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CROSS REFERENCE TO RELATED APPLICATIONS 
       [0001]    This application claims priority of U.S. Provisional Patent Application Ser. No. 61/719,765, entitled “Production String Activated Wellbore Sealing Apparatus and Method for Sealing a Wellbore Using a Production String”, filed Oct. 29, 2012, and hereby incorporates the same provisional application by reference herein in its entirety. 
     
    
     TECHNICAL FIELD 
       [0002]    The present disclosure is related to the field of wellbore sealing apparatuses, in particular, wellbore sealing apparatuses that can be connected in-line with a production string. 
       BACKGROUND 
       [0003]    Various wellbore sealing apparatuses are used in producing oil wells to provide a seal between the outside of tubing inserted into the wellbore and the inside of the casing, liner or wall of the wellbore. Providing a seal between the outside of the tubing and the inside of the wellbore is necessary in order to isolate different zones within the wellbore to facilitate various tasks. The wellbore sealing apparatuses used for this purpose are commonly known as packers. Production packers remain in wells while they are producing oil while service packers are used with work strings and are temporarily in wells for various well maintenance tasks, including cement squeezing, acidizing, fracturing and well testing. 
         [0004]    Many packers are not removable once they are put in place. A packer of this kind must be milled out of the wellbore when the user no longer wishes to use them. This is a time-consuming and expensive process, and the packer is destroyed as a result. 
         [0005]    More complex packers that use mechanical and hydraulic systems to engage and disengage can be removed more easily and reused. However, these packers cannot be operated using a production string. Instead, they require the use of additional equipment, specifically service rigs hooked up to a work string. To get the work string into the wellbore the production string must first be removed. When the work is completed, the work string is removed and the production string placed back in the well. This complicated process is time consuming and costly. 
         [0006]    Work strings can be used to deposit fluids into a wellbore when performing various maintenance tasks. Sand and other debris can collect at the sites of the perforations in a formation during production, which slows the rate of oil production and can cause wear on the production pumps. When the rate of production slows to a particular level, the well is cleaned. Typically this type of maintenance is performed using a work string which allows fluid to be pushed into the wellbore to clean the sand and other debris away from the perforations. Along with being forced into the formation through the perforation, thereby pushing the sand and debris from the openings, the fluid fills the space between the casing and the work string tubing. The amount of fluid required is typically greater than can be transported in standard tank trucks, therefore more than one trip has to be made. The majority of the fluid must be removed before the work string is removed and the production string put back in place. Whether or not sufficient sand and debris has been removed during the maintenance process can only be determined after the production string is replaced in the wellbore. Therefore, only one cleaning cycle can occur every day. 
         [0007]    It is therefore desirable to provide a wellbore sealing apparatus that overcomes the shortcomings of the prior art. 
       SUMMARY 
       [0008]    A wellbore sealing apparatus which is positioned along production string tubing is provided. This sealing apparatus combines an outer sleeve, an inner mandrel telescopically received within the outer sleeve, a sealing element that expands when compressed, an actuator interaction assembly and top and bottom seal pushers. The sealing element is disposed on the inner mandrel with the top seal pusher uphole and the bottom seal pusher downhole. The actuator interaction assembly has a means to couple to an actuator and is positioned downhole, but in-line with the inner mandrel. The inner mandrel includes a pin or peg extending outwardly and interacts with a slot in the outer sleeve to limit rotation of the inner mandrel. When the actuator couples to the actuator interaction assembly, the inner mandrel is pushed upwardly to be telescopically received into the outer sleeve. This movement also causes the top and bottom seal pushers to be brought closer together and exert opposing pressure on the sealing element such that the sealing element compresses and expands to form a seal with the wellbore casing. 
         [0009]    In one aspect of the invention, the actuator interaction assembly contains one or more slots in the assembly body that allow an actuator having one or more connectors to couple to the actuator interaction assembly by sliding the one or more connectors into the one or more slots. Alternatively the slots may be on the actuator and the connectors may be on the assembly body. In one aspect of the invention the slots are J-shaped. 
         [0010]    In a further aspect of the invention, the actuator interaction assembly may also include at least one gap between the first and section sections of the assembly body to allow connectors in the actuator to pass through the actuation interaction assembly. Alternatively, there may be at least one by-pass gap extending longitudinally along the length of the actuator to allow it to pass by connectors in the actuator interaction assembly. 
         [0011]    The actuator interaction assembly can further comprise a top assembly sleeve, an assembly body having first and second sections, and a bottom assembly sleeve. The top and bottom assembly sleeves can comprise an assembly body enclosure for housing the first and second sections of the assembly body. The first and second sections of the assembly body can also each include a slot and/or a connector. The first and second sections of the assembly body can be oriented such that slots or connectors, or a combination thereof, can connect or couple to the actuator. 
         [0012]    In one aspect of the invention the length and location of the peg slot on the outer sleeve and the location of the at least one peg on the inner mandrel can be such that the inner mandrel is unable to extend out of the outer sleeve to a position where substances in the well could enter the central conduit running through the inside of the wellbore sealing apparatus through the at least one peg slot. 
         [0013]    In some embodiments, the wellbore sealing apparatus can further comprise a seal piston. The seal piston can attach to the top of the inner mandrel and the seal piston and the inner mandrel can be inserted into the bottom of the outer sleeve. The inner mandrel can slide back and forth within the outer sleeve while the seal piston acts to prevent substances from leaking into a central conduit running through the inside of the wellbore sealing apparatus by forming a seal between the inside of the outer sleeve and the outside of the seal piston. In some embodiments, the seal between the inside of the outer sleeve and the outside of the seal piston can be airtight. 
         [0014]    The seal piston can further comprise a piston body, a seal and a cap. The piston body can comprise a threaded cap insert, a seal holder and a first collar. The cap can comprise a threaded midsection. The seal can be put over the piston body around the seal holder and the threaded midsection of the cap can be threaded onto the threaded cap insert of the piston body to secure the seal in place. 
         [0015]    In another aspect of the invention the sealing apparatus also includes a biasing means, disposed on the inner mandrel between the outer sleeve and the top seal pusher. The biasing means can assist in disengaging the wellbore sealing apparatus by pushing the inner mandrel out of the outer sleeve when the actuator stops pushing the inner mandrel into the outer sleeve. 
         [0016]    The wellbore sealing apparatus can further comprise a spring pusher connected to the bottom end of the outer sleeve. The main body of the spring pusher can comprise a spring slot, with the spring slot oriented such the top end of the spring fits into the spring slot. 
         [0017]    An actuator positioned on a production rod string is also provided. The actuator has a coupling or connecting means that allows it to couple to an actuator interaction assembly when the production rod string is pulled upwardly. The coupling or connecting means can be connectors or slots, or a combination thereof. The actuator may also comprise a by-pass gap that allows it to pass by the connectors positioned on the actuator interaction assembly. 
         [0018]    A method for sealing a wellbore using a production string is also provided. A sealing apparatus having a sealing element and an actuator interaction assembly is positioned along the production string tubing and an actuator positioned along the production rod string. The actuator is coupled or connected to the actuator interaction assembly of the sealing apparatus, and then the sealing element is compressed and expands to form a seal between the sealing apparatus and the wellbore casing. 
         [0019]    The actuator interaction assembly may include slots and/or connectors which interact with corresponding connectors and/or slots on the actuator. This interaction allows the actuator to couple or connect to the sealing apparatus. 
         [0020]    In one aspect of the invention, the slots are J-shaped and are oriented in such a way that when placed adjacent to one or more connectors, when the actuator is rotated and/or lifted the connectors slide into the slots. 
         [0021]    In one aspect of the invention the method further comprises disengaging the sealing apparatus by lowering and uncoupling the actuator from the sealing assembly. The production string rod can push down on the actuator and the actuator interaction assembly, thereby pulling the inner mandrel out of the outer sleeve and contracting the sealing element to disengage the wellbore sealing apparatus. The actuator can be removed from the actuator interaction assembly by positioning and rotating the actuator so that the connectors slide out of the slots. 
         [0022]    Since the sealing apparatus is positioned along the production string tubing and the actuator is positioned along the production rod string, there is no need to use a work string or to remove the production string from the wellbore when is it desirable to seal the well to perform maintenance tasks. It also means that it may be possible to provide multiple stimulations per day. In addition, the use of a seating element means that less volume of fluid may be required to perform any necessary treatment and may also improve the degree of success of the treatment. 
     
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
         [0023]      FIG. 1  is a partial cross-section side view depicting one embodiment of a production string activated wellbore sealing apparatus. 
           [0024]      FIG. 2  is a partial cross-section side view depicting an embodiment of a top connector of the production string activated wellbore sealing apparatus of  FIG. 1 . 
           [0025]      FIG. 3  is a cross-section side view depicting an embodiment of an outer sleeve of the production string activated wellbore sealing apparatus of  FIG. 1 . 
           [0026]      FIG. 4  is a partial cross-section side view depicting an embodiment of a spring pusher of the production string activated wellbore sealing apparatus of  FIG. 1 . 
           [0027]      FIG. 5  is a partial cross-section side view depicting components of an embodiment of a seal piston of the production string activated wellbore sealing apparatus of  FIG. 1 . 
           [0028]      FIG. 6  is a partial cross-section side view depicting an embodiment of an inner mandrel of the production string activated wellbore sealing apparatus of  FIG. 1 . 
           [0029]      FIG. 7  is a side view depicting an embodiment of a top seal pusher of the production string activated wellbore sealing apparatus of  FIG. 1 . 
           [0030]      FIG. 8A  is a side view depicting an embodiment of a bottom seal pusher of the production string activated wellbore sealing apparatus of  FIG. 1 . 
           [0031]      FIG. 8B  is a top view depicting the bottom seal pusher of  FIG. 8A . 
           [0032]      FIG. 9A  is a side view depicting an embodiment of a peg of the production string activated wellbore sealing apparatus of  FIG. 1 . 
           [0033]      FIG. 9B  is a top view depicting the peg of  FIG. 9A . 
           [0034]      FIG. 10  is a cross-section side view depicting an embodiment of a top assembly sleeve of the production string activated wellbore sealing apparatus of  FIG. 1 . 
           [0035]      FIG. 11A  is a top elevation view depicting an embodiment of the assembly body of the production string activated wellbore sealing apparatus of  FIG. 1 . 
           [0036]      FIG. 11B  is a side elevation view depicting the assembly body of  FIG. 11A . 
           [0037]      FIG. 12  is a cross-section side view depicting an embodiment of a bottom assembly sleeve of the production string activated wellbore sealing apparatus of  FIG. 1 . 
           [0038]      FIG. 13A  is a partial cross-section side view depicting the production string activated wellbore sealing apparatus of  FIG. 1  disengaged within a well along with an actuator attached to the end of a production rod string. 
           [0039]      FIG. 13B  is a partial cross-section side view depicting the production string activated wellbore sealing apparatus of  FIG. 1  engaged within a well along using an actuator attached to the end of a production rod string. 
           [0040]      FIG. 14A  is a side view depicting an embodiment of the actuator of  FIGS. 13A and 13B . 
           [0041]      FIG. 14B  is a top view depicting the actuator of  FIG. 14A . 
       
    
    
     DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENT 
       [0042]    A production string is comprised of two main components, the production string tubing and the production rod string. The bottom end of the production string is open to allow for fluid to enter into the inner portion of the tubing. The fluid is pulled into the tubing and pushed upwardly by a pump located at the bottom end of the production string. The pump is comprised of a rotor and stator. The rotor is attached to the end of the production rod string, which travels the inner length of the tubing. When it is desirable to deposit fluid into the formation, the production rod string is pulled upward and the rotor is disengaged from the stator so that the fluid can move past the rotor and out the openings at the bottom end of the production string. 
         [0043]    The production string activated wellbore sealing apparatus is positioned along the production string tubing, and the actuator is positioned along the production rod string. 
         [0044]    Referring to  FIG. 1 , a preferred embodiment of a production string activated wellbore sealing apparatus is shown. In this embodiment the production string activated wellbore sealing apparatus  10  comprises top connector  20 , outer sleeve  30 , spring pusher  40 , seal piston  100 , inner mandrel  90 , spring  50 , top seal pusher  60 , sealing element  70 , bottom seal pusher  80  and actuator interaction assembly  140 . 
         [0045]    Referring to  FIG. 2 , an embodiment of top connector  20  is shown. The top connector  20  can comprise main body  21 , threaded production string tubing insert  27 , collar  22 , threaded outer sleeve insert  23 , central conduit  25  and widened opening  26 . 
         [0046]    Referring to  FIG. 3 , an embodiment of outer sleeve  30  is shown. The outer sleeve  30  can comprise main body  31 , peg slot  32 , first inner threaded opening  36 , second inner threaded opening  37  and central conduit  35 . 
         [0047]    Referring to  FIG. 4 , in some embodiments, a spring pusher  40  can be used. The spring pusher  40  can comprise main body  41 , spring slot  42 , threaded outer sleeve insert  43  and mandrel passage  45 . 
         [0048]    Referring to  FIG. 5 , an embodiment of the seal piston  100  is shown. The seal piston  100  comprises cap  101  and piston  110 . Cap  101  can comprise inner threaded midsection  102 , widened opening  103 , central conduit  105 , seal holder opening  106 , seal end  107  and chamfered end  108 . Piston  110  can comprise threaded cap insert  111 , seal holder  112 , first collar  113 , central conduit  115 , midsection  116 , second collar  117 , threaded mandrel insert  118  and seal  120 . The seal  120  fits over the top of piston  110  at seal holder  112 . The inner threaded midsection  102  of cap  101  screws onto the threaded cap insert  111  of piston  110  so that seal holder opening  106  of cap  101  fits around the seal holder  112  of piston  110  and the threaded insert  111  of piston  110  contacts the edge of the central conduit  105  of cap  101  such that the seal  120  can be held in place between the first collar  113  of piston  110  and the seal end  107  of cap  101 . The central conduit  115  of piston  110  and the central conduit  105  of cap  101  form one continuous passageway through the center of the seal piston  100 . 
         [0049]    Referring to  FIG. 6 , an embodiment of inner mandrel  90  is shown. The inner mandrel  90  comprises main body  91 , threaded peg passage  92 , collar  93 , central conduit  95 , threaded channel assembly insert  96  and inner threaded opening  97 . 
         [0050]    Referring to  FIG. 7 , an embodiment of top seal pusher  60  is shown. The top seal pusher  60  can comprise seal end  61 , chamfered end  62 , spring slot  63  and mandrel passage  65 . 
         [0051]    Referring to  FIGS. 8A and 8B , an embodiment of bottom seal pusher  80  is shown. The bottom seal pusher  80  can comprise seal end  81 , chamfered end  82  and mandrel passage  85 . 
         [0052]    Referring to  FIGS. 9A and 9B , an embodiment of peg  130  is shown. The peg  130  can comprise threaded section  131 , head  132  and wrench slot  133 . 
         [0053]    Referring to  FIGS. 1 ,  10 ,  11 A,  11 B and  12 , an embodiment of the actuator interaction assembly  140  is shown. The actuator interaction assembly comprises a top assembly sleeve  150 , an assembly body  158 , having a first section  160  and a second section  170 , and a bottom assembly sleeve  180 . The top assembly sleeve  150  can comprise inner mandrel end  151 , widened opening  152 , inner threaded opening  153 , assembly body enclosure  155  and chamfered end  156 . The first section of the assembly body  160  can comprise a first slot  161  having slot opening  162 , angled portion  163 , vertical portion  164  and slot end  165 . The second section of the assembly body  170  can comprise s second slot  171  having slot opening  172 , angled portion  173 , vertical portion  174  and slot end  175 . The bottom assembly sleeve  180  can comprise chamfered end  181 , enclosure section  182 , threaded end  183  and assembly body enclosure  185 . 
         [0054]    The curvature of the assembly body  158  corresponds to the curvature of the inside of assembly body enclosures  155  and  185  of top assembly sleeve  150  and bottom assembly sleeve  180 . Chamfered end  156  of top assembly sleeve  150  can be welded to chamfered end  181  of bottom assembly sleeve  180 . The assembly body  158  can be welded to the walls of the cavity formed by assembly body enclosures  155  and  185 , and oriented such that the vertical portion  164  and the slot end  165  of the first slot  161  are aligned directly with the vertical portion  174  and the slot end  175  of the second slot  171 . The angled portion  163  and the slot opening  162  of first section of the assembly body  160  are oriented in a substantially opposite direction to the angled portion  173  and the slot opening  172  of second section of the assembly body  170 . The two gaps between the first and second sections of the assembly body  160  and  170  are oriented opposite one another at the midpoint between the vertical portions  164  and  174  and slot ends  165  and  175 . The central conduit  145  of the actuator interaction assembly  140  is formed by the space in the center of the top assembly sleeve  150  and bottom assembly sleeve  180 , terminating with bottom opening  190 . 
         [0055]    The production string activated wellbore sealing apparatus is positioned within the length of a production string tubing, with the top connector  20  being attached to the production string tubing uphole of the apparatus and the bottom opening  190  being attached to the production string tubing downhole of the apparatus. The apparatus is hollow such that it has a passageway along its entire length that allows fluid communication between the uphole and downhole sections of production string tubing. 
         [0056]    Referring to  FIGS. 1 through 4 , the threaded outer sleeve insert  23  of top connector  23  can screw into first inner threaded opening  36  of outer sleeve  30  such that collar  22  of top connector  20  rests against the edge of main body  31  of outer sleeve  30 . 
         [0057]    When a spring  50  is present, the threaded outer sleeve insert  43  of spring pusher  40  screws into the second inner threaded opening  37  of outer sleeve  30  and the main body  41  of spring pusher  40  can rest against the main body  31  of the outer sleeve  30 . The central conduit  25  of top collar  20  and central conduit  35  of outer sleeve  30  therefore form a continuous passageway. Although a spring  50  is shown in the figures, other biasing means may be placed between the sealing element  70  and the outer sleeve  30 . An apparatus without a spring or other biasing means is also contemplated. 
         [0058]    Referring to  FIGS. 1 ,  5  and  6 , to form a continuous passageway, the threaded mandrel insert  118  of seal piston  100  can screw into the inner threaded opening  97  of the inner mandrel  90  such that the second collar  117  of seal piston  110  can rest against the main body  91  of inner mandrel  90  and central conduit  115  of piston  110 . 
         [0059]    Referring to  FIGS. 1 and 4  through  7 , the seal piston  100  and main body  91  of inner mandrel  90  can be inserted into outer sleeve  30  and spring pusher  40  through mandrel passage  45  of spring pusher  40 . The outer diameter of the main body  91  of the inner mandrel  90  and the inner diameters of mandrel passage  45  of the spring pusher  40  and the main body  31  of outer sleeve  30  can be such that the main body  91  of inner mandrel  90  is telescopically received by the mandrel passage  45  of spring pusher  40  and main body  31  of outer sleeve  30 . Seal  120  of seal piston  100  fits snugly against the inside of main body  31  of outer sleeve  30  so that a continuous passageway is formed by central conduit  95  of inner mandrel  90 , central conduit  115  of piston  110  of seal piston  100 , central conduit  105  of cap  101  of seal piston  100 , central conduit  35  of outer sleeve  30 . In addition, the central conduit  25  of top collar  20  is isolated from the narrow annulus formed between the outside of main body  91  of the inner mandrel  90  and the inside of main body  31  of the outer sleeve  30 . The position and dimensions of the seal piston  100  are such that any fluid or material that may be traveling through the hollow center of the apparatus  10  is not able to escape through the peg slot  32  of the outer sleeve  30  and enter into the space between the outer sleeve  32  and the well casing  2 . 
         [0060]    It is desirable to keep the production string tubing, actuator interaction assembly  140  and inner mandrel  90  from rotating within the well casing  2 . The preferred method to minimize rotation is shown in  FIGS. 1 ,  3 ,  4 ,  6 ,  9 A and  9 B. The threaded peg passage  92  of the inner mandrel  90  aligns with peg slot  32  of outer sleeve  30  so that outer threaded section  131  of peg  130  can screw into the threaded peg passage  92  of inner mandrel  90 . The outer diameter of the head  132  of peg  130  corresponds with the width of the peg slot  32  of the outer sleeve  30  such that there is minimal rotation by the inner mandrel  90  with respect to the outer sleeve  30 , while allowing the head  132  of peg  130  can slide back and forth within peg slot  32  of the outer sleeve  30  as the main body  91  of the inner mandrel  90  is retracted into and extended out of the mandrel passage  45  of spring pusher  40 . The length of the peg slot  32  and its location on outer sleeve  30  as well as the location of the threaded peg passage  92  of the inner mandrel  90  can be such that the seal  120  of seal piston  100  will always remain completely above the peg slot  32  so that debris cannot enter the central conduit  35  of outer sleeve  30  through peg slot  32 . Limiting the rotation of the inner mandrel  90  also limits the rotation of the actuator interaction assembly  140  and the downhole production string tubing. While the figures show the use of a circular peg and an elongated peg slot, it is contemplated that the peg and peg slot may have an alternate shape, for example square or tapered, and an L-shape or a T-shape, respectively. 
         [0061]    Referring to  FIGS. 1 ,  4  and  6  through  8 B, the bottom seal pusher  80 , sealing element  70  and top seal pusher  60  are disposed on the main body  91  of inner mandrel  90 . The inner diameters of the mandrel passage  85  of bottom seal pusher  80 , sealing element  70  and mandrel passage  65  of top seal pusher  60  may all correspond to the outer diameter of main body  91  of inner mandrel  90 . The top seal pusher  60  is positioned uphole of the sealing element  70  and downhole of the outer sleeve  30 , while the bottom seal pusher  80  is positioned downhole of the sealing element  70  and uphole of the actuator interaction assembly  140 . When in the sealing or engaged position, described below, the top seal pusher  60  produces a downward force on the sealing element  70  and the bottom seal pusher  80  produces an upwards force on the sealing element  70 , thereby causing the sealing element  70  to be compressed. The top seal pusher may be contiguous with the outer sleeve  30 , the sealing element  70 , both or neither when the sealing apparatus is in the disengaged position. Similarly, the bottom seal pusher may be contiguous with the actuator interaction assembly  140 , the sealing element  70 , both or neither when the sealing apparatus is in the disengaged position. 
         [0062]    In the preferred embodiment, chamfered end  82  of the bottom seal pusher  80  rests against collar  93  of the inner mandrel  90 . The sealing element  70  is positioned between seal end  81  of bottom seal pusher  80  and seal end  61  of top seal pusher  60 . 
         [0063]    When present, the spring  50  is disposed on the main body  91  of the inner mandrel  90  and may have an inner diameter that corresponds to the outer diameter of the main body  91  of the inner mandrel  90 . The bottom of the spring  50  can rest in the spring slot  63  of the top seal pusher  60  and top of spring  50  can rest in spring slot  42  of spring pusher  40 . 
         [0064]    Referring to  FIGS. 1 ,  6  and  10 , the threaded assembly insert  96  of inner mandrel  90  can screw into the inner threaded opening  153  of the top assembly sleeve  150  of actuator interaction assembly  140  such that collar  93  of inner mandrel  90  can rest within widened opening  152  of top assembly sleeve  150 . 
         [0065]    The wellbore sealing apparatus  10  interacts with an actuator  200 . The actuator  200  is positioned along the production rod string, which runs longitudinally through the internal passageway of the production string tubing. 
         [0066]    In one embodiment, as shown in  FIGS. 14A and 14B , the actuator  200  has connectors  202  which interact with the slots in the assembly body  158 . Alternatively, the slots can be located in the actuator  200  and the connectors can be located in the assembly body  158 . 
         [0067]    In use, the wellbore sealing apparatus  10  is placed at a certain point along the production string and lowered into the well  1 . Similarly, the actuator  200  is placed at a certain point along the production rod string  3  and lowered into the well  1 . The sealing apparatus is engaged or disengaged using actuator  200 , through the movement of the production rod string  3 . 
         [0068]    When the well is producing oil the sealing apparatus  10  is in its disengaged state, meaning the sealing element  70  is relaxed and not contacting the well casing  2 . To move the apparatus into its sealed or engaged position, the production rod string  3  is pulled upwardly so that the actuator  200  couples to the actuator interaction assembly. This coupling results in the upward movement of the inner mandrel  90  telescopically into the outer sleeve  30 , thereby causing the top seal pusher  60  and bottom seal pusher  80  to exert opposing forces on the sealing element  70 . This pressure results in the sealing element  70  compressing vertically and extending horizontally thereby creating a seal with the well casing  2 . 
         [0069]    In the preferred embodiment the coupling of the actuator  200  and the actuator interaction assembly  140  occurs as a result of the alignment of the slots and connectors on the assembly body  158  and actuator  200 , respectively. In an alternate embodiment, the slots may be found on the actuator  200  and the connectors on the assembly body  158 . While the figures show the preferred use of round connectors and J-shaped slots, it is contemplated that other shapes of connectors and slots can be used to couple the actuator  200  and the actuator interaction assembly  140 . 
         [0070]    In order to engage the apparatus of the preferred embodiment, the connectors  202  on the actuator  200  should first align vertically with the first and second slot openings  162  and  172  of the assembly body  158 . Next, the production rod string  3  is rotated such that connectors  202  enter slots  161  and  171 . The production rod string continues to be rotated and raised until connectors  202  contact slot ends  165  and  175 . Once this coupling has occurred, the production rod string  3  can pull up on actuator  200  and thus actuator interaction assembly  140 , causing the top and bottom seal pushers to move towards each other and exert opposing forces on the sealing element  7 . These opposing forces compress the sealing element vertically, while expanding it horizontally. When a spring  50 , or other biasing means, is present, it can assist in the compressing of the sealing element  70  by placing additional force on the top or bottom seal pushers or both. At the same time, the inner mandrel  90  and seal piston  100  to slide up into the outer sleeve  30 . 
         [0071]    The apparatus is fully engaged when sealing element  70  forms an airtight seal against well casing  2  of well  1 , isolating the upper well section  4  from the lower well section  5 . 
         [0072]    With the lower section of the well being sealed off from the upper section of the well, fluid or other material may be injected into the well. 
         [0073]    After the maintenance is completed, the sealing apparatus can be disengaged using the production rod string  3 . The actuator  200  is lowered and allows the force of gravity to act on the actuator interaction assembly  140  and inner mandrel  90 . The pressure on the sealing element  70  from the top and bottom seal pushers is relaxed, which allows sealing element  70  to expand vertically and retract horizontally, removing the seal between sealing element  70  and well casing  2  of well  1 . When present, the force of the spring  50 , or other biasing means, can also assist in sliding the inner mandrel  90  and seal piston  100  out of outer sleeve  30 . 
         [0074]    Once the sealing apparatus is disengaged the well can quickly begin producing again. If the maintenance process did not adequately fix the production problem, the sealing apparatus can be re-engaged and subsequent maintenance can begin. Therefore, multiple stimulation of the well may occur in one day. 
         [0075]    In the preferred embodiment, the production rod string  3  can raise and lower the actuator  200  past the actuator interaction assembly  140  by rotating the actuator  200  so that connectors  200  are oriented to pass through the gaps between first assembly body  160  and second assembly body  170 . This allows the rotor and/or actuator  200  to be removed and serviced without have to remove the production string tubing. Alternatively, where the connectors are on the assembly body, the gaps are located in the actuator. 
         [0076]    In some embodiments there is a widened opening  26  of top connector  20  to prevent attachments on the end of production rod string  3  from getting caught on the threaded outer sleeve insert  23  of the top connector  20  as the production rod string  3  is being raised. Similarly, the widened opening  103  of cap  101  of seal piston  100  can prevent attachments on the end of production rod string  3  from getting caught on the cap  101  of seal piston  100  as production rod string  3  is being lowered. 
         [0077]    Although a few embodiments have been shown and described, it wilt be appreciated by those skilled in the art that various changes and modifications can be made to these embodiments without changing or departing from their scope, intent or functionality. The terms and expressions used in the preceding specification have been used herein as terms of description and not of limitation, and there is no intention in the use of such terms and expressions of excluding equivalents of the features shown and described or portions thereof, it being recognized that the invention is defined and limited only by the claims that follow.

Summary:
A wellbore sealing apparatus positioned along production string tubing is provided to allow for sealing of a wellbore without needing to use a work string. The sealing apparatus includes an outer sleeve, an inner mandrel telescopically received within the outer sleeve, a sealing element positioned on the inner mandrel, an actuator interaction assembly and top and bottom seal pushers. An actuator positioned along the production rod string is also provided. The wellbore sealing apparatus has a sealed or engaged position and a disengaged position. To seal the wellbore, the actuator is pulled upwardly via the production rod string and couples to the actuator interaction assembly of the sealing apparatus. The continued upward movement of the actuator results in the inner mandrel moving further into the outer sleeve and the top and bottom pushers exerting opposing forces on the sealing element. The sealing element compresses and expands to seal the wellbore.