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CROSS-REFERENCE TO RELATED APPLICATIONS 
   This application is a continuation-in-part of U.S. patent application Ser. No. 10/073,685, filed Feb. 11, 2002, now U.S. Pat. No. 6,695,057 which is a continuation-in-part of U.S. patent application Ser. No. 09/858,153, filed May 15, 2001, now abandoned, which is a divisional of U.S. patent application Ser. No. 09/435,388, filed Nov. 6, 1999, which is now U.S. Pat. No. 6,253,856, issued Jul. 3, 2001. All of which are herein incorporated by reference in their entireties. 

   BACKGROUND OF THE INVENTION 
   1. Field of the Invention 
   This invention is related to downhole tools for a hydrocarbon wellbore. More particularly, the invention relates to an apparatus useful in conducting a fracturing or other wellbore treating operation. More particularly still, this invention relates to a filtered inlet port through which a wellbore treating fluid such as a “frac” fluid may be pumped without obstructing the workings of a hydraulic tool. 
   2. Description of the Related Art 
   In the drilling of oil and gas wells, a wellbore is formed using a drill bit that is urged downwardly at a lower end of a drill string. When the well is drilled to a first designated depth, a first string of casing is run into the wellbore. The first string of casing is hung from the surface, and then cement is circulated into the annulus behind the casing. Typically, the well is drilled to a second designated depth after the first string of casing is set in the wellbore. A second string of casing, or liner, is run into the wellbore to the second designated depth. This process may be repeated with additional liner strings until the well has been drilled to total depth. In this manner, wells are typically formed with two or more strings of casing having an ever-decreasing diameter. 
   After a well has been drilled, it is desirable to provide a flow path for hydrocarbons from the surrounding formation into the newly formed wellbore. Therefore, after all casing has been set, perforations are shot through the liner string at a depth which equates to the anticipated depth of hydrocarbons. Alternatively, a liner having pre-formed slots may be run into the hole as casing. Alternatively still, a lower portion of the wellbore may remain uncased so that the formation and fluids residing therein remain exposed to the wellbore. 
   In many instances, either before or after production has begun, it is desirable to inject a treating fluid into the surrounding formation at particular depths. Such a depth is sometimes referred to as “an area of interest” in a formation. Various treating fluids are known, such as acids, polymers, and fracturing fluids. 
   In order to treat an area of interest, it is desirable to “straddle” the area of interest within the wellbore. This is typically done by “packing off” the wellbore above and below the area of interest. To accomplish this, a first packer having a packing element is set above the area of interest, and a second packer also having a packing element is set below the area of interest. Treating fluids can then be injected under pressure into the formation between the two set packers. 
   A variety of pack-off tools are available which include two selectively-settable and spaced-apart packing elements. Several such prior art tools use a piston or pistons movable in response to hydraulic pressure in order to actuate the setting apparatus for the packing elements. However, debris or other material can block or clog the piston apparatus, inhibiting or preventing setting of the packing elements. Such debris can also prevent the un-setting or release of the packing elements. This is particularly true during fracturing operations, or “frac jobs,” which utilize sand or granular aggregate as part of the formation treatment fluid. 
   Prior solutions to the debris problem have included running in a filter or screen above the down-hole tool. This has several disadvantages. First, once the screen is run above the down-hole tool, full pressure can no longer be transmitted to the piston. Second, emergency release mechanisms and other devices actuated by a ball cannot be used. 
   There is, therefore, a need for a hydraulic down-hole tool which does not require a piston susceptible to becoming clogged by sand or other debris. 
   SUMMARY OF THE INVENTION 
   The present invention generally discloses a novel actuator port for use in a hydraulic wellbore tool, a method of making the actuator port, and methods of using the actuator port. The actuator port filters out particulates so they do not obstruct the workings of the actuator. The filtered port may comprise fine slots disposed through a wall of a mandrel spaced around the circumference of the mandrel. 
   The present invention introduces a hydraulic tool for use in a wellbore, comprising: a tubular wall for separating a first fluid containing region from a second fluid containing region, the tubular wall including a filter portion; and an actuating member disposed within the second fluid containing region, the actuating member operable upon contact with a fluid flowing from the first fluid containing region and through the filter portion. 
   The present invention discloses forming at least one filter slot in the tubular wall utilizing manufacturing methods including but not limited to electrical discharge machining and laser cutting. 
   The present invention may be incorporated into any kind of hydraulic tool, including but not limited to a packer comprising a packing element and a fracture valve comprising a fracture port. These may be provided into a pack-off system comprising an upper packer, a fracture valve, and a lower packer all utilizing the present invention. The pack-off system may include other components as well. 
   The pack-off system utilizing the present invention may be run into a wellbore where the packing elements are set and the fracture port is opened by injecting fluid into the packer system under various flow rates resulting in various pressures. Further, an actuating fluid may be used to set the packers and open the fracture valve, and then treatment fluid may be injected through a fracture port into the wellbore. 

   
     BRIEF DESCRIPTION OF THE DRAWINGS 
     So that the manner in which the above recited features of the present invention can be understood in detail, a more particular description of the invention, briefly summarized above, may be had by reference to embodiments, some of which are illustrated in the appended drawings. It is to be noted, however, that the appended drawings illustrate only typical embodiments of this invention and are therefore not to be considered limiting of its scope, for the invention may admit to other equally effective embodiments. 
       FIG. 1  is a view of one cross-section of a hydraulic packer utilizing a filtered actuator according to one embodiment of the present invention.  FIG. 1A  is a section of  FIG. 1  detailing a filtered inlet port.  FIG. 1B  is a cross-sectional view of a nozzle valve. 
       FIG. 2  is a cross-sectional view of a fracture valve utilizing a filtered actuator according to one embodiment of the present invention.  FIG. 2A  is an enlargement of a piston/mandrel interface of  FIG. 2 . 
       FIGS. 3A–3D  are section views of a completed pack-off system.  FIG. 3A  is the system in the run in position.  FIG. 3B  is the system after the nozzle valve has been closed.  FIG. 3C  is the system after the packers have been set.  FIG. 3D  is the system after opening of the fracture valve. 
   

   DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENT 
     FIG. 1  presents a sectional view of a hydraulic packer  1  as might be used with a filtered port of the present invention. The packer is seen in a run in configuration. The packer  1  first comprises a packing element  40 . The packing element  40  may be made of any suitable resilient material, including but not limited to any suitable elastomeric or polymeric material. Actuation of the packing element below a workstring (not shown) is accomplished, in one aspect, through the application of hydraulic pressure. 
   Visible at the top of the packer  1  in  FIG. 1  is a top sub  10 . The top sub  10  is a generally cylindrical body having a flow bore therethrough. The top sub  10  is threadedly connected at a top end to the workstring (not shown) or a fracture valve (as shown in  FIG. 2 ). At a lower end, the top sub  10  is threadedly connected to an element adapter  20 . The element adapter  20  defines a tubular body surrounding a lower portion of the top sub  10 . An o-ring  13  seals a top sub  10 /element adapter  20  interface. At a lower end, the element adapter  20  is threadedly connected to a center mandrel  15 . The center mandrel  15  defines a tubular body having a flow bore therethrough. The lower end of the element adapter  20  surrounds an upper end of the center mandrel  15 . One or more o-rings may be used to seal the various interfaces of the packer  1 . In one embodiment, an o-ring  12  seals an element adapter  20 /center mandrel  15  interface. 
   The packer  1  shown in  FIG. 1  also includes a packing element compressor  30  and a piston  45 . The packing element compressor  30  and the piston  45  each generally define a cylindrical body and each surround a portion of the center mandrel  15 . An o-ring  14  seals a packing element compressor  30 /center mandrel  15  interface. An upper end of the piston  45  is disposed within and threadedly connected to the packing element compressor  20 . An o-ring  16  seals a packing element compressor  30 /piston  45  interface. Surrounding a lower end of the packing element compressor  30  and threadedly connected thereto is an upper gage ring  5 . The upper gage ring  5  defines a tubular body and also surrounds a portion of the piston  45 . At a lower end, the upper gage ring  5  comprises a retaining lip that mates with a corresponding retaining lip at an upper end of the packing element  40 . The lip of the upper gage ring  5  aids in forcing the extrusion of the packing element  40  outwardly into contact with the surrounding casing (not shown) when the packing element  40  is set. 
   At a lower end, the packing element  40  comprises another retaining lip which corresponds with a retaining lip comprised on an upper end of a lower gage ring  50 . The lower gage ring  50  defines a tubular body and surrounds a portion of the piston  45 . At a lower end, the lower gage ring  50  surrounds and is threadedly connected to an upper end of a center case  55 . The center case  55  defines a tubular body which surrounds a portion of the piston  45 . Within the center case  55 , the piston  45  defines a chamber  60 . Corresponding to the chamber  60  is a filtered inlet port  65  disposed through a wall of the center mandrel  15 . Preferably, the filtered inlet port  65  comprises two sets of filter slots. 
   Each filter slot  65  is configured to allow fluid to flow through but to prevent the passage of particulates. Preferably, the filter slots are substantially rectangular in shape. In one embodiment shown in  FIG. 1A , ten filter slots  65  are equally spaced around the entire circumference of the center mandrel for each set of inlet slots. The filter slots  65  can be cut into the center mandrel  15  using a laser or electrical discharge machining (EDM). The dimensions and number of slots may vary depending on the size of the particulates expected in the fracture fluid. As an example, for a fracture fluid with a minimum particulate size of 0.016 inch in diameter, each filter slot  65  would preferably be 0.9 inch long and between 0.006–0.012 inch wide. Optionally, the width of the slot  65  may be reduced down to 0.003 inch or as far as current manufacturing technology will allow. Typically, a maximum slot width of 0.02–0.03 inch would be expected, however, a width of 0.2 inch would also fall within the scope of the present invention. Use of the term “width” does not mean that the slot  65  must be rectangular. Other shapes can be used for the filter slots  65 , such as triangles, ellipses, squares, and circles. In those cases the “width” would be the smallest dimension across the slot  65  (not including the thickness of the slot through the mandrel  15 ). Other manufacturing techniques may be used to form the filtered inlet port  65 , such as the formation of a powdered metal screen or the manufacture of a sintered powdered metal sleeve with the non-flow areas of the sintered sleeve being made impervious to flow. 
   Disposed within the inlet slot  60  are blocks  62 . Preferably, the blocks  62  are annular plates which are threaded on both sides. The outer threads of the blocks  62  mate with threads disposed on an inner side of the center case  55 . The inner threads of the blocks  62  mate with threads disposed on an outer side of the center mandrel  15 . The blocks are disposed on the center mandrel  15  just below a lower set of filtered inlet slots  65 . Preferably, the blocks  62  further comprise a tongue disposed on an upper end for mating with a groove disposed on the outside of the central mandrel  15 . Preferably, the blocks  62  do not completely fill the inlet slot  60 , thereby leaving a gap allowing fluid to flow around the blocks within the inlet slot. 
   An o-ring  17  seals an upper piston  45 /center case  55  interface. An o-ring  18  seals a lower piston  45 /center case  55  interface. An o-ring  19  seals a piston  45 /center mandrel  15  interface. Abutting a lower end of the piston  45  is an upper end of a biasing member  70 . Preferably, the biasing member  70  comprises a spring. The spring  70  is disposed on the outside of the center mandrel  15 . The lower end of the spring  70  abuts an upper end of a spring adapter  75 . The spring adapter  75  defines a tubular body. At an upper end, the spring adapter  75  surrounds and is threadedly connected to a lower end of the central mandrel  15 . At a lower end, the spring adapter  75  surrounds and is threadedly connected to a bottom sub  80 . The bottom sub  80  defines a tubular body having a flow bore therethrough. An o-ring  21  seals a spring adapter  75 /center mandrel  15  interface. A lower end of the bottom sub  80  is threaded so that it may be connected to other members of the workstring such as a nozzle valve  85  (as illustrated in  FIG. 1B ), or a fracture valve (as displayed in  FIG. 2 ). An o-ring  22  seals a spring adapter  75 /bottom sub  80  interface.  FIG. 1B  contains a cross sectional view of the nozzle valve  85 . The nozzle valve  85  comprises a flow bore therethrough with a tapered seat for a ball that may be dropped through the workstring. 
     FIG. 2  presents a sectional view of a fracture valve  100  as might be used with a filtered port of the present invention. The fracture valve  100  is seen in a run in configuration. Visible at the top of the fracture valve  100  in  FIG. 1  is a top sub  110 . The top sub  110  is a generally cylindrical body having a flow bore therethrough. The top sub  110  is threadedly connected at a top end to the workstring (not shown) or a packer (as shown in  FIG. 1 ). 
   At a lower end, the top sub  110  surrounds and is threadedly connected to an upper end of a mandrel  115 . The mandrel  115  defines a tubular body having a flow bore therethrough. Set screws  105  optionally prevent unthreading of the top sub  110  from the mandrel  115 . An o-ring  113  seals a top sub  110 /mandrel  115  interface. Also at the lower end, the top sub  110  is surrounded by and threadedly connected to an upper end of a sleeve  120 . The sleeve  120  defines a tubular body with a bore therethrough. Disposed between the mandrel  115  and the sleeve  120  below the top sub is an adjusting nut  122 . The adjusting nut  122  is threadedly connected to the mandrel  115 . Abutting a lower end of the adjusting nut  122  is an upper end of a biasing member  125 . Preferably, the biasing member  125  comprises a spring. Abutting a lower end of the spring  125  is a piston  130 .  FIG. 2A  is an enlarged partial view of a piston  130 /mandrel  115  interface. The piston  130  and the mandrel  115  define a chamber  135 . Corresponding to the chamber  135  is a filtered inlet port  140  disposed through a wall of the mandrel  115 . Preferably, the filtered inlet port  140  comprises one set of filter slots. Each filter slot  140  is similar to the filter slot  65  discussed above with reference to the packer  1 . Disposed in the wall of the mandrel  115  below the filter slots  140  is a fracture port  145 . An upper o-ring  114  and a middle o-ring  116  cooperate to seal a piston  130 /mandrel  115  interface above the fracture port  145 . The middle o-ring  116  and a lower o-ring  117  cooperate to seal the piston  130 /mandrel  115  interface proximate the fracture port  145 . Abutting a lower end of the piston  130  is a bottom sub  150 . The bottom sub  150  is a generally cylindrical body having a flow bore therethrough. At an upper end, the bottom sub  150  surrounds and is threadedly connected to a lower end of the mandrel  115 . Set screws  155  optionally prevent unthreading of the bottom sub  150  from the mandrel  115 . An o-ring  118  seals a bottom sub  150 /mandrel  115  interface. Disposed below the bottom sub  150 /mandrel  115  interface in a wall of the bottom sub  150  are jet nozzles  160 . At a lower end, the bottom sub  150  is threaded so that it may be connected to the workstring or other members thereof, such as a packer (as displayed in  FIG. 1 ). 
   Referring to  FIGS. 3A–3D , in operation, the packer  1  and the fracture valve  100  are run into the wellbore on the workstring, such as a string of coiled tubing, as part of a pack-off system  200 . The workstring is any suitable tubular useful for running tools into a wellbore, including but not limited to jointed tubing, coiled tubing, and drill pipe. The pack-off system  200  comprises a top packer  205 , the fracture valve  100 , the bottom packer  1 , and the nozzle valve  85  or a solid nose portion (not shown). It is understood that additional tools, such as an unloader (not shown) may be used with the pack-off system  200  on the workstring. Preferably, the top packer  205  is a slightly modified version of the bottom packer  1 . The top sub and the bottom sub are exchanged enabling the top packer to be mounted upside down in the workstring. The pack-off system may also comprise a spacer pipe (not shown) between the two packers. 
   In  FIG. 3A , the pack-off system  200  is positioned adjacent an area of interest, such as perforations  242  within a casing string  240 . Once the pack-off system  200  has been located at the desired depth in the wellbore, a ball is dropped from the surface into the pack-off system  200  to seal the nozzle valve as shown in  FIG. 3B . Fluid is injected into the system at a first flow rate sufficient to set the packers  1  and  205 . Because the flow of fluid out of the bottom of the pack-off system  200  is closed off, fluid is forced to exit the system  200  through the jet nozzles  160  of the fracture valve  100 . Flow through the jet nozzles  160  will generate a back pressure within the system. Fluid, under this back pressure, also enters the piston chambers  60  and  135  through the filter slots  65  and  140  of the packers  1  and  205  and fracture valve  100  respectively. The filter slots  65  and  140  prevent any debris in the fluid from entering the piston chambers  60  and  135 . The pistons  45  and  130  are configured such that one face of the pistons within the chambers  60  and  135  is larger than the other. This will create a net force, generated by the pressure, on the larger piston faces. This force will be opposed by the springs  70  and  125  and, in the packers  1  and  205 , the packing elements  40 . Once the pressure is sufficient to overcome the opposing forces (the spring force of the fracture valve  100  is greater than that of the packers  1  and  205 ), it will force the pistons  45  of the upper  205  and lower  1  packers downward (upward for the upper packer) since the system  200  and thus the center mandrels  15 , blocks  62 , center cases  55 , and lower gage rings  50  are held in place by the workstring. This forces the packing element compressors  30  and upper gage rings  5  to move downwardly (upwardly for the upper packer). The upper gage rings  5  push down (up for the upper packer) to set the packing elements  40  of the upper and lower packers  1  and  205 . The packing elements  40  are shown set within the casing  240  in  FIG. 3C . 
   After sufficient pressure has been applied to the pack-off system  200  through the bores of the center mandrels  15  to set the packing elements  40 , the fluid injection rate is increased into the system  200 . From there fluid enters the annular region between the pack-off system  200  and the surrounding casing  240 . The injected fluid is held in the annular region between the packing elements  40  of the upper  205  and lower packers  1 . Fluid continues to be injected, at this higher rate, into the system  200  and through the jet nozzles  160  until a greater second pressure level is reached. This second pressure causes the piston  130  of the fracture valve  100  to move upward along the mandrel  115 . This, in turn, exposes the fracture port  145  to the annular region between the pack-off system  200  and the surrounding casing  240  as shown in  FIG. 3D . A greater volume of fracturing fluid can then be injected into the wellbore so that formation fracturing operations can be further conducted. 
   If any debris should deposit on the filter slots, it may be purged when the system is reset by de-pressurization. This is due to the fact that as the pistons  45  and  130  are urged back to their run in positions, fluid will be forced from the chambers  60  and  135  of the packers  1  and  205  and fracture valve  100  back through the filtered slots  65  and  140  into the center mandrels  15  and mandrel  115  respectively. 
   The filtered inlet ports shown in  FIGS. 1–3  may be used with any hydraulically operated tool. While the foregoing is directed to embodiments of the present invention, other and further embodiments of the invention may be devised without departing from the basic scope thereof, and the scope thereof is determined by the claims that follow.

Summary:
Methods of using and making and apparatuses utilizing a filtered actuator port for hydraulically actuated down hole tools. The filtered port prevents sand or other debris from entering the actuator workings of a tool. In accordance with one aspect of the invention, hydraulic tools utilizing filtered actuator ports are disclosed. In a second aspect, the filtered port comprises fine slots disposed through a wall of a mandrel spaced around the circumference of the mandrel. In a third aspect, the inlet port is formed by laser cutting or electrical discharge machining. In a fourth aspect, the filtered port is disposed in various components of a fracture pack-off system. Methods of using the fracture pack-off system utilizing the filtered port are provided.