at least one cutting layer  28  in a substrate  32 ; and securing the cutter  30  to the well tool  24 . 
         [0081]    The embedding step can include partially covering a leading face  40  of the cutting layer  28  with the substrate  32 . The embedding step can include at least partially covering a trailing face  44  of the cutting layer  28  with the substrate  32 . 
         [0082]    The embedding step can include positioning the cutting layer  28  at an approximate longitudinal middle of the substrate  32 . 
         [0083]    The embedding step can include setting a depth of cut DOC of the cutter  30  by protruding the cutting layer  28  from the substrate  32  a predetermined distance δ 1 - 3 . 
         [0084]    The forming step can include embedding multiple cutting layers  28  in the substrate  32 . 
         [0085]    The embedding step can include contacting the substrate  32  with a non-planar surface of the cutting layer  28 . 
         [0086]    The securing step can include securing the cutter  30  on a blade  26  of the well tool  24 . 
         [0087]    A drill bit (such as, well tool  24 ) is also described above. In one example, the drill bit can comprise a drill bit blade  26 , and a cutter  30  secured on the drill bit blade  26 . The cutter  30  can include a substrate  32  and at least one cutting layer  28  embedded in the substrate  32 , with the substrate  32  overlying leading and trailing faces  40 ,  44  of the cutting layer  28 . 
         [0088]    The substrate  32  may only partially overly the leading face  40 . The substrate  32  may completely overly the trailing face  44 . 
         [0089]    Although various examples have been described above, with each example having certain features, it should be understood that it is not necessary for a particular feature of one example to be used exclusively with that example. Instead, any of the features described above and/or depicted in the drawings can be combined with any of the examples, in addition to or in substitution for any of the other features of those examples. One example&#39;s features are not mutually exclusive to another example&#39;s features. Instead, the scope of this disclosure encompasses any combination of any of the features. 
         [0090]    Although each example described above includes a certain combination of features, it should be understood that it is not necessary for all features of an example to be used. Instead, any of the features described above can be used, without any other particular feature or features also being used. 
         [0091]    It should be understood that the various embodiments described herein may be utilized in various orientations, such as inclined, inverted, horizontal, vertical, etc., and in various configurations, without departing from the principles of this disclosure. The embodiments are described merely as examples of useful applications of the principles of the disclosure, which is not limited to any specific details of these embodiments. 
         [0092]    In the above description of the representative examples, directional terms (such as “above,” “below,” “upper,” “lower,” etc.) are used for convenience in referring to the accompanying drawings. However, it should be clearly understood that the scope of this disclosure is not limited to any particular directions described herein. 
         [0093]    The terms “including,” “includes,” “comprising,” “comprises,” and similar terms are used in a non-limiting sense in this specification. For example, if a system, method, apparatus, device, etc., is described as “including” a certain feature or element, the system, method, apparatus, device, etc., can include that feature or element, and can also include other features or elements. Similarly, the term “comprises” is considered to mean “comprises, but is not limited to.” 
         [0094]    Of course, a person skilled in the art would, upon a careful consideration of the above description of representative embodiments of the disclosure, readily appreciate that many modifications, additions, substitutions, deletions, and other changes may be made to the specific embodiments, and such changes are contemplated by the principles of this disclosure. For example, structures disclosed as being separately formed can, in other examples, be integrally formed and vice versa. Accordingly, the foregoing detailed description is to be clearly understood as being given by way of illustration and example only, the spirit and scope of the invention being limited solely by the appended claims and their equivalents.