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CROSS-REFERENCE TO RELATED APPLICATION 
     The present application is a continuation-in-part of U.S. application Ser. No. 13/448,060 filed Apr. 16, 2012 now abandoned, and claims the benefit thereof. 
    
    
     BACKGROUND 
     The present invention relates to packer, bridge plug and frac plugs type tools used in wellbores and more particularly to retaining assemblies, such as extrusion limiters or retaining shoes, used in packer and bridge plug type tools. 
     In the drilling or reworking of oil wells, a great variety of downhole tools are used. For example, but not by way of limitation, it is often desirable to seal tubing or other pipe in the casing of the well, such as when it is desired to pump cement or other slurry down the tubing and force the cement or slurry around the annulus of the tubing or out into a formation. It then becomes necessary to seal the tubing with respect to the well casing and to prevent the fluid pressure of the slurry from lifting the tubing out of the well or for otherwise isolating specific zones in a well. Downhole tools referred to as packers and bridge plugs are designed for these general purposes and are well known in the art of producing oil and gas. 
     When it is desired to remove many of these downhole tools from a wellbore, it is frequently simpler and less expensive to mill or drill them out rather than to implement a complex retrieving operation. In milling, a milling cutter is used to grind the packer or plug, for example, or at least the outer components thereof, out of the wellbore. In drilling, a drill bit is used to cut and grind up the components of the downhole tool to remove it from the wellbore. This is a much faster operation than milling, but requires the tool to be made out of materials that can be accommodated by the drill bit. To facilitate removal of packer type tools by milling or drilling, packers and bridge plugs have been made, to the extent practical, of non-metallic materials such as engineering grade plastics and composites. 
     Packer tools and other wellbore isolation devices sometimes have elements that undesirably protrude radially and inadvertently contact a wellbore, a casing within a wellbore, or other object. Such contact sometimes results in damage to the packer tool and/or premature transitioning of the device from a run in configuration to a set configuration. For example, some conventional slip segments of wellbore isolation devices are held together somewhat tightly against a mandrel through the use of one or more bands. The bands may be intended to stretch or fracture when the tool is activated in order to allow deployment. However, the bands often protrude radially and, thus, offer limited resistance to inadvertent deployment when the wellbore isolation device undergoes inadvertent perturbation. 
     SUMMARY 
     The present invention provides a downhole apparatus that is more resistant to inadvertent deployment than prior art downhole apparatuses. 
     In one embodiment of the invention there is provided a downhole apparatus for use in a wellbore. The apparatus has a mandrel having a longitudinal axial centerline and a radial direction perpendicular to the longitudinal axial centerline. A sealing assembly is disposed about the mandrel. The sealing assembly is radially expandable from an unset position to a set position in response to the application of axial force on the sealing assembly. In the set position the sealing assembly engages the wellbore. The invention also includes at least one retaining assembly for retaining the sealing assembly and resisting extrusion of the sealing assembly. The retaining assembly is proximate to the sealing assembly and has a plurality of segments disposed about the mandrel. The plurality of segments is adapted to resist extrusion of the sealing assembly and adapted to expand radially to engage the wellbore when the sealing assembly is in the set position. When the sealing assembly is in the unset position, the segments define an outer surface facing the wellbore and at least one end surface extending from the outer surface towards the mandrel. The end surface has a groove that extends around the end surface wherein the groove is not exposed to the wellbore. Additionally, at least when the sealing assembly is in the unset position, the retaining assembly further comprises a band positioned in the groove and suitable for holding the plurality of segments in place about the mandrel. 
     In another embodiment of the invention there is provided a retaining assembly for limiting the extrusion of a sealing assembly disposed about a mandrel. The sealing assembly is movable from an unset position to a set position in a wellbore, and the sealing assembly seals the wellbore when moved to the set position. The retaining assembly has a plurality of segments with each segment adjacent to at least one other segment. When the sealing assembly is in the unset position the segments define: an inner surface for encircling the mandrel; an outer surface; a first end surface for engaging an end of the sealing assembly and wherein the first end surface extends from the inner surface to the outer surface; and a second end surface opposing the first end surface and extending from the inner surface to the outer surface. Additionally, a first groove extends around the first end surface and a second groove extends around the second end surface. The first and second grooves are spaced from said outer surface. When in place about the mandrel and when the sealing assembly is in the unset position the retaining assembly further has a first band positioned in the first groove and a second band positioned in the second groove. The first band and second band are suitable for holding the plurality of segments in place about the mandrel while the sealing assembly is in the unset position. 
    
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
         FIG. 1  is a cross-sectional side view of a downhole apparatus having retaining assemblies embodying the present invention. 
         FIG. 2A  is a cross-sectional side view of a sealing assembly and retaining assemblies of the embodiment of  FIG. 1 . of the present invention. 
         FIG. 2B  is a cross-sectional side view of a sealing assembly and retaining assemblies of another embodiment of the present invention. 
         FIG. 3  is a cross-sectional side view of the downhole apparatus of the embodiment of  FIG. 1  in a set position. 
         FIG. 4  is a front view of a retaining assembly of the present invention. 
         FIG. 5  is a perspective view of a single retaining assembly segment. 
         FIG. 6  is a perspective view of the retaining assembly of the present invention. 
         FIG. 7  is a perspective view of the retaining assembly of the present invention as viewed from the opposite side as the view of  FIG. 6 . 
         FIG. 8  is a cross-sectional side view of a prior art packer element and retaining assembly, 
     
    
    
     DETAILED DESCRIPTION 
     Referring now to  FIGS. 1 ,  2  and  3 , downhole tool, or downhole apparatus  10  is shown in an unset position  11  ( FIGS. 1 and 2 ) or a set position  13  ( FIG. 3 ) in a well  15  having a wellbore  20 . The wellbore  20  can be either a cased completion with a casing  22  cemented therein as shown in  FIG. 1  or an openhole completion. Generally, as used here in the term “wellbore” will refer to either a cased completion or an openhole completion. Downhole apparatus  10  is shown in set position  13  in  FIG. 3 . Casing  22  has an inner surface  24 . An annulus  26  is defined by casing  22  and downhole tool  10 . Downhole tool  10  has a mandrel  28 , and may be referred to as a bridge plug due to the downhole tool  10  having a plug  30  being pinned within mandrel  28  by radially oriented pins  32 . Plug  30  has a seal means  34  located between plug  30  and the internal diameter of mandrel  28  to prevent fluid flow therebetween. The overall downhole tool  10  structure, however, is adaptable to tools referred to as packers, and frac plugs which typically have at least one means for allowing fluid communication through the tool. Packers may therefore allow for the controlling of fluid passage through the tool by way of one or more valve mechanisms which may be integral to the packer body or which may be externally attached to the packer body. Frac plugs control fluid passage through the use of a frac ball. Such valve mechanisms are not shown in the drawings of the present document. Packer tools may be deployed in wellbores having casings or other such annular structure or geometry in which the tool may be set. 
     Mandrel  28  has an outer surface  36 , an inner surface  38 , and a longitudinal central axis, or longitudinal axial centerline  40 . Also, as referred to herein the term “radially” will refer to a radial direction perpendicular to the longitudinal axial centerline. An inner tube  42  is disposed in, and is pinned to, mandrel  28  to help support plug  30 . 
     Downhole tool  10 , which as illustrated is a packer apparatus, includes the usage of a spacer ring  44  which is preferably secured to mandrel  28  by pins  46 . Spacer ring  44  provides an abutment, which serves to axially retain slip segments  48  which are positioned circumferentially about mandrel  28 . Slip retaining bands  50  serve to radially retain slip segments  48  in an initial circumferential position about mandrel  28  as well as slip wedge  52 . Bands  50  are made of a steel wire, a plastic material, or a composite material having the requisite characteristics of having sufficient strength to hold the slip segments  48  in place prior to actually setting the downhole tool  10  and to be easily drillable when the downhole tool  10  is to be removed from the wellbore  20 . Preferably, bands  50  are inexpensive and easily installed about slip segments  48 . Slip wedge  52  is initially positioned in a slidable relationship to, and partially underneath, slip segments  48  as shown in  FIG. 1 . Slip wedge  52  is shown pinned into place by pins  54 . Designs of slip segments  48  and co-acting slip wedges  52  are described in U.S. Pat. No. 5,540,279, which is incorporated herein by reference. 
     Located below slip wedge  52  is a sealing assembly  56 , which includes at least one sealing element, and as shown in  FIG. 1  includes three expandable sealing elements  58  positioned about mandrel  28 . In packer type tools such sealing elements are often referred to as packer elements. Sealing assembly  56  has upper end  60  and lower end  62 . Sealing assembly  56  has unset and set positions  57  ( FIG. 1) and 59  ( FIG. 3 ) corresponding to the unset and set positions  11  and  13 , respectively, of downhole tool  10 . The sealing assembly  56  is radially expandable from the unset position  57  to a set position  59  in response to the application of axial force on the sealing assembly  56 . In the set position  59 , the sealing assembly  56  engages the casing  22  to create a seal to prevent flow through annulus  26 . 
     The present invention has retaining assemblies  66  disposed at the upper and lower ends  60  and  62  of sealing assembly  56  to axially retain the sealing assembly  56 . Retaining assemblies  66  (also referred to as retaining shoes or extrusion limiters) may be referred to as an upper retaining assembly  68  and a lower retaining assembly  70 . A slip wedge  72  is disposed on mandrel  28  below lower retaining assembly  70  and is pinned with a pin  74 . Located below slip wedge  72  are slip segments  76 . Slip wedge  72  and slip segments  76  are like slip wedge  52  and slip segments  48 . At the lowermost portion of downhole tool  10  is an angled portion, referred to as mule shoe  78 , secured to mandrel  28  by pin  79 . The lowermost portion of downhole tool  10  need not be mule shoe  78  but can be any type of section which will serve to terminate the structure of the downhole tool  10  or serve to connect the downhole tool  10  with other tools, a valve or tubing, etc. It will be appreciated by those in the art that pins  32 ,  46 ,  54 ,  74 , and  79 , if used at all, are preselected to have shear strengths that allow for the downhole tool  10  to be set and deployed and to withstand the forces expected to be encountered in the wellbore  20  during the operation of the downhole tool  10 . 
       FIG. 8  shows a prior art arrangement of a retaining assemblies  150 , which may referred to as retaining shoes or extrusion limiters. Upper and lower retaining assembly  152  and  154  are essentially identical. Therefore, the same designating numerals will be used to further identify features on each of retaining shoes  152  and  154 , which are referred to collectively herein as retaining assemblies  150 . Retaining assemblies  150  comprise an inner shoe, or inner retainer  156  and an outer shoe, or outer retainer  158  Inner and outer shoes  156  and  158  are held in place by retaining bands  160 , which are received in a groove  162 . Retaining bands  160  are exposed so that they can undergo inadvertent contact with a wellbore, a casing within a wellbore, or other object. 
     Referring now to FIGS.  2 A and  4 - 7 , the retaining assemblies  66  (also called retaining shoes or extrusion limiters) of the present invention will be described. Upper and lower retaining assemblies  68  and  70  are essentially identical. Therefore, the same designating numerals will be used to further identify features on each of retaining assemblies  68  and  70 , which are referred to collectively herein as retaining assemblies  66 . Retaining assemblies  66  are preferably comprised of a plurality of retainer segments, or shoe segments,  80  to form retaining assemblies  66  that encircles mandrel  28 . Retainer segments  80  can be made form any suitable material that will withstand the downhole use and yet can be readily cut or ground up by drilling with a drill bit. Generally, non-metallic engineering grade plastics can be used for the retaining materials, such as composite materials or structural phenolic materials. A suitable phenolic materials are available from General Plastics &amp; Rubber Company, Inc., 5727 Ledbetter, Houston, Tex. 77087-4095. Alternatively, structural phenolics available from commercial suppliers may be used. A suitable composite materials are available from General Plastics &amp; Rubber Company, Inc., 5727 Ledbetter, Houston, Tex. 77087-4095. Particularly suitable materials for at least a portion retaining assemblies  66  includes direction specific composite material available from General Plastics &amp; Rubber Company, Inc. 
     Retaining assemblies  66  have an outer surface  82 . Retaining assemblies  66  also have an inner surface  84  composed of inner surface  86 , first end surface  88  and second end surface  90 . When the downhole tool is in the unset position  11 , retaining segments  80  define outer surface  82  and inner surface  84 . Generally outer surface  82  will be substantially cylindrical and face the wellbore  20 . In the set position  13 , the arc surfaces  83  of retaining segments  66  making up outer surface  82  engage the wellbore. Generally inner surface  86  will be a substantially cylindrical inner surface, which encircles the mandrel. Timer surface  86  is defined by arc surfaces  87  of retaining segments  66 . Arc surfaces  87  engage mandrel  28  in an initial or running position of the downhole tool  10 . First end surface  88  extends from the outer surface  82  to inner circle  86 . Additionally, first end surface  88  extends in a generally circumferential direction but is preferably not parallel to the radial direction. As can best be seen from  FIG. 6 , first end surface  88  can have an arcuate shaped cross-section or can be sloped. In the embodiment shown, first end surface  88  is shaped to accommodate the upper and lower ends  60  and  62  of the sealing assembly  56  and, thus, is preferably sloped as well as arcuate to provide a generally truncated conical surface which transitions from having a greater radius proximate outer surface  82  to a smaller radius proximate substantially cylindrical inner surface  86 . Second end surface  90  opposes first end surface  88  and, hence, extends from the outer surface  82  to inner circle  86 . Additionally, second surface  90  extends in a generally circumferential direction. Second end surface  90  may be generally parallel to the radial direction or may be at a slight angle, preferably less than 10° from parallel to the radial direction. However, it is within the scope of the invention for both end surfaces (first end surface  88  and second end surface  90 ) to have other shapes as long as they generally extend circumferentially and from outer surface  82  to inner surface  86 . 
     As shown in  FIG. 2 , upper and lower ends  60  and  62  of sealing assembly  56  reside directly against upper and lower retaining assemblies  68  and  70 . Retaining assemblies  66  are preferably comprised of a plurality of retainer segments  80  that encircles mandrel  28 . Each retainer segment  80  has ends  92  and  94 , which can be flat and convergent with respect to a center reference point, which, if the retainer segments  80  are installed about mandrel  28 , will correspond to the longitudinal central axis  40  of the mandrel  28  as depicted in  FIG. 1 . Ends  92  and  94  need not be flat and can be of other topology. In a preferred embodiment end  92  has a shelf  96  and end  94  has a tongue portion  98 , as can be seen in  FIGS. 5 and 6 . Tongue portion  98  is adapted to be received onto shelf  96  so that, in the unset position  11 , retainer segments overlap and form a substantially continuous ring. Further tongue portion  98  and shelf  96  are adapted so that, when retaining assemblies  66  are expanded in the set position  13 , the retaining segments still overlap and extrusion of the sealing elements  58  through the gaps  118  between retaining segments is blocked by the tongue and shelf arrangement. 
       FIG. 4-7  illustrate retaining assemblies  66  being made of a total of eight retainer segments  80  to provide a 360 degrees annulus encircling structure to provide a maximum amount of end support for sealing elements  58  to be retained in the axial direction. A lesser or greater amount of retainer segments  80  can be used depending on the nominal diameters of the mandrel  28 , the sealing elements  58 , and the wellbore  20  or casing  22  in which the downhole tool  10  is to be deployed. Inner diameter  122  generally approaches the inner diameter of the sealing assembly  56 . As is apparent from the drawings, outer surface  82  faces outwardly away from the downhole tool  10 . The slope of first end surface  88  is preferably approximately 45 degrees as shown in  FIG. 2 . However, the exact slope will be determined by the exterior configuration of the ends of the sealing elements  58  that are to be positioned and eventually placed in contact with retaining assemblies  66  and first end surface  88 . Inner surface  86  of retaining assembly  66  can be slightly sloped, approximately 5 degrees if desired, but it is best determined by the surface of the downhole tool  10  which it eventually abuts against when downhole apparatus  10  is centered in the wellbore  20 . 
     Each retainer segment  80  can have a lug (protruding member)  100  extending out from second end  90 . As can be seen from  FIGS. 1 and 2 , the lugs  100  of upper retaining assembly  68  contacts or abuts a slip wedge  52  such that an upper gap  110  is created when the downhole tool is in the unset position  11 . As can be seen in  FIG. 3 , when the downhole tool is moved to the set position, tipper retaining assembly  68  expands allowing slip wedge  52  to slide under the lugs  100  and fill gap  110  such that the end of the slip wedge that abutted the lugs is now between the lugs and the mandrel. Similarly, the lugs  100  of lower retaining assembly  70  contacts slip wedge  72  such that a lower gap  112  is created when the downhole tool is in the unset position. Also, when the downhole tool is moved to the set position, upper retaining assembly  70  expands allowing slip wedge  72  to slide under the lugs  100  and fill gap  112 . 
     An important aspect of the current invention is groove  114  and  116 . Groove  114  extends circumferentially around the first end surface  88 . Groove  116  extends circumferentially around the second end surface  90 . Retaining band  115  is positioned in groove  114  and retaining band  117  is positioned groove  116 . Retaining bands  115  and  116  are received in grooves  114  and  116  to initially hold the retainer segments  80  in place prior to setting the downhole tool  10  into the set position  13 . It is a preferred embodiment that the grooves  114  and  116  and retaining bands  115  and  117  be located on inner surface  84  instead of outer surface  82 . More preferably the grooves  114  and  116  and retaining bands  115  and  117  should be located on first end surface  88  and second end surface  90 . The grooves  114  and  116  should be spaced from outer surface  82 , i.e., not exposed to the wellbore  20  or not facing the wellbore  20 . Location of the bands and grooves in these positions prevent contacts that might fracture or release the bands and result in premature expansion of the retainer segments  80 . Retaining bands  115  and  117  may be made of a nonmetallic material, such as composite materials available from General Plastics &amp; Rubber Company, Inc., 5727 Ledbetter, Houston, Tex. 77087-4095. However, bands  114  and  116  may be alternatively made of a metallic material such as ANSI 1018 steel or any other material having sufficient strength to support and retain the retaining assembly  66  in position prior to actually setting the downhole tool  10 . Furthermore, retaining bands  115  and  117  may have either elastic or non-elastic qualities depending on how much radial, and to some extent axial, movement of the retainer segments  80  can be tolerated prior to enduring the deployment of the associated downhole tool  10  into the wellbore  20 . 
     In unset position  57 , retaining bands  115  and  117  serve to hold retainer segments  80  in place. Prior to the downhole tool  10  being set, retaining assemblies  66  engage mandrel  28  about the upper and lower ends  60  and  62  of the sealing assembly  56 . Lower retaining assembly  70  engages lower end  62  of sealing assembly  56  and upper retaining assembly  68  engages the upper end  60  of sealing assembly  56  in the unset positions  11  and  57  of downhole tool  10  and the sealing assembly  56 , respectively. When the downhole tool  10  has reached the desired location in the wellbore  20 , setting tools as commonly known in the art will move the downhole tool  10  and, thus, the sealing assembly  56 , to their set positions  13  and  59 , respectively, as shown in  FIG. 3 . 
     Gaps  118  have a width  120  that can be essentially zero when the retainer segments  80  are initially installed about mandrel  28 , and before the downhole tool  10  is moved from the unset position  11  to the set position  13 . However, a small gap, for example a gap of 0.06″ may be provided for on initial installation. The width  120  of gap  118  will increase from that which exists on initial installation, as the downhole tool  10  is set. 
     When the downhole tool  10  is moved to its set position  13 , retaining bands  115  and  117  will break and retaining assembly  66  will move radially outwardly so that arc surfaces  83  of each retainer segment  80  will engage inner surface  24  of casing  22 . The radial movement will cause width  120  of gaps  118  to increase. However, the tongue portion  98  and shelf  96  of retainer segments  80  will still overlap and, thus, extrusion of sealing elements  58  through gaps  118  and past retaining assembly  66  will be prevented. Additionally, the slip wedges  52  and  72  will move under lugs  100 , as described above. Accordingly, slip wedges  52  and  72  will prevent extrusion of sealing elements  58  between retaining assembly  66  and mandrel  28  as illustrated in  FIG. 3 . 
     As can be understood from the foregoing description, the extrusion of sealing elements  58  is essentially eliminated, since arc surface  83  engage the wellbore  20  and prevent extrusion on the wellbore side of the downhole tool. Additionally, any material extruded through gaps  118  will be blocked by the tongue and shelf arrangement of the retainer segments, extrusion between retainer segments  80  and mandrel  28  is blocked by the slip wedges  52  and  72 . Retaining assemblies  66  are thus expandable retaining shoes that will prevent or at least limit the extrusion of the sealing elements  58  and be less subject to premature expansion. Retaining assembly  66  may also be referred to as an expandable retainer. The arrangement is particularly useful in high pressure, high temperature wells, since there is no extrusion path available. It should be understood, however, that the disclosed retaining assembly  66  may be used in connection with packer-type tools of lesser or greater diameters, differential pressure ratings, and operating temperature ratings than those set forth herein. 
     Turning now to  FIG. 2B  an alternative embodiment of the invention is shown. In  FIG. 2B  similar parts to those in  FIG. 2A  have been given the same reference number. In the embodiment of  FIG. 2B  there is upper retaining assembly  132  and lower retaining assembly  134 . Upper and lower retaining assemblies  134  are essentially identical. Therefore the same designating numerals will be used to further identify features on each of retaining assemblies  132  and  134 , which are referred to collectively herein as retaining assemblies  130 . Retaining assemblies  130  comprising an inner ring  136  and an outer ring  142 . Inner ring  136  can have an arcuate or an angular cross section and mates with outer ring  142 , such that radial portion  138  is between outer ring  142  and either the upper or lower end of the sealing assembly  60  or  62  and such that the longitudinal or axial portion  140  of inner ring  136  is between mandrel  28  and outer ring  142 . Additionally, inner ring  136  can be comprised of a plurality of segments with each segment adjacent to at least one other segment. Outer ring  142  is essentially identical to retaining assemblies  66 , except that it has a larger inner diameter  122  to accommodate inner ring  136 . 
     Although the disclosed invention has been shown and described in detail with respect to a preferred embodiment, it will be understood by those skilled in the art that various changes in the form and detailed area may be made without departing from the spirit and scope of this invention as claimed. Thus, the present invention is well adapted to carry out the object and advantages mentioned as well as those which are inherent therein. While numerous changes may be made by those skilled in the art, such changes are encompassed within the spirit of this invention as defined by the appended claims.

Summary:
An improved downhole tool apparatus for limiting the extrusion of a sealing elements in downhole tools that use segmented retaining assemblies, retaining shoes or retaining limiters. The apparatus provides for locating the retaining bands for the retaining assemblies in a groove on the inner surface of the retaining assembly so that the bands are protected from breaking prematurely by inadvertently contacting the wellbore, casing within a wellbore, or other object.