Patent Publication Number: US-10329889-B2

Title: Fracking tool further having a dump port for sand flushing, and method of fracking a formation using such tool

Description:
CROSS-REFERENCE 
     This application is a continuation-in-part of U.S. application Ser. No. 14/637,114 (US Pub. Nol. 2016/0258258) filed Mar. 3, 2015 entitled “Method and Tool for Perforating a Wellbore Casing in a Formation using a Sand Jet, and using such Tool to further Frac the Formation”. 
    
    
     FIELD OF THE INVENTION 
     The present invention relates to a downhole tool for fracking an underground hydrocarbon formation. More specifically, the present invention relates to a tool which has a dump port in place of a perforating jet which tool allows successive flushing of an annular region surrounding the tool after each successive fracing operation carried out by the tool, to thereby avoid sanding in of the tool within the wellbore after each fracking operation. A method of fracking employing such tool is further taught. 
     BACKGROUND OF THE INVENTION AND DESCRIPTION OF THE PRIOR ART 
     The below provided background information and description of prior publications is provided for the purpose of making known information believed by the applicant to be of possible relevance to the present invention. No admission is necessarily intended, nor should be construed, that any of the below publications and information provided constitutes prior art against the present invention. 
     In order to prepare a cased wellbore drilled in a hydrocarbon formation for production, such cased wellbore first needs to be perforated along portions of its length in order for hydrocarbons to flow into such wellbore for pumping to surface. 
     Prior art apparati and methods for creating perforations in the wellbore casing have typically comprised placing a string of explosive charges, namely shaped charges adapted to explode radially outwardly, within and along a length of the wellbore, and igniting such charges and thereafter withdrawing the perforating string from the wellbore. 
     Other methods and apparati for creating perforations along a wellbore have involved insertion of a tool having one or more nozzles, adapted to direct radially outwardly therefrom an abrasive fluid under high pressure. Such abrasive high pressure fluid impacts the wellbore casing and due to its abrasive nature, cuts a hole or holes in the wellbore casing. Such tool is moved along the wellbore casing to create additional perforations in such wellbore along a desired length thereof. 
     Typically, after a wellbore has been perforated, as a means to increase the rate and volume of production from the formation prior to commencing production therefrom a fracking fluid (typically containing proppants, acids, diluents, and/or other flow-stimulating additives) is injected under high pressure into the wellbore in a fracking operation. Typically only portions of a wellbore are “fracked” at a time, requiring a zone of a wellbore that is to be fracked to be isolated from other regions of the wellbore, typically by rubberized packer elements which are actuated by hydraulic pressure. 
     In such fracking operation, when a particular one or number of perforations along a wellbore are isolated by packers, a high pressure fluid is flowed into the wellbore and thus into the formation in the region of the perforation(s). Such high pressure fluid creates fissures within the formation. The created fissures (typically lines of fracture within the formation) generally emanate radially outwardly from the wellbore and thereby create flow channels in the formation which lead to the wellbore, thereby assisting hydrocarbons to subsequently flow into and be collected by the wellbore. 
     Unsatisfactorily however, no tool exists that is able to both perforate using abrasive jets, as well as carry out fracking operations without having to use separate tools and trip the tool out, in an effective and efficient manner. 
     U.S. Pat. No. 4,781,250 to McCormick et al., entitled “Pressure Actuated Cleaning Tool” teaches a downhole tool for cleaning tubing, casing and flow lines with pressurized cleaning fluid pumped through coiled tubing. The cleaning tool is rotated by a “J”-slot indexing tool, which activated by fluid pressure changes and a spring, to effectively rotate the tool 360°. McCormick et al does not, however, disclose any apparati or method on the same tool for further being able to carrying out fracking of the formation via the perforations created by such same tool. 
     U.S. Pat. No. 7,963,332 to Dotson, entitled “Apparatus and Method for Abrasive Jet Perforating”, teaches a device using an abrasive jet for perforating, with a mechanical locating collar. Such patent however does not teach any sliding sleeve to open and close the perforating jet, nor does it teach use of such perforator jet, in combination with a packers, a bypass, a “j” slot used to set and release a setting tool, and frac ports, all incorporated into and for use by the same tool to permit both perforating and fracking using the same tool. 
     Likewise, and to similar effect, U.S. Pat. No. 8,757,262 similarly to Dotson, entitled “Apparatus and Method for Abrasive Jet Perforating and Cutting of Tubular Members”, teaches an abrasive jet perforating tool, coupled rotatably to a tubing string, and a horizontal indexing tool coupled thereto. An extension tool with a protective sleeve is used to protect the apparatus. Again, however, such patent fails to disclose any apparati or method on the same tool for further being able to carrying out fracking of the formation via the perforations created by such same tool. 
     U.S. Pat. No. 5,765,756 by Jordan et al., entitled “Abrasive Slurry Jetting Tool and Method” teaches an abrasive jet perforating tool with telescoping jet nozzles. The jetting nozzles are operated perpendicularly to the longitudinal axis of the tool body, although the nozzle assemblies can pivot back into the tool body for retrieval back up the wellbore. Jordan et al similarly fails to disclose a single tool with further components which allow not only perforation but also setting of the tool to frac as well as perforate, or a method by which fracking and perforation using an abrasive jet may be accomplished by a single tool. 
     Accordingly, a clear need exists in the wellbore completion industry for a tool which uses abrasive jetting to create perforations in wellbore casings, and which may further accomplish fracking of the formation using the same tool, to thereby save time and speed completion of wellbores in preparation for hydrocarbon production therefrom. 
     A clear and serious need further exists in fracking operations to provide a tool which is not prone to becoming “sanded-in” within the wellbore. In this regard, a “sanded-in” fracking tool at the end of a frack string cannot be removed after fracking to thereby allow oil production to commence from the completed well. 
     Specifically, it has been found that fracking tools at the end of a fracking tubing string and which are typically lowered to the bottom of a wellbore and thereafter moved upwardly to successively frac the formation along the wellbore during such upward movement, may frequently, due to the introduction of fracking sand within a fracking mixture at each fracking interval to thereby “prop” open the fractures created in the wellbore to allow better flow of oil, cause the fracking tool becoming “sanded in” within the wellbore and the frac string thus be unable to be removed from the wellbore. 
     This is a very serious and potential problem if it occurs, as no production of oil can thereafter be achieved. The fracking string will then need to be pulled up with such force that it will break, and a milling tool re-inserted down the wellbore to mill out any remaining sand-entrapped components of the frack string remaining in the well, to thereby clear the well for production. 
     Obviously, ‘sanding-in’ of fracking tools is a very serious problem as it results in significant lost production time, to say nothing of the time resulting lost time and expense of having to mill out damaged and “sanded-in” frac string components. 
     A very serious need thus exists for a fracking tool which is able to reliably or better prevent “sanding in” of the tool after one or more successive fracking operations along a wellbore. 
     SUMMARY OF THE INVENTION 
     It is thus an object of one aspect of the invention to provide a frac tool which is adapted to successively frac a wellbore along its length, but is further provided with means to avoid the fracking tool becoming sanded-in after a particular fracking operation along the wellbore. 
     Accordingly, in one particular aspect the present invention provides a downhole tool which not only successively fracs at spaced intervals along a perforated wellbore, but is further provided with what is figuratively referred to herein as a “dump valve” which may be opened, if desired or considered necessary, to allow flushing of an annular space surrounding the frac tool with a flushing fluid after every successive frac operation carried out, so as to reduce the risk of the fracking tool, and thus the frac string, from becoming “sanded-in”. 
     More particularly, the present invention in a third embodiment thereof comprises a downhole tool for injecting a fluid into a hydrocarbon formations at various spaced intervals along a wellbore and further having capability to flush an annular space around the tool after each interval of injection of said fluid into the hydrocarbon formation, comprising:
         (i) an elongate substantially cylindrical member, having a hollow bore and an outer periphery, adapted for insertion in a wellbore;   (ii) an uphole cylindrical, hollow slidable sleeve within said bore;   (iii) a dump port, situated in said outer periphery, configured to direct a stream of fluid radially outwardly from said tool into an annular space between said tool and the wellbore, fluid communication of said dump port with said annular space allowed and prevented by slidable movement of said uphole slidable sleeve;   (iv) an uphole packer member, situated on a portion of said periphery downhole of said dump port;   (v) a downhole packer member, situated on a portion of said periphery downhole of said uphole packer member and spaced apart therefrom;   (vi) a frac port in said periphery of said cylindrical member, intermediate said uphole and said downhole packer members;   (vii) a slidably moveable guide member, having radially protruding slip members thereon, said slip members configured to frictionally engage said wellbore casing when said tool is inserted therein, said guide member situated on said tool downhole of said downhole packer member, said guide member further having radially expandable jaw members on an uphole side thereof; and   (viii) a ‘j’ slot subassembly within said tool, situated downhole of said downhole packer member, and having an associated cylindrical hollow mandrel with a slotted profile therein, said ‘j’ slot subassembly, when downward force is applied to said tool and said guide member frictionally engages said wellbore casing, does not allow further relative downward movement of a lower portion of said downhole packer member relative to said guide member and thus does not allow said jaw members to become actuated, and said ‘j’ slot sub-assembly when an upward pulling force is applied to said tool and thereafter a downward force is re-applied to said tool, is then in a ‘set’ position where said lower portion of said downhole packer member is allowed further downward downhole movement to allow said lower portion of said downhole packer member to be forced against said jaw members so as to expand them radially outwardly to engage said wellbore casing; and   wherein slight upward movement of the tool after said tool has been configured in said ‘set’ position within said wellbore causes said slidable sleeve to uncover said dump port and allow a flushing fluid to be delivered via the bore of said tool to said annular space.       

     Preferably, the uphole slidable sleeve is adapted to be slidably moved so as to uncover said dump port when the guide member and the outer periphery possessing the dump port remain stationary at a specific location within said wellbore and a portion of the tool uphole of the dump port and including the slidable sleeve is raised uphole. 
     Alternatively, the uphole slidable sleeve is adapted to be moved so as to uncover the dump port by a pick-up tool insertable within said bore of said tool. 
     In a refinement of this third embodiment, the tool is provided with an annular cup seal on the periphery of said tool intermediate the dump port and the said downhole packer member, which reduces flow of abrasive pressurized fluid and associated wellbore casing cuttings downhole. 
     In a further refinement, an expandable chamber and associated piston member is provided, wherein the chamber is adapted to receive fluid under pressure from the bore and cause the associated piston member, when the fluid is supplied to said bore, to compress and outwardly expand said uphole packer member; 
     In a still-further refinement, the tool possesses a bypass port in the periphery to allow bypass of fluid in the wellbore so as to circumvent the packers, when repositioning the tool. The bypass port is preferably situated uphole of the downhole packer, configured when open to provide fluid communication between an exterior of the tool and the hollow bore thereof and permit fluid exterior to said tool and above the downhole packer member to flow into said hollow bore; and 
     a slidable valve member which slidably opens and closes the bypass port; and 
     wherein when an upward force is exerted on said tool the slidable valve member is in an open position thereby keeping open said bypass port, and 
     wherein subsequently actuating the ‘j’ slot to the ‘set’ position by subsequent downward force on the tool and/or fluid pressure being further applied to the hollow bore uphole of the slidable valve member, the slidable valve member moves to a closed position thereby closing the bypass port. 
     In a still further refinement, the bore of the tool, in the region of said frac port, is provided with a deflector to deflect fracking fluid out the frac port. 
     In a fourth embodiment, the invention relates to a method for fracturing a hydrocarbon formation by injecting a pressurized fracking fluid containing said into said formation and repositioning such tool at various spaced intervals along a wellbore, which advantageously provides for a flushing step immediately prior to repositioning the tool for another fracking operation at a further uphole site along the wellbore. 
     Accordingly, in such embodiment of the present invention the method comprises the steps of: 
     (i) running said tool, which possesses a hollow bore in the region of a dump port and a frac port thereon, into said wellbore to a desired depth within said wellbore; 
     (ii) pulling upwardly on said tool to configure a ‘j’ slot on said tool from a “running” position of step (i) to a “pulling” position and positioning an uphole and downhole packer member situated on said tool on mutually opposite sides of a region along said wellbore which is desired to be fracked; 
     (iii) pushing slightly down on an upper portion of said tool to cause said ‘j’ slot to allow movement of a portion of the tool wherein jaw members on said tool are forced against said wellbore and a downhole packer member on said tool is longitudinally compressed and caused to expand radially outwardly, so as to configure said tool in a “set” position; 
     (iv) injecting said pressurized fracking fluid into said wellbore and into a bore of said tool and causing said pressurized fluid to pass via a frac port in said tool into fissures created in said formation extending radially outwardly from said wellbore; 
     (v) ceasing supply of said pressurized fracking fluid to said bore of the tool; 
     (vi) pulling upwardly on the tool to disengage the jaw members and re-configure the ‘j’ slot into said “pulling” configuration, and simultaneously causing a slidable sleeve covering said dump port to move so as to uncover said dump port; and 
     (vii) providing a flushing fluid not containing sand to the hollow bore of the tool and causing said flushing fluid to be expelled from the bore of the tool via the dump port and thereby flushing an annular space between the wellbore and the tool with said flushing fluid, and 
     (viii) thereafter pulling the tool further uphole for further subsequent injection of pressurized fluid containing sand into additional fissures created in the formation. 
     In a refinement of the above method, such method further comprises the step, at the time of performing step (iv) and injecting said pressurized fracking fluid into said bore, of causing a piston member in said tool to longitudinally compress an uphole packer member on said tool and cause said uphole packer member to expand radially outwardly. 
     In a still further refinement of the above method, step (iii) further comprises the step, when pushing downwardly on a portion of the tool uphole of the downhole packer, of closing a bypass port to thereby prevent the otherwise bypass of frac fluid downhole. 
     Alternatively, step (iv) may instead further comprise the step, when supplying pressurized fluid to said bore of said tool, of closing a bypass port to thereby prevent the otherwise bypass of frac fluid downhole. 
     Lastly, in a still further refinement of the above method, step (vi) of causing the slidable sleeve covering said dump port to move so as to uncover said dump port comprises the step of inserting a pick up tool within said wellbore and said bore of said tool to move said slidable sleeve uphole to a position uncovering said dump port. 
    
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
       Further advantages and permutations and combinations of the invention will now appear from the above and from the following detailed description of the various particular embodiments of the invention, taken together with the accompanying drawings each of which are intended to be non-limiting, in which: 
         FIG. 1  is a perspective view of a first embodiment of the downhole tool of the present invention, broken into three individual segments for illustrative purposes only; 
         FIG. 2A  is a partial cross-sectional view of the uphole portion of a first embodiment of the downhole tool, with the uphole portion of the tool being on the left-hand side of  FIG. 2A , when the tool is being “run” into the wellbore; 
         FIG. 2B  is a partial cross-sectional view of the lower portion of the tool of  FIG. 2A , with the downhole portion of the tool being on the right hand side of  FIG. 2B  and when the tool is being “run” into the wellbore, further showing in relief a view on the exterior of the tool in the region of ‘j’ slot, showing the position of such ‘j’-slot sub-assembly when the tool is in the “running” position; 
         FIG. 3A  is a partial cross-sectional view of the first embodiment of the downhole tool, again showing the upper portion of the tool, but when the tool is in the “pulling” position wherein a portion of the tool has been pulled uphole for effecting operation of the ‘j’ slot; 
         FIG. 3B  is a partial cross-sectional view of the first embodiment of the downhole tool, showing the lower portion of the tool of  FIG. 3A , again showing the downhole portion of the tool being on the right-hand side of  FIG. 3B , when the tool is configured in the “pulling” position, further showing in relief a view on the exterior of the tool in the region of ‘j’ slot sub-assembly and such ‘j’-slot sub-assembly when the tool is in the “pulling” position; 
         FIG. 4A  is a partial cross-sectional view of the same first embodiment of the downhole tool, again showing the upper portion of the tool, with the uphole portion of the tool being positioned on the left-hand side of  FIG. 4A , but instead when the tool is in the “set” position after a downhole force has subsequently been applied to the tool from the “pulling” position shown in  FIG. 3A  &amp;  FIG. 3B ; 
         FIG. 4B  is a partial cross-sectional view of the same first embodiment of the downhole tool shown in  FIG. 4A , showing the lower portion of the tool, again showing the downhole portion of the tool being positioned on the right-hand side of  FIG. 4B , when the tool is configured in the “set” position, further showing in relief a view on the exterior of the tool in the region of ‘j’ slot sub-assembly, showing the position of such ‘j’-slot sub-assembly when the tool is in the “set” position; 
         FIG. 5  is a flow diagram of a particular method of the present invention for perforating a wellbore casing and fracking the formation via the created perforations; 
         FIG. 6A  is a partial cross-sectional view of a second embodiment of the downhole tool, showing the upper portion of the tool (the lower portion of the tool remaining the same as in  FIG. 2B ), with the uphole portion of the tool being positioned on the left-hand side of  FIG. 6A , when the tool is being “run” into the wellbore; 
         FIG. 7A  is a partial cross-sectional view of the same second embodiment of the downhole tool, again showing the upper portion of the tool (the lower portion of the tool remaining the same as in  FIG. 3B ), with the uphole portion of the tool being positioned on the left-hand side of  FIG. 7A , but instead when the tool is in the “pulling” position wherein a portion of the tool having been pulled uphole for effecting operation of the ‘j’ slot; and 
         FIG. 8A  is a partial cross-sectional view of the same second embodiment of the downhole tool, again showing the upper portion of the tool (the lower portion of the tool remaining the same as in  FIG. 4B ), with the uphole portion of the tool being positioned on the left-hand side of  FIG. 8A , but instead when the tool is in the “set” position after a downhole force has subsequently been applied to the tool from the “pulling” position shown in  FIG. 7A ; 
         FIG. 9A  is a partial cross-sectional view of an upper portion of a third embodiment of the downhole tool, with the uphole portion of the tool being the left-hand side of  FIG. 9A , when the tool is being “run” into the wellbore; 
         FIG. 9B  is a partial cross-sectional view showing the lower portion of the tool of the third embodiment, with the downhole portion of the tool being on the right hand side of  FIG. 9B  and when the tool is being “run” into the wellbore, further showing in relief a view on the exterior of the tool in the region of ‘j’ slot, showing the position of such ‘j’-slot sub-assembly when the tool is in such “running” position; 
         FIG. 10A  is a partial cross-sectional view of the upper portion of the tool of the third embodiment, when the tool is in the “pulling” position wherein a portion of the tool has been pulled uphole for effecting operation of the ‘j’ slot; 
         FIG. 10B  is a partial cross-sectional view of the lower portion of the tool of the third embodiment, when the tool is configured in the “pulling” position, further showing in relief a view on the exterior of the tool in the region of ‘j’ slot sub-assembly and showing the position of such j′-slot sub-assembly when the tool is in such “pulling” position; 
         FIG. 11A  is a partial cross-sectional view of the upper portion of the tool of the third embodiment, when the tool is configured in the ‘set’ position for fracking, and when the dump port is closed; 
         FIG. 11B  is a partial cross-sectional view of the lower portion of the tool of the third embodiment when the tool is configured in the ‘set’ position, further showing in relief a view on the exterior of the tool in the region of ‘j’ slot sub-assembly and showing the position of such ‘j’-slot sub-assembly when the tool is in such ‘set’ position; 
         FIG. 12A  is a partial cross-sectional view of the upper portion of the tool of the third embodiment, when the tool is again pulled slightly uphold so as to open the dump port in such tool to allow fluidic flushing of the annular region between the tool and the wellbore; and 
         FIG. 12B  is a partial cross-sectional view of the lower portion of the tool when carrying out the flushing operation; and 
         FIG. 13  is a flow diagram of the method of the present invention for fracking and thereafter flushing the annular space to prevent sand-in, using a tool of the third embodiment, namely a flow chart depicting a method of successively configuring the tool as per the successive configurations shown in  FIGS. 9A &amp; 9B, 10A &amp; 10B, 11A &amp; 11B, and 12A &amp; 12B . 
     
    
    
     DETAILED DESCRIPTION OF SOME PREFERRED EMBODIMENTS 
     In the following description, similar components in the drawings figures are identified with corresponding same reference numerals. 
       FIG. 1  and  FIGS. 2A, 2B, 3A, 3B, 4A, 4B  together illustrate one embodiment of the downhole tool  10  of the present invention, with  FIG. 1  depicting the tool  10  separated into three individual segments for illustrative purposes only, with remaining  FIGS. 2A, 3A , and  4 A showing an upper portion of the same tool  10  in three successive stages of operation (as hereinafter further explained), with corresponding  FIGS. 2B, 3B, and 4B  showing the lower portion of the same tool  10  in the same three successive stages of operation. 
     As may be seen, tool  10  is adapted for insertion in a wellbore casing (not shown), and comprises an elongate substantially cylindrical member  20 . Cylindrical member  20  possesses a hollow bore  16  for receiving pressurized abrasive fluid and a frac fluid (which in one particular embodiment, as mentioned above, may be one and the same fluid), and further possesses an outer periphery  17 . A cylindrical hollow slidable sleeve  14  is positioned within bore  16 , adapted for longitudinal slidable movement along bore  16  in a reciprocating manner. 
     One or more jet ports  18  are provided in outer periphery  17  which are configured to direct a stream of pressurized abrasive fluid, typically a fluid containing quantities of sand and/or silica granules, radially outwardly from the tool  10 , for impacting and creating perforations in a surrounding wellbore casing. Jet ports  18 , typically two or more being located at a similar longitudinal position along cylindrical member  20  as shown in  FIGS. 2A-4A and 6A-8A , typically comprise jet nozzles  18 ′ of hardened steel having an single aperture therein, which are thread ably inserted into periphery  17  of tool  10  and are retained in periphery  17  by threaded bosses  19 . 
     In one preferred embodiment the diameter of an exit aperture in each jet nozzle  18 ′ is 0.0241 inches (0.61 mm) for creating perforations in the wellbore casing of similar size. At pressures of approximately 3,000 psi (20,685 kPa), with production wellbore casing thicknesses of ¼ inch (6.35 mm) (Schedule 20) carbon steel for a nominal 8.625 inch (193 mm) o.d. casing, with fine silica sand of 20-40 API mesh size (0.84-0.42 mm) (i.e. diameter less than 0.241 inch) and three nozzles, the penetration time using a jet nozzle  18 ′ will take in the range of 30 seconds to create a perforation of desired size in the casing. A similar time to perforate a wellbore casing exists when the casing is of cement as opposed to carbon steel. 
     The size of perforations desired to be created in wellbore casing (which is in turn dependent upon, inter alia, the characteristics (temperature, viscosity, and physical properties of the actual hydrocarbons which are being recovered from the underground formation) will determine the size of the aperture of each nozzle  18 ″. Typically two, and up to four, jet nozzles  18 ′ will be located at a similar longitudinal position on periphery  17  of cylindrical member  20 . For optimum adaptability of tool  10 , threaded bosses  19  on periphery  17  to tool  10  in which the jet port nozzles  18 ′ are threadably inserted are adapted to receive a variety of nozzles  18 ′ of varying apertures diameters, depending on the size of the perforations desired to be created in the wellbore casing. 
     Fluid communication between jet ports  18  (jet nozzles  18 ′) and inner bore  16  is regulated by slidable sleeve  14 , which when slidably positioned over jet ports  18  prevents fluid communication between bore  16  and jet ports  18 , effectively closing the jet ports  18 . Movement of slidable sleeve  14 , either by: (i) application of an uphole force to draw slidable sleeve  14  upward (ref.  FIG. 3A ), (ii) use of a “pick-up” tool (not shown), inserted downhole into bore  16  when tool  10  is at a location along a wellbore where a perforation therein is desired to be created, or (iii) by injection of a pressurized fluid in bore  16  which thereafter enters chamber  22  and causes slidable sleeve  14  to act as a piston (ref.  FIG. 7A, 8A ) so as to thereby be caused to move so as to open jet port  18 , are all alternative and different ways in which slidable sleeve  14  may be actuated to respectively allow and prevent fluid access from bore  16  to jet ports  18 . 
     In the embodiment of the invention shown in  FIGS. 2A, 3A, and 3B , slidable sleeve  14  is guided by a pin member  24  travelling in longitudinal slot  26  to ensure longitudinal guided movement of slidable sleeve  14  within cylindrical member  20  and bore  16 , and to provide extremities of movement for such slidable sleeve  14 . 
     An uphole packer member  30  is situated on a portion of periphery  17  of tool  10 , downhole of jet ports  18 . An expandable chamber  40  and associated piston member  41  are provided, wherein chamber  40  is adapted to receive fluid under pressure from bore  16  and cause said associated piston member  41 , when pressurized fluid is supplied to bore  16 , to compress and outwardly expand uphole packer member  30  to create a seal in the wellbore, between the tool and the wellbore casing. 
     A downhole packer member  32  is further provided, situated on a portion of periphery  17  of tool  10  downhole from uphole packer member  30 , as shown in  FIGS. 1, 2B, 3B , &amp;  4 B. Downhole packer member  32  is typically comprised of an elastomeric substance, and in uncompressed when in a non-activated state, as shown in  FIGS. 2B &amp; 3B . Upon high pressure fluid, such as a fracking fluid, being provided to bore  16 , such high pressure fluid flows into chamber  40  via aperture  43  in piston member  41  causing expansion of chamber  40  as may be seen in  FIG. 3A . Expansion of chamber  40  causes piston member  41  to compress upone packer member  30 , thereby creating a seal between tool  10  and wellbore casing at the location of uphole packer member  30  in the wellbore. 
     One or more frac ports  50  are provided on tool  10  circumferentially about the periphery  17  of cylindrical member  20 . Frac ports  50  are located on tool  10  intermediate uphole packer member  30  and downhole packer member  32 . 
     A slidably moveable guide member  60 , having radially protruding slip members  62  which frictionally engage the wellbore casing when tool  10  is inserted in the casing, is provided. Guide member  60  is situated on tool  10  downhole of downhole packer member  32 . Guide member  60  is further provided with radially expandable jaw members  78 , on an uphole side thereof, as shown in  FIGS. 2B, 3B &amp; 4B . 
     A ‘j’-slot subassembly  80  is provided on tool  10 , situated downhole of downhole packer member  32 . ‘J’-slot subassembly  80  comprises an inner mandrel member  64 , having a slotted profile “P” therein, and a pin member  65  which travels in slotted profile “P”. 
     When the ‘j’-slot subassembly  80  is in the ‘run’ position (ref.  FIG. 2A, 2B , and  FIG. 6A ) and downward force is applied to tool  10  guide member  60  frictionally engages the wellbore casing. In such “run” position, the slotted profile “P in associated mandrel member  64  does not allow further relative downward movement of a wedge-shaped lower portion  90  of downhole packer member  32 , and thus does not allow jaw members  78  to become actuated. 
     When an upward pulling force is applied to tool  10  (ref.  FIG. 3A, 3B , and  FIG. 7A ) and thereafter a downward force is re-applied to said tool  10  (ref.  FIG. 4A, 4B , and  FIG. 8A ), the ‘j’-slot subassembly becomes configured in the ‘set’ position where:
         (i) the wedge-shaped lower portion  90  of downhole packer member  32  is allowed further downward downhole movement to allow said lower portion  90  to be forced against jaw members  78  so as to expand them radially outwardly to engage the wellbore casing, and thereby fix the tool  10  within the wellbore casing to allow fracking to be carried out.       

     In a preferred embodiment a bypass port  94  is provided, uphole of the downhole packer member  32 , configured when open to provide fluid communication between an exterior of tool  10  and interior bore  16  and permit fluid exterior to tool  10  and above said downhole packer member  32  to flow into said bore. With such bypass port  94  the tool  10  may be more easily pulled uphole than would otherwise be the case. A slidable valve member  95  slidably opens and closes said bypass port  94 . 
     When an upward force is exerted on the tool  10  slidable valve member  95  is in an open position thereby keeping open bypass port  94 . When subsequently actuating said ‘j’ slot subassembly  80  to the ‘set’ position by subsequent downward force on tool  10 , and/or frac pressure is applied to bore  16 , slidable valve member  95  is moved to a closed position thereby closing bypass port  94 . 
     In the embodiments of the tool shown in  FIGS. 2B, 3B , &amp;  4 B, the slidable valve member  95  which is provided is moved to the closed position in  FIG. 4B , by hydraulic frac fluid being applied to bore  16 , which thereby moves spring-biased conical deflector  97  downhole, thereby moving slidable valve member  95  to cover and thereby close bypass port  94 . In an alternative configuration (not shown) mandrel  64  may further or alternatively be configured, to that when the “j’-slot subassembly  80  is in the “set” position, that bypass port  94  is thereby closed, either by mandrel  64  itself, or by mandrel  64  actuating slidable valve member  95  to close bypass port  94 . 
     Numerous other configurations to effectively close bypass port  94  upon ‘j’ slot subassembly  80  moving to the “set” position (as shown in  FIG. 4B ) will now occur to persons of skill in the art, and all such variations are within the contemplation of this invention. Similarly, conical deflector  97  is shown in  FIGS. 2B &amp; 3B  as being biased by a helical coil spring  99  to close port  50  and leave bypass port  94  open, unless a fluid pressure is supplied to bore  16 , allow conical deflector  97  to leave slidable valve member  95  in a position where bypass port  94  is closed and port  50  is open (ref.  FIG. 4B ) open. Other means of biasing conical deflector  97 , other than by spring means, to accomplish the aforesaid result will now occur to persons of skill in the art, and such permutations and substitutions are likewise contemplated as forming the invention described herein. 
       FIGS. 6A, 7A, 8A  show successive operation of an alternative embodiment of the upper portion of the tool  10  (the bottom portion of the tool  10  being identical to the configurations successively depicted in corresponding successive  FIGS. 2B, 3B , &amp;  4 B) in particular with regard to the manner of actuation of the sliding sleeve  14 , where such embodiment is specifically adapted to both perforate and frac at the same time. 
     The components of the bottom portion of the tool  10 , for the embodiment shown in successive  FIGS. 6A, 7A , &amp;  8 A, are identical and correspond to the configuration shown in corresponding successive  FIGS. 2B, 3B, and 4B . Specifically,  FIG. 6A  (and corresponding bottom portion of the tool  10  in such embodiment shown in  FIG. 2B ) shows the tool  10  of such embodiment in the “run in” position.  FIG. 7A  (and corresponding bottom portion of the tool  10  in such embodiment shown in  FIG. 3B ) shows the tool  10  of such embodiment in the “pulling” position. Lastly,  FIG. 8A  (and corresponding bottom portion of the tool  10  in such embodiment shown in  FIG. 4B ) shows the tool  10  of such embodiment in the “set” position. 
     In such alternative embodiment shown in  FIGS. 6A, 7A, and 8A , slidable sleeve  14  has a port  23  therein and is configured so as to form a chamber  22 . After the tool  10  is moved slightly uphole to the “pulling” position shown in  FIGS. 7A &amp; 3B ) and then moved downwardly to allow the ‘j’-slot to move to the “set” position (ref.  FIGS. 8A &amp; 4B ) pressurized abrasive fluid is the supplied to bore  16  of tool  10 . Such pressurized fluid enters chamber  22  via port  23  and causes slidable sleeve  14  to automatically move uphole as shown in  FIG. 8A , thereby uncovering jet port  18  to thereafter allow the perforation operation to be performed. In this alternative embodiment/alternative method, the pressurized abrasive fluid also serves as the fracking fluid. In such case, the foregoing embodiment allows simultaneous creation of an uphole perforation in the wellbore casing when such sliding sleeve  14  is opened, while at the same time fracking of the formation being simultaneously conducted by a lower portion of the tool  10 , since upper and lower packer members  30 ,  32  respectively now “straddle” an earlier-created perforation in the wellbore casing, and pressurized abrasive/fracking fluid is injected into the formation via such lower earlier-created perforation. 
     In the preferred embodiments of the upper portion of the tool  10  shown in  FIGS. 2A, 3A , &amp;  4  A, and  6 A,  7 A, &amp;  8 A, such upper portion  10  is provided with an annular cup seal  100  on periphery  17  of tool  10 . Such annular cup seal  100  is situated intermediate jet port  18  and said downhole packer member  32 , and serves to reduce flow of abrasive pressurized fluid and associated wellbore casing cuttings downhole during the casing perforation operation, which is part of the method of the present invention more fully explained below. 
     Manner of Operation of Tool, and Methods for Perforating Wellbore Casing and Fracking a Formation Using the Single Tool 
     A broad outline of a method for operating the tool  10  and methods for perforating a wellbore casing and fracking a formation using a single tool  10  are set out below and are depicted successively in  FIGS. 2A, 2B, 3A, 3B &amp; 4A,4B , and likewise successively for the alternative embodiment shown in  FIGS. 6A, 7A &amp; 8A  (with corresponding lower portions of the tool  10  shown respectively in  FIGS. 2B, 3B , &amp;  4 B). 
     In the method, broadly described, tool  10  is initially run into a wellbore casing to a desired depth in the wellbore casing. During such run-in, and as shown in  FIG. 2A  and  FIG. 6A , slidable sleeve  14  covers jet port  18 . Frac port  50  may be in an open or closed position (shown in the closed position in  FIGS. 2 b    &amp;  3 B and in the open position in  FIG. 4B ), and likewise for bypass port  94  may be in an open or closed position (shown in the open position in  FIGS. 2B, 3B  and in the closed position in  FIG. 4B ). Thereafter, when the tool  10  has been lowered to the lowermost portion of the wellbore which is desired to be perforated and fracked, slight upward movement of tool  10  (ref.  FIGS. 3A, 3B ) pulls slidable sleeve  14  uphole, while guide member  60  and slips  62  thereon generally keep the remainder of tool  10  at a fixed position within the wellbore, thusly opening jet port  18  and jet nozzles  18 ′. 
     An abrasive pressurized fluid containing an abrasive compound such as uniformly sized sand particles or tungsten carbide filings of small uniform dimension, is then injected into bore  16 . Such fluid not only enters chamber  40  through port  43  and caused piston  41  to compress uphole packer member  30  to thereby create a seal between tool  10  and the wellbore casing at such location, thereby preventing flow of abrasive fluid downhole, at such time the pressurised fluid is further expelled in a radially outward manner from jet ports  18  and jet nozzles  18 ′ to thereby impinge upon the wellbore casing, and after a short time interval of impingement, perforate the casing at such location, with perforations equal in number to the number of jet ports  18  (ref.  FIGS. 3A, 3B ) 
     It is noted that slidable sleeve  14  in the method of the present invention need not necessarily be opened by slight upward force on the tool string and tool  10 , as described above, but rather in an alternative embodiment shown in  FIGS. 6A, 7A, and 8A , such slidable sleeve  14  is configured so as to form a chamber  22 , and is opened by pressurized fluid being supplied to such chamber  22 . This variation is described further below. 
     After the above perforation operation is performed, injection of pressurized abrasive fluid is ceased, and tool  10  may then be further drawn uphole to thereby position both the uphole packer member  30  and the lower (downhole) packer member  32  of tool  10  on the uphole and downhole side, respectively, of the created perforation, so as to effectively “straddle” the perforation with packer members  30 ,  32 . 
     Thereafter, and as shown in  FIGS. 4A &amp;B, further downward force is re-applied reapplied to the tool  10  to move slidable sleeve  14  downward (downhole) to cover jet ports  18  and to further actuate ‘j’ slot subassembly to allow wedge-shaped lower portion  90  of lower packer member  32  to be forced against jaw members  78 , thereby causing such jaw members  78  to be forced radially outwardly and thus against the wellbore casing so as to thereby temporarily secure tool  10  within the wellbore casing. Simultaneously, by downhole packer member  32  being forced against jaw members  78  of guide member  60 , the downhole packer member  32  is compressed and caused to expand radially outwardly, thereby creating a seal between the tool  10  and the wellbore casing at that location. 
     Thereafter, as shown in  FIGS. 4A &amp;B, pressurized fracking fluid is injected into bore  16 , which causes piston member  41  in said tool  10  to compress said uphole packer member  30  and cause said uphole packer member  30  to expand radially outwardly, and thereby cause the pressurized fluid to pass into said the created perforation via frac port  50  in tool  10 . 
     Thereafter, after completion of the fracking of the wellbore and this particularly location, supply of the pressurized fracking fluid is ceased and an upward force is then re-applied to the tool  10  to disengage jaw members  78  and allow re-positioning of tool  10  further uphole for creating further perforations and injecting further fracking fluid into further created perforations at such locations. 
       FIG. 5  shows a further elaboration/itemization of one particular method  400  of the present invention, using the tool  10  configuration shown in  FIGS. 2A , B,  3 A,  3 B, &amp;  4 A,  4 B, and where a bypass port  94  further is utilized. 
     In step  401 , tool  10  is run downhole. Jet port  18  remains closed, and frac port  50  remains open, and neither upper packer member  30  or lower packer member  32  are “set” (i.e. compressed), thereby allowing the tool  10  to be run in into the wellbore, to a desired lowest depth where perforations and fracking is desired to be conducted. The ‘j’ slot subassembly  80 , namely pin member  65  within slot “P” of mandrel  62 , is in the “run in” position as shown in  FIG. 2B   
     If there is an existing perforation in the wellbore, the operator will, as shown in step  402 , elect to proceed to step  403  to pull up slightly on the tool  10  to move the j-slot  80  from the run-in” position to the “pulling position” as shown in  FIG. 3B , to thereby align frac port  50  proximate the perforation, and thereby also open bypass port  94  (If no existing perforation, the operate will proceed with step  407 , described below). Thereafter, in step  404  the operator will push tool  10  slightly back down in the wellbore, to move ‘j’ slot subassembly  80  to the “set” position (ref.  FIG. 4B ), and simultaneously set (i.e. compress) the lower packer member  32  and jaw members  78 , close bypass port  94 , and close jet port  18 . 
     In subsequent step  405 , pressurized frac fluid is then supplied to bore  16  to tool  10 , to “set” (i.e. compress) upper packer member  30  by movement of piston  41 , and frac fluid is injected into the formation in the region of the created perforation by supply of frac fluid to frac port  50  and thereby to the formation. 
     After fracking, tool  10  is pulled uphole in step  407  to thereby open jet port  18  and bypass port  94 , release lower packer  32  and jaw member  78 , and allow movement of tool  10  to an uphole location in the wellbore where desired to further perforate the casing. 
     In subsequent step  408 , abrasive fluid is supplied to bore  16  of tool  10 , and subsequently through jet port  18  to perforate the wellbore casing at such new uphole position, and thereafter the supply of such abrasive pressurized fluid is ceased. 
     In subsequent step  409 , the tool  10  is pulled further uphole to position frac port  50  over the newly created perforation, and move ‘j’-slot  80  to the “pulling” position. 
     If the desired length of the wellbore has not been completely perforated and fracked, the completion engineer reverts to step  404 , and re-execute steps  404 - 409  at such further location in the wellbore. Otherwise, if at such point the wellbore has been completely perforated and fracked to the extent desired, the tool  10  can then be removed from the wellbore. 
     The operation of the configuration of tool  10 , having the configuration shown in  FIGS. 6A, 7A , &amp;  8 A, allows both perforation and fracking to be simultaneously carried out, and necessarily involves the abrasive fluid being one and the same as the frac fluid. 
     Such further refinement to the method  400  comprises simultaneously with step  405  injecting the abrasive/frac fluid, causing, by injection of such abrasive/frac fluid, the slidable sleeve  14  to move to an open position and expelling said abrasive/fracking fluid in a radially outward manner via said jet port  18  to thereby create a further perforation in the wellbore. Step  409  further comprises the step of repositioning the tool  10  further uphole so as to further position upper packer member  30  above the further created perforation, and again supplying the abrasive/fracking fluid to tool  10  when in such further position, to frac the formation in the region of the further perforation in the wellbore, and at the same time to further create an additional uphole perforation. 
     Third Embodiment of the Tool, and Method for Fracking Using Such Tool 
     As noted in the Summary of the Invention, in a further aspect the present invention provides a downhole tool which not only successively fracs at spaced intervals along a perforated wellbore, but is further provided with what is figuratively referred to herein as a “dump valve” which may be opened, if desired or considered necessary, to allow flushing of an annular space surrounding the frac tool with a flushing fluid after every successive frac operation carried out, so as to reduce the risk of the fracking tool, and thus the frac string, from becoming “sanded-in”. 
     More particularly, the present invention in a third embodiment thereof comprises a downhole tool for injecting a fluid into a hydrocarbon formations at various spaced intervals along a wellbore and further having capability to flush an annular space around the tool after each interval of injection of said fluid into the hydrocarbon formation. 
     With reference to  FIGS. 9A &amp; 9B ,  FIGS. 10A &amp; 10   b ,  FIGS. 11A &amp; 11B ,  FIGS. 12 &amp; 12B , such figures depict the third embodiment of the tool of the present invention. 
     All numerical references identified in  FIGS. 9A &amp; 9B ,  FIGS. 10A &amp; 10   b ,  FIGS. 11A &amp; 11B ,  FIGS. 12 &amp; 12B  having the same reference numerals as identified in respect of earlier Figures perform the same function and correspond to a similar component as those components identified in such earlier drawings figures, and their description is incorporated with regard to the aforementioned drawings. 
       FIGS. 9A &amp; 9B ,  FIGS. 10A &amp; 10   b ,  FIGS. 11A &amp; 11B ,  FIGS. 12 &amp; 12B , and  FIG. 13  all teach a tool  10  and method  800 , respectively, which fracs a formation  200  at spaced intervals along a wellbore  204  but does not also perforate a wellbore or wellbore casing. Instead, in the variation of the aforementioned tool  10  as shown in the above Figures, the jet ports  18  and jetting nozzle  18 ′ (if further provided) are merely used as (or comprise), or substituted with, “dump ports”  300  (ref.  FIGS. 9A, 10A, 11A , &amp;  12 A) for providing a flushing fluid (not shown) into an annular space  202  between the tool  10  and the wellbore or wellbore casing  204  when the tool  10  is situated in the wellbore  204 . Such configuration advantageously serves to reduce incidence of potential “sanding in” of the tool  10  within wellbore  204  after a fracking operation is completed at a particular interval along wellbore  204 . 
       FIGS. 9A &amp; 9B ,  FIGS. 10A &amp; 10   b ,  FIGS. 11A &amp; 11B ,  FIGS. 12 &amp; 12B , each respectively shows an upper portion ( FIGS. 9A, 10A, 11A, and 12A ) and a corresponding bottom portion ( FIGS. 9B, 10B, 11B, and 12B ), respectively, during various sequential configurations of tool  10  during a run in, fracing operation, and subsequent flushing operation with a wellbore. 
     Specifically,  FIGS. 9A &amp; 9B  show the configuration of each of the top portion ( FIG. 9A ) and bottom portion ( FIG. 9B ) respectively of tool  10 , and in particular for the ‘j’-slot  80  thereof, during an initial “running in” configuration of the tool  10 . 
       FIGS. 10A, 10B  show the configuration of each of the top portion ( FIG. 10A ) and bottom portion ( FIG. 10B ) respectively of tool  10 , and in particular for the ‘j’-slot  80  thereof, during a subsequent “pulling” stage where the tool  10  has then been pulled slightly uphole to re-configure ‘j-slot  80  to the ‘pulling position’ 
       FIGS. 11A, 11B  show the configuration of each of the top portion ( FIG. 11A ) and bottom portion ( FIG. 11B ) respectively of tool  10 , and in particular for the ‘j’-slot  80  thereof, during a subsequent “setting” stage where the tool  10  has then been pushed slightly downhole to re-configure ‘j-slot  80  to the ‘set’ or ‘setting’ position’ and align frac port  50  of tool  10  proximate a perforation (not shown) in wellbore casing  204  or proximate a desired location along wellbore  204  for the first fracking operation. Configuration of ‘j’-slot  80  to the ‘set’ position causes/allows wedge-shaped lower portion  90  of lower packer member  32  to be forced against jaw members  78 , thereby causing such jaw members  78  to be forced radially outwardly and thus against the wellbore casing so as to thereby temporarily secure tool  10  within the wellbore or wellbore casing  204 . Simultaneously, by downhole packer member  32  being forced against jaw members  78  of guide member  60 , the downhole packer member  32  is compressed and caused to expand radially outwardly, thereby creating a seal between the tool  10  and the wellbore or wellbore casing  204  at that location. 
     When tool  10  is positioned and thereby configured in the ‘setting’ position shown in  FIG. 11A, 11B , a pressurized injection fluid (not shown) can then be supplied to the bore  16  of tool  10 . Supply of such pressurized injection (fracking) fluid which typically contains high percentages of silicates of uniform diameter, will then:
         (i) push down on spring-biased conical deflector, and cause bypass port  94  to then be closed;   (ii) in a configuration where, as described above, uphole packer member  30  is actuated by an expandable chamber  40  and associated piston member  41 , chamber  40  receives fluid under pressure from bore  16  via port  43  and causes associated piston member  41  to compress and outwardly expand uphole packer member  30  to create a seal in wellbore  204 ; and   (iii) cause high pressure frac fluid to flow out frac port  50  and into wellbore  204 , and frac the formation  200  in a region between upper and lower packer members  30 ,  32  not only creating fissures in the formation  200  but further allowing the sand particles in the injected fluid to “prop” open the fissures to allow in the formation  200  to flow into wellbore  204  via such fissures for subsequent production to surface.       

     After the aforesaid fracking operation at the desired interval along the wellbore  204  has been completed using the modified tool  10  described above, namely by subsequent cessation of supply of pressurized fluid to frac ports  50 , the tool  10  can then be configured as shown in  FIGS. 12A &amp; 12B  to conduct a flushing operation. 
     As may be seen from the configuration of the tool as shown in  FIGS. 12A, 12B , cessation of supply of high pressurized fluid results in:
         (i) disengagement of sealing of uphole packer member  30  with wellbore  204 , by piston  41  returning to its initial position; and   (ii) return of spring-biased conical deflector to a position closing frac port  50 , and opening bypass port  94 .       

     Tool  10  may then return to the configuration shown in  FIGS. 12A, 12B  by pulling the tool  10  slightly upwardly while guide member  62  hold a lower portion of the tool  10  below downhole packer  32  stationary within wellbore  204 , so as to release jaws&#39;  78  engagement with wellbore  204  and release downhole packer member  32  sealing engagement with wellbore  32 . 
     In addition, slight uphole movement of the upper portion of tool  10 , or by use of a “pick-up” tool as described below, will result in sliding sleeve  14  to be moved uphole, thereby uncovering dump ports  300 . 
     Accordingly, tool  10  when now configured to the configuration shown in  FIG. 12A, 12B , may advantageously then have a flushing fluid (typical not containing any sand or low concentration of sand) supplied to bore  16  to tool  10  and caused to flow out dump port(s)  300  into annular space  202 , and caused to be circulated via such annular space  202  back uphole for collection and processing. In such manner annular space  202  intermediate tool  10  and wellbore  204  may be flushed of sand in the region around the tool  10  and in all areas above the tool, thereby freeing the tool  10  for further movement uphole for progressively carrying out further fracking operations at spaced intervals uphole. 
     While  FIG. 11A  in comparison with  FIG. 12A  merely shows that sliding sleeve  10  and a portion of tool  10  has been pulled uphole slightly to thereby cause slidable sleeve  14  to slidably uncover dump port(s)  300 , other manners of actuating the sliding sleeve  14  to uncover the dump ports  300  can be employed. For example, a commonly-known “pick-up” tool (not shown) may be inserted in hollow bore  16  of tool  10  and actuated to removably and temporarily grasp sliding sleeve  14  and when such pick-up tool is then moved uphole, causing slidable sleeve  14  to uncover dump ports  300  (as shown for example in  FIG. 12A ). Upon sliding sleeve  14  reaching an extremity of travel uphole, further uphole movement of sliding sleeve  14  causes disengagement of pick-up tool therewith, allowing pick-up tool to thereafter be drawn uphole and removed from the wellbore  204 , and the tool  10 , and particularly the bore  16  thereof, to be supplied with a flushing fluid (preferably free of sand) which flushing fluid when passing from inner bore  16  of tool  10  into annular space  202  via dump port(s)  300  then flushes annular space  202  of any entrained sand, thereby preventing tool  10  from becoming sanded in within wellbore  204 . 
       FIG. 13  is a flow diagram, showing and summarizing the method  800  of the present invention using the third embodiment of the tool  10  as shown in  FIGS. 9A &amp; 9B ,  FIGS. 10A &amp; 10   b ,  FIGS. 11A &amp; 11B ,  FIGS. 12 &amp; 12B . 
     The first step  801  of method  800 , depicted in  FIGS. 9A &amp; 9B , involves running tool  10 , which possesses hollow bore  16  in the region of dump port  300  and frac port  50 , downhole to a desired depth within wellbore  204 , typically a lowermost position in wellbore  204 . Bypass port  94  will be open, and upper and lower packers  30 ,  32  will not be set in wellbore  204  ‘J’-slot  80  will be positioned in the “run in” position shown in  FIG. 9B . 
     The second step  802  of method  800  depicted in  FIGS. 10A &amp; 10B  comprises pulling slightly upwardly on tool  10  to configure ‘j’-slot  80  on tool  10  from a “running” position of step (i) to a “pulling” position, and positioning an uphole and downhole packer member  30 ,  32  situated on tool  10  on mutually opposite sides of a region along wellbore  204  which is desired to be fracked. 
     The third step  803  of method  800  depicted in  FIGS. 11A &amp; 11B  comprises pushing slightly down on an upper portion of tool  10  to cause said ‘j’ slot  80  to allow movement of a portion of tool  10  wherein jaw members  78  on tool  10  are forced against wellbore  204  and downhole packer member  32  on tool  10  is longitudinally compressed and caused to expand radially outwardly, so as to configure tool  10  in a “set” position. Pushing down on tool  10  will slidably close slidable sleeve  14  over dump ports  300 . 
     The fourth step  804  of method  800 , also carried out when the tool is configured as per the configuration shown in  FIGS. 11A &amp; 11B , involves injecting pressurized fracking fluid into bore  16  of tool  10 . Such causes conical deflector  94  to move to open frac port  50  and close bypass port  94 , and further causes the pressurized fluid to pass via a frac port  50  in tool  10  into fissures created in the formation extending radially outwardly from wellbore  204 . 
     The fifth step  805  of method  800 , also carried out when tool  10  is configured as per the configuration shown in  FIGS. 11A and 11B , entails ceasing supply of said pressurized fracking fluid to bore  16  of tool  10 . 
     The sixth step  806  of method  800 , carried out when the tool is configured as per the configuration shown in  FIGS. 12A and 12B , comprises pulling upwardly on tool  10  to disengage the jaw members  78  with wellbore  204  and re-configure the ‘j’ slot  80  into said “pulling” configuration, and simultaneously cause slidable sleeve  14  covering dump port  300  to move so as to uncover dump port  300 . 
     The seventh step  807  of method  800  comprises providing a flushing fluid not containing sand to hollow bore  16  of tool  10  and causing the flushing fluid to be expelled from bore  16  of tool  10  via dump port(s)  300  and thereby flushing the annular space  202  between wellbore  204  and tool  10  with said flushing fluid. 
     The eight step  808  of method  800  comprises thereafter pulling tool  10  further uphole for further subsequent injection of pressurized fluid containing sand into additional fissures created in formation  200 . 
     The foregoing description of the disclosed embodiments is provided to enable any person skilled in the art to make or use the present invention. The scope of the claims should not be limited by the preferred embodiments set forth in the examples, but should be given the broadest interpretation consistent with the description as a whole. Thus, the present invention is not intended to be limited to the embodiments shown herein, but is to be accorded the full scope consistent with the claims, wherein reference to an element in the singular, such as by use of the article “a” or “an” is not intended to mean “one and only one” unless specifically so stated, but rather “one or more”. In addition, where reference to “fluid” is made, such term is considered meaning all liquids and gases having fluid properties. 
     For a complete definition of the invention and its intended scope, reference is to be made to the summary of the invention and the appended claims read together with and considered with the disclosure and drawings herein.