Patent Abstract:
A technique facilitates the dependable, long-lasting use of a downhole component coupled into a drill string. In some applications, the downhole component comprises a stabilizer having a plurality of blades extending outwardly from a body, e.g. sleeve. Various features of the downhole component enhance the usefulness and dependability of the downhole component. Examples of such features comprise uniquely shaped surfaces; materials with a desired hardness, toughness, and impact strength; and/or wear protection elements incorporated into the downhole component.

Full Description:
CROSS-REFERENCE TO RELATED APPLICATIONS 
       [0001]    The present document is based on and claims priority to U.S. Provisional Application Ser. No.: 61/970864, filed Mar. 26, 2014, and U.S. Provisional Application Ser. No.: 62/036572, filed Aug. 12, 2014, which are incorporated herein by reference in their entirety. 
     
    
     BACKGROUND 
       [0002]    In many hydrocarbon well applications, wellbores are drilled into a desired hydrocarbon-bearing formation via a variety of drilling systems. For example, drilling operations may be performed with drill strings including a variety of bottom hole assemblies constructed to drill a desired wellbore. In some applications, rotary steerable drilling systems may be used to control the trajectory of the wellbore being drilled. This facilitates the drilling of deviated, e.g. horizontal, wellbores. During drilling, stabilizers and other drilling components of the bottom hole assembly may be subjected to substantial abrasion. This abrasion can be detrimental to the life of the stabilizer or other bottom hole assembly components. Depending on the application, stabilizers may be used with steerable drilling systems to provide contact points with the wellbore wall to facilitate steering. Additionally, stabilizers known as string stabilizers may be used farther up the bottom hole assembly of the drill string to support tools, to reduce shock and vibration, and to reduce stick-slip. 
       SUMMARY 
       [0003]    In general, a system and methodology are provided to facilitate the dependable, long-lasting use of a downhole component coupled into a drill string. In some embodiments, the downhole component may comprise a stabilizer having a plurality of blades extending outwardly from a body, e.g. sleeve. Various features of the downhole component enhance the usefulness and dependability of the downhole component. Examples of such features comprise uniquely shaped surfaces; materials with a desired hardness, toughness, and impact strength; and/or wear protection elements incorporated into the downhole component. 
         [0004]    However, many modifications are possible without materially departing from the teachings of this disclosure. Accordingly, such modifications are intended to be included within the scope of this disclosure as defined in the claims. 
     
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
         [0005]    Certain embodiments of the disclosure will hereafter be described with reference to the accompanying drawings, wherein like reference numerals denote like elements. It should be understood, however, that the accompanying figures illustrate the various implementations described herein and are not meant to limit the scope of various technologies described herein, and: 
           [0006]      FIG. 1  is a side view of an example of a stabilizer, e.g. an abrasion resistant stabilizer, mounted in a drill string, according to an embodiment of the disclosure; 
           [0007]      FIG. 2  is a cross-sectional view of an example of a stabilizer to illustrate mounting of the stabilizer on a collar of a drill string, according to an embodiment of the disclosure; 
           [0008]      FIG. 3  is a side view of another example of a stabilizer, according to an embodiment of the disclosure; 
           [0009]      FIG. 4  is a graphical representation illustrating plots of pull force versus taper angle for varying hole inclinations, according to an embodiment of the disclosure; 
           [0010]      FIG. 5  is a side view of another example of a stabilizer, according to an embodiment of the disclosure; 
           [0011]      FIG. 6  is an orthogonal view of an abrasion resistant sleeve which may be used with a variety of downhole components, including stabilizers, according to an embodiment of the disclosure; 
           [0012]      FIG. 7  is an illustration of a drill string having a plurality of downhole components protected with abrasion resistant sleeves and/or other abrasion resistant features, according to an embodiment of the disclosure; 
           [0013]      FIG. 8  is an illustration of another example of an abrasion resistant component in the form of a rotary valve system, according to an embodiment of the disclosure; and 
           [0014]      FIG. 9  is an illustration of another example of an abrasion resistant component in the form of an impeller which may be used in a variety of downhole components, according to an embodiment of the disclosure. 
       
    
    
     DETAILED DESCRIPTION 
       [0015]    In the following description, numerous details are set forth to provide an understanding of some embodiments of the present disclosure. However, it will be understood by those of ordinary skill in the art that the system and/or methodology may be practiced without these details and that numerous variations or modifications from the described embodiments may be possible. 
         [0016]    With respect to certain embodiments of the present disclosure, a system and methodology are described for facilitating a drilling operation which employs a stabilizer or stabilizers on a drill string. The stabilizer (or stabilizers) comprises an end face or end faces having shallower slopes instead of steep slopes. Steep slopes can sometimes cause the bottom hole assembly to get stuck on a ledge or other obstruction along the wellbore. In some applications, shallower slopes may be employed on both leading and trailing faces. In other applications, a shallower slope may be employed on one of the faces. For example, the shallower slope may be located on a trailing face of the stabilizer to reduce the risk of hanging-up the bottom hole assembly on a ledge or other obstruction while tripping out of the hole. It should be noted the shallower slopes and/or the relatively shallower slope on the trailing face may be employed on a variety of parts, components or entire tools. 
         [0017]    In some applications, the stabilizer may be constructed with a shallow sloped trailing face and a leading face having a steeper slope. The steeper leading face moves the crown (contact point) of the stabilizer forward toward the drill bit. By moving the crown of the stabilizer toward the drill bit, the dogleg capability of the drilling system may be substantially increased. 
         [0018]    Referring generally to  FIG. 1 , an example of a downhole component  10  in the form of a stabilizer mounted in a drilling system  12  is illustrated. However, downhole component  10  may comprise a variety of parts, components or entire tools. In this embodiment, drilling system  12  comprises a drill string  14  having a drill string collar  16  and a drill bit  18 . The stabilizer  10  is mounted on drill string collar  16  and comprises a body  20 , e.g. a tubular body, having an interior surface  22  and an exterior surface  24 . The interior surface  22  faces inwardly toward the drill string collar  16  and the exterior surface  24  faces in a radially outward direction. The stabilizer  10  further comprises a plurality of blades  26  which extend outwardly from exterior surface  24 . The blades  26  extend along at least a portion of the longitudinal length of body  20  and are separated circumferentially by flow channels  28 . In some applications, the blades  26  are arranged helically and thus provide generally helical flow channels  28  therebetween. The flow channels  28  allow flows of fluid to move longitudinally past the stabilizer  10  along drill string  14 . 
         [0019]    The longitudinal ends of blades  26  establish a leading face  30  and a trailing face  32 . Generally, the leading face  30  is on the downhole end toward drill bit  18  and the trailing face  32  is on the uphole end of blades  26 . The leading face  30  is oriented at a leading end angle  34  with respect to exterior surface  24 , and trailing face  32  is oriented at a trailing end angle  36  with respect to exterior surface  24 . Depending on the application, the leading face  30  and/or trailing face  32  may have a shallow slope in the form of a relatively small leading end angle  34  and/or trailing end angle  36 , respectively. In the embodiment illustrated in  FIG. 1 , the leading face  30  has a relatively steep taper, e.g. a leading end angle  34  of 70° or greater. In this embodiment, the trailing face  32  has a shallow taper, e.g. a trailing end angle  36  of 45° or less. In some applications, the shallow taper may comprise a trailing end angle  36  of 30° or less. 
         [0020]    As illustrated, some embodiments may utilize a substantially shallower taper on the trailing face  32  relative to a steeper taper on the leading face  30 . Additionally, the leading face  30  and/or trailing face  32  may be constructed with the leading end angle  34  and the trailing end angle  36 , respectively, formed as compound angles. In other words, one or both of the leading end angle  34  and/or trailing end angle  36  may be formed with a plurality of differently angled slopes. 
         [0021]    The stabilizer  10  may be mounted on drill string collar  16  of drilling system  12  via a variety of structures and techniques. An example of such a structure and technique is illustrated in  FIG. 2 . In this embodiment, the interior surface  22  has an internal diameter profile  38 , e.g. an abutment, located to facilitate construction of a lengthened stabilizer body  20 . The profile  38  is oriented for engagement with a shoulder  40  of drill string collar  16 . Additionally, the stabilizer  10  may be threadably engaged with and tightened against shoulder  40  via a threaded region  42  on collar  16  and a corresponding threaded region  44  along the interior of body  20 . In this example, the drill string collar also may comprise a bit box  46  for engagement with drill bit  18 . The overall arrangement facilitates construction of a longer stabilizer  10  to accommodate the longer, shallower slopes of the face or faces  30 ,  32 . For example, profile  38  acts against the collar shoulder  40  at an internal location which allows the stabilizer to be lengthened by enabling the blades  26  to extend over this internal location. 
         [0022]    Referring generally to  FIG. 3 , another embodiment of the stabilizer  10  is illustrated. In this embodiment, the leading face  30  and the trailing face  32  of blades  26  both have a relatively shallow slope. In other words, the leading end angle  34  and the trailing end angle  36  are relatively small. For example, the shallow slope of the leading face  30  and the trailing face  32  may have leading end angle  34  and trailing end angle  36 , respectively, of 45° or less. In some applications, the shallow taper may comprise both a leading end angle  34  and a trailing end angle  36  of 30° or less. In some applications, a shallower taper on the leading face  30  can limit steerability and dogleg capability. To increase dogleg capability, the slope taper at the leading face  30  may be steeper and the slope taper at the trailing face  32  may be relatively shallower. 
         [0023]    As illustrated by the graph of  FIG. 4 , the face taper angle has an effect on the force applied to the drill string, e.g. the pull force, to overcome friction associated with an obstruction, e.g. a ledge.  FIG. 4  illustrates examples of pull force used to overcome friction for a variety of borehole inclinations and face taper angles. As illustrated, the pull force used to move stabilizer  10  past the obstruction decreases as the face taper angle decreases.  FIG. 4  provides a graphical overview of this relationship for a variety of wellbore types. 
         [0024]    Referring generally to  FIG. 5 , another embodiment of the stabilizer  10  is illustrated. In this embodiment, cutting features  48  are added along the slopes, e.g. the shallow slopes, of leading face  30  and/or trailing face  32 . The cutting features  48  may comprise cutters, such as polycrystalline diamond (PDC) cutters, formed of hard material and positioned along the sloped faces  30  and/or  32 . The cutting features may be oriented to cut away obstructions, such as ledges resulting from washouts, encountered along the wellbore. In some applications, the cutting features may be applied to a non-magnetic stainless steel substrate. 
         [0025]    According to other and/or additional aspects of the present disclosure, various downhole components  10 , e.g. stabilizers, other components, or entire tools, may be constructed in a manner providing resistance to abrasion in well related applications and non-well related applications. For example, the technique may provide increased abrasion resistance in a downhole component deployed in a drilling bottom hole assembly. In some applications, a sleeve is mounted to or constructed as part of the downhole component. The sleeve is formed of materials having suitable hardness, toughness and impact strength, such as materials comprising a tungsten carbide matrix. By way of example, the tungsten carbide matrix may comprise tungsten carbide particles in a suitable matrix, e.g. cobalt, and processed according to appropriate powder metallurgy techniques to form a metal matrix composite referred to herein as tungsten carbide matrix. In some applications, the sleeve may be formed primarily of tungsten carbide matrix. 
         [0026]    In other applications, the sleeve may be formed of a suitable composite material with portions comprising the tungsten carbide mixture. By way of example, the portions of hard tungsten carbide mixture may be bonded to steel or to another material having suitable toughness and impact strength. However, various other materials and material combinations may be used to form the sleeve. The composition of the tungsten carbide matrix also may be adjusted to accommodate various loading effects, thermal effects, and/or other effects likely to be experienced by the sleeve in a given application. The sleeve also may employ a plurality of wear protection elements. Depending on the application, the wear protection elements may be used with or incorporated into a variety of other components. It should be noted the suitable composite material and the plurality of wear protection elements may be used in a variety of parts, components or entire tools. 
         [0027]    In some embodiments, the abrasion resistant components facilitate drilling operations and may be in the form of a stabilizer (or stabilizers) having an abrasion resistant sleeve. One or more of the stabilizers may be employed at various positions along a drill string and in combination with various types of drill string components, such as bottom hole assembly components. In addition to their usefulness in stabilizers, the abrasion resistant sleeves and/or other abrasion resistant features may be used in combination with directional drilling components, measurement-while-drilling components, and logging-while-drilling components. However, the abrasion resistant sleeves and/or other abrasion resistant features also may be used with a variety of other components, such as bottom hole assembly components. Examples include wear bands, kicker plates, filters and screens, telemetry modulators, impellers, turbine blades, cutter blocks for hole enlargement tools, stabilizer blocks for variable gauge stabilizers, and/or other downhole components. 
         [0028]    Depending on the parameters of a given application, the abrasion resistant sleeves may comprise a suitable material or materials, e.g. a composite material having portions formed of tungsten carbide matrix. In some applications, the entire abrasion resistant sleeve may be made of tungsten carbide matrix. The sleeve also may be provided with additional wear protection elements, such as polycrystalline diamond compacts and thermally stable polycrystalline components. The polycrystalline diamond compacts and the thermally stable polycrystalline components can be constructed in a variety of different shapes to provide additional, high abrasion resistance with respect to the sleeves or other components. The additional wear protection elements also may be positioned in optimized patterns or arrangements to help reduce the erosion and abrasive wear. 
         [0029]    Referring again to  FIG. 1 , the component  10 , e.g. stabilizer  10 , may be formed as an abrasion resistant component  10 . The abrasion resistant stabilizer  10  (or other component  10 ) may similarly be mounted on drill string collar  16 . As with embodiments described above, the abrasion resistant stabilizer  10  may comprise the plurality of blades  26  which extend outwardly from exterior surface  24 . Also, the abrasion resistant stabilizer  10  may be used in combination with drill bit  18  and/or in combination with other drill string components. 
         [0030]    As illustrated in  FIG. 6 , the abrasion resistant stabilizer  10  may comprise an abrasion resistant sleeve  50 . The abrasion resistant sleeve  50  may be constructed as the entire abrasion resistant stabilizer  10 , or the abrasion resistant sleeve  50  may be mounted to or incorporated into the stabilizer  10 . In this example, the abrasion resistant sleeve  50  is formed at least in part from tungsten carbide matrix and comprises a plurality of additional wear protection elements  52 . By way of example, the additional wear protection elements  52  may comprise polycrystalline diamond compacts and/or thermally stable polycrystalline components. 
         [0031]    In this stabilizer example, sleeve  50  may be formed with stabilizer blades  26  and the wear protection elements  52  may be mounted on or incorporated into the stabilizer blades  26 . By way of example, the wear protection elements  52  may comprise polycrystalline diamond compact elements  54  and/or thermally stable polycrystalline elements  56 . The wear protection elements  52  may be mounted along a lead edge  58  progressing up along each stabilizer blade  26  and in an arrangement which reduces wear on the lead edge  58 . Additionally, the wear protection elements  52  may be arranged to reduce transversal wear patterns. 
         [0032]    In the embodiment illustrated, the wear protection elements  52  comprise polycrystalline diamond compact elements  54  constructed as high rake cutters provided along the leading edges  58 . In some applications, the polycrystalline diamond compact elements  54  are arranged in rows along the leading edge  58 . In this example, the blades  26  also comprise thermally stable polycrystalline elements  56  positioned to provide additional wear protection. It should be noted, however, the wear protection elements  52  may be formed from a variety of hardened materials. The wear protection elements  52  also may have various shapes and may be arranged in different patterns depending on the environment, the application, and/or the type of abrasion resistant component  10 , e.g. stabilizer  10 . In some applications, sleeve  50  may comprise threaded regions  59  (or other suitable connector mechanisms) at its longitudinal ends to facilitate attachment to adjacent well string components. 
         [0033]    Referring generally to  FIG. 7 , other embodiments of abrasion resistant components  10  are illustrated. In this example, the abrasion resistant components  10  are assembled into drill string  14  deployed in a wellbore  60 . The abrasion resistant components  10  incorporate abrasion resistant sleeves  50  which provide the components with high abrasion resistance. Again, the abrasion resistant sleeves  50  may be formed in whole or in part of tungsten carbide matrix. In some applications, the abrasion resistant sleeves  50  may be used to protect antennas  62  of, for example, measurement-while-drilling components and/or logging-while-drilling components. The abrasion resistant sleeves  50  also may be used in conjunction with, e.g. as part of, stabilizers to form abrasion resistant stabilizer components  10  as described above. The abrasion resistant sleeves  50  in these embodiments may again comprise or be combined with a variety of the wear protection elements  52  formed of various hard materials. The wear protection elements  52  may be attached to sleeve  50  via suitable attachment mechanisms, such as threaded attachment mechanisms, weldments, independent fasteners, and/or other suitable attachment mechanisms. 
         [0034]    As illustrated in  FIG. 8 , the abrasion resistant component  10  also may comprise a variety of rotary valves  64  in which hardened, wear protection elements  52  are combined with various components of the valve  64 . In some downhole applications, the rotary valve  64  is combined with a torque impeller  66 , and the wear protection elements  52  may be mounted on or formed with impeller blades and/or other system components to provide a high resistance to abrasion from, for example, sand and other particulates. 
         [0035]    As illustrated in  FIG. 9 , for example, a variety of impellers  66  may incorporate wear protection elements  52  along impeller blades  68  and/or at other portions of the impeller  66  to provide resistance to abrasion. As discussed above, however, the abrasion resistant sleeves  50  and/or wear protection elements  52  may be used with many types of components to construct abrasion resistant components  10 . The abrasion resistant sleeves  50  and/or wear protection elements  52  may be combined with wear bands, kicker plates, filters and screens, telemetry modulators, turbine blades, cutter blocks for hole enlargement tools, stabilizer blocks for variable gauge stabilizers, and/or other downhole components. 
         [0036]    Depending on the application, the wear resistant components  10  may have a variety of configurations comprising other and/or additional components. For example, the wear resistant components  10  may comprise a variety of rotary steerable system components such as pads, e.g. actuator pads, or kickers. In stabilizer applications, the shape and structure of the stabilizer body and stabilizer blades may vary in size and configuration depending on the parameters of a given application and environment. Similarly, a variety of materials may be used to construct the wear protection elements  52 . Additionally, the wear protection elements  52  may be combined with many types of abrasion resistant sleeves  50  and/or other types of abrasion resistant components in well applications and non-well applications. In some applications, the sleeve  50  may utilize features, e.g. tongue and groove features, to facilitate making-up the connection with adjacent components. 
         [0037]    Although a few embodiments of the disclosure have been described in detail above, those of ordinary skill in the art will readily appreciate that many modifications are possible without materially departing from the teachings of this disclosure. Accordingly, such modifications are intended to be included within the scope of this disclosure as defined in the claims.

Technology Classification (CPC): 4