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CROSS-REFERENCE TO RELATED APPLICATIONS 
     Not applicable 
     STATEMENT REGARDING FEDERALLY SPONSORED RESEARCH OR DEVELOPMENT 
     Not applicable 
     REFERENCE TO MICROFICHE APPENDIX 
     Not applicable 
     TECHNICAL FIELD 
     This invention relates to apparatus for completing and producing hydrocarbons from wells, and, in particular, to improved well tools that are supported in the wellbore at a subterranean location. The apparatus of the present invention are applicable to packers, plugs, liner hangers, and like tools of the type utilizing a gripping means to secure the tool in position in the wellbore. 
     BACKGROUND OF THE INVENTION 
     In the completion and the production of hydrocarbons from wells, it is frequently necessary to isolate a portion of the well using a well tool, such as a packer, plug, tubing hanger and the like, supported in the wellbore at a subterranean location. These tools are lowered into the well in a retracted state called the “run position” and in a process called “setting”, the gripping means and packing means are radially expanded to a “set position” wherein the slips means and packing means engage the wellbore. A variety of types of gripping means are well known in the art and, in the illustrated embodiment, a slip means with wedge-shaped slip elements is described. Typically, packing means have resilient annular members mounted on the tool to move axially to pack off or seal the annulus around the tool. In the disclosed embodiment, the packing means comprise one or more resilient annular packing elements which, depending on the use environment, may also comprise back up and/or anti-extrusion rings. When these packing elements are axially compressed, they expand radially from the mandrel into contact with the wellbore. To hold these tools in place in the wellbore against movement, slip means typically are mounted on the tool. These slip means, like the packing means, expand radially to grip the wellbore when forced to compress axially. 
     Axially directed forces are used to axially compress the packing elements and slip assemblies. Such forces are typically generated by moving the tubing string; initiating an explosive charge; or applying pressure to the tool. Examples of tools that are set by manipulating the tubing string include weight down and tension packers. A weight down packer is one in which force generated by the weight of the tubing string above the tool is used to set (expand) the packing and slip element and to hold the tool in set condition. In a tension packer, the tubing string is placed in tension and that tension force is used to set and hold the tool in the set condition. 
     Weight down and tension packers typically comprise a hollow tubular mandrel which is connected to the tubing string. Mounted on the mandrel are the axially compressible packing elements adjacent to the slip assembly. An annular tool element called a “drag block assembly” is located on the mandrel, adjacent the slip assembly on the opposite side from the packing elements. In weight down tools, the drag block is located below the slip means and, in the tension packer, the drag block is located above the slip mean. 
     Certain terminology may be used in the following description for convenience only and is not limiting. For instance, the words “inwardly” and “outwardly” are directions toward and away from, respectively, the geometric center of a referenced object. Note that as used herein, “below”, “down”, “downward”, or “downhole” refers to the direction in or along the wellbore away from the wellhead whether the wellbore&#39;s orientation is horizontal, toward the surface or away from the surface. The terms “above,” “up,” “upward” or “uphole” indicates the direction in and along the wellbore toward the wellhead, whether the wellbore&#39;s orientation is horizontal, toward the surface, or away from the surface. As used herein, the term “J-slot tool” refers to a tool having a sleeve receptacle with a fitted, male element that has pins that fit into J-shaped slots on the sleeve. The J-shaped slots have short and long sides or legs. The short sides of the j-slots provide a shoulder for limiting relative movement between the pin and the sleeve. When the male element is moved up or down, depending on the orientation of the slot, and turned relative to the sleeve, the pins slide in the slot towards the long side of the J, which is open ended or long. The pins are released to move the length of the long side, thus releasing the sleeve for movement. The releasing procedure is called “unjaying the tool.” In some embodiments, the location of the pin and slot is reversed with the pin located on the sleeve. As used herein, the term “synthetic material” refers to materials that are not of natural origin and that are prepared or made artificially, using synthesis by combining separate elements or by modifying elements. 
     Drag block assemblies typically frictionally engage the wellbore. Drag block assemblies are mounted to slide axially on the mandrel. Movement of drag block on the mandrel is commonly limited by a pin in a J-slot. By axially moving and rotating the tubing string counter clockwise, the pin can be moved from the short leg of the J-slot to the long leg where axially moving the tubing string causes the drag block assembly to set the slip assembly and packing elements. 
     Conventional prior art packers utilize complicated, expensive drag block assemblies made from heavy metallic with metallic springs that engage the wellbore. An example of a prior art weight down packer of this type is illustrated in U.S. Pat. No. 4,590,995, which is incorporated by reference herein for all purposes. Examples of commercial versions of these tools are marketed by Halliburton as Champ® V Packer and Pin Point Injection (PPI) Packer. A conventional tension packer is illustrated in U.S. Pat. No. 3,422,898, which is incorporated by reference herein for all purposes. 
     Thus, there are needs for improved methods and apparatus for setting well tools, including providing a simple, cost-effective, improved drag block assembly that can be used with packers and other well tools. 
     SUMMARY 
     The present invention provides improved methods and apparatus for setting tools in the wellbore at downhole locations, using drag blocks molded from synthetic elastomeric materials. These drag blocks of the present invention are simple and inexpensive to construct and relatively lightweight, thus reducing tubing string weight. 
     Other and further objects, features and advantages of the present invention will be readily apparent to those skilled in the art upon a reading of the description of preferred embodiments which follows when taken in conjunction with the accompanying drawings, in which: 
    
    
     
       DESCRIPTION OF THE DRAWINGS 
         FIG. 1  is an elevation view partially in section illustrating a weight down packer embodying principles of the present invention; 
         FIG. 2  is a perspective view of one embodiment of the drag block configuration of the present invention; 
         FIG. 3  is a side elevation view of the drag block configuration of  FIG. 2 ; 
         FIG. 4  is a cross-sectional view of the drag block configuration of  FIG. 3  taken at central ring  380  and indicating the positioning of side members  95 ; and 
         FIG. 5  is a cross-sectional view of the drag block configuration of  FIG. 3  taken at lower ring  390  and the positioning of side members  95 . 
     
    
    
     DETAILED DESCRIPTION OF THE INVENTION 
     The present invention provides improved methods and apparatus for setting packers and other well tools in wellbores at subterranean location. One embodiment of the invention will be described by reference to the drawings in which reference characters are used to indicate like or corresponding parts throughout the several figures. Referring now to the drawings and in particular to  FIG. 1 , there is illustrated partially in section one embodiment of a weight down packer apparatus  10  configured for use as a straddle packer or pinpoint injection packer.  FIG. 1  illustrates packer apparatus  10  in a first or run-in position prior to it being set in the wellbore. Packer apparatus  10  is adapted to be connected in a tubing string in a cased wellbore (not shown). As will be described, the packer has two sets of spaced packing means that, when set, isolate a length of the wellbore for treatment. It should be understood that the packer apparatus could be configured with one set of packing means and used as a conventional packer. 
     Packer apparatus  10  may have an upper end  15  which has internal threads thereon adapted to be suspended from a tubing string (not shown) which extends to the well head. Packer apparatus  10  further includes a lower end  20  having threads thereon for connecting with tubing string (not shown) or other apparatus located below packer apparatus  10 . Thus, packer apparatus  10  is adapted to be connected to and made up as part of a tubing string  11 . The tubing strings above and below packer apparatus  10  may be production tubing or any other known work or pipe string and may include any kind of equipment and/or tool utilized in the course of treating and preparing wells for production. Packer apparatus  10  defines a central flow passage  32  for the communication of fluids through packer apparatus  10  and tubing strings above and below the packer. 
     Packer apparatus  10  includes a packer mandrel  35  with an upper end  40  and a lower end  45 . In this embodiment, the packer mandrel  35  is a multi-part mandrel; however, a single piece mandrel could be used. Lower end  45  comprises the lower end of the packer apparatus and includes the lower threads. Upper end  40  may be threaded to a hydraulic hold-down assembly  50  which has threads therein adapted to be connected to the tubing string, thereby adapting packer mandrel  35  to be connected in tubing string. The operation and construction of the hydraulic hold-down assembly is well known in the industry. 
     Packer apparatus  10  further includes an upper radially expandable seal assembly  90  disposed about packer mandrel  35 . A lower radially expandable seal assembly  92  is disposed about the packer mandrel  35  at a position axially below upper seal assembly  90 . As shown in  FIG. 1 , axially spaced seal assemblies  90  and  92  are closely received about outer packer surface. Seal assemblies  90  and  92  are spaced of isolate a portion of the wellbore for treatment. Although not shown or described, a valve or injection port may be located between the seal assemblies  90  and  92  for flowing fluids between the isolated wellbore portion and mandrel interior. Seal assemblies  90  and  92  may comprise one or more annular sealing elements  104 . Sealing elements  104  are preferably formed from an elastomeric material, such as, but not limited to, NBR, FKM, VITON®, or the like. However, one skilled in the art will recognize that, depending on the temperatures and pressures to be experienced, other materials may be used without departing from the scope and spirit of the present invention. 
     Seal assemblies  90  and  92  may further include anti-extrusion rings (not shown). Packer apparatus  10  further includes first, or upper and second, or lower annular shaped pusher shoes  196  and  198 , respectively, disposed on the mandrel, abutting the outer most sealing elements of the seal assemblies  90  and  92 . 
     Lower pusher shoe  198  on seal assembly  92  is threaded at its lower end to slip means in the form of a slip assembly  354 . Slip assembly  354  is, in turn, connected at its lower end to a drag block assembly  356 . Slip assembly  354  is of a type known in the art. Thus, slip assembly  354  may include a slip wedge  358  disposed about packer mandrel  35  and a plurality of slips  360  disposed on the mandrel adjacent slip wedge  358 . 
     A lower end  362  of slip wedge  358  engages a generally upwardly facing shoulder  364  on mandrel  35 . Shoulder  364  limits downward movement of the wedge on the mandrel when packer apparatus  10  is in the run in position. Shoulder  364  preferably extends around the entire circumference of packer mandrel  35 . Slip wedge  358 , which is slidable relative to mandrel  35  may have slots therein to allow wedge  358  to slide relative to the packer mandrel. Such a configuration and the operation thereof are well known in the art. 
     A split ring collar  363  connects drag block assembly  356  to the lower end of the slip assembly  354 . The details of the drag block assembly  356  are illustrated in  FIGS. 2-5 . In the preferred embodiment, drag block assembly  356  includes three axially spaced annular rings, i.e., upper ring  370 , center ring  380  and lower ring  390 . Three rings were selected for this embodiment; however, it is envisioned that more or less rings could be included. A pair of longitudinally extending, side members  395  connect the rings together in a parallel spaced relationship. Again, more or less side members could be included, as desired. The side members could be formed as a continuous or slotted cylinder, extending between two or more of the rings. 
     Drag block assembly  356  is substantially formed from a synthetic material. In the preferred form drag block assembly  356  is integrally formed by molding from an elastomeric materials, such as, Nitrile Butadiene Rubber (NBR), Hydrogenated Acrylonitrile-butadiene Rubber (HNBR), Florocarbon Rubber (FKM), Tetrafluroethylene-Propylene (AFLAS) and any elastomeric materials that could withstand a well environment. The term “elastomeric material” is used herein, to refer to material that has a substantial resilient property. The term “substantially non metallic material” is used to describe a drag block which may comprise metallic wear or structural members but is not primarily formed of metallic material. 
     J-slots  400  with short leg  420  and long leg  430  are preferably formed in the inside surface of side members  395 . A pair of radially outwardly extending lugs  376  is defined on the packer mandrel  35 . As is known in the art, lugs  376  are preferably disposed 180 degrees apart and rest in short legs  420  of J-slots  400  when packer apparatus  10  is in the run position. The legs of the J-slot  400  need not extend through the side members  395 , but need only be deep enough to allow the lugs  376  formed on the mandrel  35  to travel up and down therein. As shown, portions or all of the slots  400  can extend completely through the side members  395 . 
     Rings  380  and  390  are sized to fit around and slide axially on the exterior of mandrel  35 . As illustrated in  FIG. 3 , rings  380  and  390  have downward facing tapered profiles  397 . The taper is in the form of frusto conical surfaces at the downward facing edge. Flow passages  392  are formed in rings  380  and  390  to permit fluids in the well to bypass the rings. Flow passages  392  extend axially through the rings. The maximum diameter of the outer surface of the rings  380  and  390  is selected to form an interference fit to frictionally engage or drag along the inner diameter of the wellbore. The diameter of the rings  380  and  390  is selected so that a drag force is created sufficient to axially move the drag block assembly when the lugs  376  are located in the long leg  430  of the J-slot  400 . Preferably, the interference fit is small enough as to minimize wear on the rings from contact with the wellbore. To provide additional drag force and to limit damage to rings  380  and  390 , wear members  440  in the form of buttons or inserts are mounted on or in the exterior surface of rings  380  and  390 . The wear members can be formed from tough wear resistant materials, such as composite materials (hard rubber, resins and the like), metallic materials (steel, carbide and the like), and ceramic materials. Upper ring  370 , like rings  380  and  390 , has an interior that is sized to fit around and slide axially on the exterior of mandrel  35 . In this embodiment, the exterior surface of upper ring  370  is cylindrical and has a smaller maximum outer diameter than the other rings. Ring  370  has an annular groove  372  for use in coupling the drag block assembly to the slips via split collar  363 . 
     The operation of the illustrated pin point injection packer apparatus  10  is as follows. Packer apparatus  10  is assembled and lowered on a tubing string into a cased wellbore in the run position illustrated in  FIG. 1 . The drag block rings  380  and  390  engage the inner surface of casing as packer apparatus  10  is lowered into the wellbore. Once packer apparatus  10  has reached the desired location in wellbore, it is necessary to move packer apparatus  10  to a set position. The tubing string is raised upwardly, which causes the hydraulic hold-down assembly  50  and packer mandrel  35  to be pulled upward. 
     Friction forces generated by contact between drag block rings  380  and  390  and the well casing will hold drag block assembly  354  in place while packer mandrel  35  is moved upward. Packer mandrel  35 , initially positioned in shower legs  420 , is moved upward and rotated counter clockwise so that lugs  376  on mandrel  35  are positioned above long legs  430  of J-slots  400 . The upward pull on the tubing string is then released and packer mandrel  35  is allowed to move downward. 
     As packer mandrel  35  moves downward, drag block assembly  356  moves slips  360  upward onto the wedge  358  to expand the slips radially outwardly. The slips will move radially outward into contact with the casing. The slips will move into the set position with the slips engaging and grab the casing. In this set position, the slips will limit or restrict movement of the tool. 
     With the slips engaged with the casing, further downward movement of the packer mandrel  35  will cause lower pusher shoe  198  to engage and axially compress seal assemblies  90  and  92 , thus expanding seal assembly  92  radially outward into the set position. In the set position the seal assemblies  90  and  92  seals or restricts flow through the annulus formed between the packer and the wellbore casing. Ideally, in this embodiment, when the packer apparatus  10  is in the set position, seal assemblies  90  and  92  sealingly engages casing and operate to maintain a seal at wellbore temperatures and pressures. To engage the hydraulic hold down assembly, a positive pressure differential is applied between the interior of the tubing string and the annulus around the tubing. To perform a pin point injection of well treating fluids into the isolated portion of the wellbore, fluids are pumped down the tubing string and exit the mandrel through a port, nozzle, valve or the like located in the mandrel between the seal assemblies  90  and  92 . 
     If it is desired to remove the packer apparatus from the wellbore or to set the packer apparatus at a different location, an upward pull is applied so that packer mandrel  35  will begin to move upwardly. Shoulder  364  on mandrel  35  will engage the lower end  362  of slip wedge  358  and will pull wedge  358  up to allow slips  360  to retract radially inwardly and release the grab on the casing. Likewise, an upward pull on the packer mandrel  35  will allow the seal assembly  92  to retract radially from the casing wall. When lugs  376  reach the top of J-slots  400 , clockwise rotation will move the lugs  376  to a position above short legs  420  of J-slots  400 . Packer mandrel  35  can be set back down and lugs  376  will rest in short legs  420  of J-slots  400 . Packer apparatus  10  will be once again in the run position as shown in  FIG. 1 . 
     Packer apparatus  10  of the present invention can be set numerous times in a wellbore and will successfully maintain sealing engagement with the casing each time it is set in a wellbore at the extreme temperatures and pressures contemplated. 
     In the tension packer embodiment (not illustrated), the orientation of the slips, packing and drag block assembly is reversed. In the tension packer embodiment, the drag block is above the slips and the seal assembly is position below the slip wedge. To install the tension packer embodiment, the packer is positioned in the wellbore. Next, the tubing string is lifted and rotated counter clockwise to move the lugs into the long legs of the J-Slots on the drag block assembly. The tubing sting and mandrel are then lifted and placed in tension, to lift the slips against the slip wedge and compress the packing assembly. To remove the tension packer, the process is reversed.

Summary:
Disclosed is a drag block assembly for use on a downhole tool for location in a cased wellbore. The tool has a hollow mandrel for suspension from a tubing string. The drag block, slips and packing elements mounted on the mandrel are moveable between the run and set positions by movement of the drag block, while engaging a lug on the mandrel. The drag block assembly comprises longitudinally spaced rings comprising resilient material connected together by longitudinally extending members.