Abstract:
A method for performing a service operation within a wellbore extending into a formation comprises sealing a first length of the wellbore to define a first isolated formation zone, flowing a pressurized fluid through a tubular string into the first isolated formation zone, and unsealing the first length of the wellbore without venting the pressurized fluid from the tubular string or awaiting depressurization of the first isolated formation zone. 
     An assembly connected to a tubular string for performing a service operation in a wellbore comprises a mandrel with a flowbore in fluid communication with the tubular string, an upper sealing device, a lower sealing device, a selectively operable valve that enables or prevents fluid communication between the flowbore and the wellbore, and a selectively closeable bypass flow path.

Description:
CROSS-REFERENCE TO RELATED APPLICATIONS 
   None. 
   STATEMENT REGARDING FEDERALLY SPONSORED RESEARCH OR DEVELOPMENT 
   Not applicable. 
   REFERENCE TO A MICROFICHE APPENDIX 
   Not applicable. 
   FIELD OF THE INVENTION 
   The present invention relates to wellbore straddle-packer assemblies and methods of wellbore servicing with a pressurized fluid. More particularly, the present invention relates to a wellbore straddle-packer comprising a fluid saver assembly which, upon completion of the service operation, can be moved without venting pressurized fluid to the surface or waiting for the pressurized formation to bleed down. 
   BACKGROUND 
   As conventional sources of natural gas in North America decline while demand for this energy resource continues to grow, coal bed methane (CBM) has been identified as a viable alternative energy source. CBM is aggressively being extracted from multi-zone wellbore formations, and during production of these formations, downhole tools are used to deliver pressurized fluid to stimulate CBM production. In particular, the tool is set within the wellbore to isolate a formation zone, and pressurized nitrogen, or another type of fracturing fluid, is pumped through the tool into the isolated formation zone. The pressurized fluid acts to open or expand “cleats” within the coal seam, thus forming a communication channel through which the CBM can flow into the cased wellbore and then up to the surface. 
   Fracturing multi-zone CBM wellbore formations is often performed using downhole cup-style straddle-packers. Typically, pressurized nitrogen is pumped through a work string, such as coiled tubing, once these cup-style straddle-packers are set at a particular location within the wellbore. After fracturing a zone, it may be necessary to allow the pressurized formation to bleed down from the applied treatment pressure in order to unseat the cups and allow movement of the straddle-packer to the next zone to be fractured. The time required for this bleed down to occur may be 20 minutes, for example. Because many CBM wellbores have multiple zones to fracture, such as 15 to 20 zones, the total time waiting for formation bleed down to occur can be significant and increases the cost of fracturing the wellbore. As an alternative to waiting for the formation to bleed down, the pressurized fluid contained in the work string may be vented to the surface. This, however, wastes volumes of pressurized fluid that could otherwise be usefully injected into the CBM formations, thereby also increasing the cost of fracturing. 
   Besides the costs associated with venting pressurized fluid, and the time delays associated with waiting to move conventional straddle-packers, the cup-style sealing elements also have operational limits. As the demand for natural gas continues to rise, it has become necessary to drill deeper wellbores, and therefore, fracture formation zones at greater depths. As wellbore depths increase, cup-style sealing elements reach their operational pressure limits and no longer work reliably. Furthermore, the rubber material of the cups is incompatible with acids and other chemicals that may be contained in some wellbore servicing fluids. Even assuming the rubber cups are suitable for use operationally, venting of a pressurized fluid containing acids or chemicals to the surface may be prohibited due to environmental regulations. Where no such prohibition exists, repeated venting of a pressurized fluid containing acid or chemicals is still undesirable, as such venting can be expensive. 
   Therefore, due to the time and the increased operational cost associated with moving and re-seating typical cup-style straddle-packers during fracturing of multi-zone CBM well formations, the costs associated with venting pressurized fluid to the surface, the inability of cup-style sealing elements to function reliably at greater wellbore depths, and the incompatibility of rubber cups with acids and other chemicals, a need exists for a downhole tool designed for such operations. Specifically, a need exists for a straddle-packer assembly that reduces the time between fracturing multiple zones, does not require venting of pressurized fluid to the surface, is operational at greater wellbore depths, and is compatible with fluids containing acids and other chemicals. 
   SUMMARY OF THE INVENTION 
   In one aspect, the present disclosure relates to a method for performing a service operation within a wellbore extending into a formation comprising: sealing a first length of the wellbore to define a first isolated formation zone, flowing a pressurized fluid through a tubular string into the first isolated formation zone, and unsealing the first length of the wellbore without venting the pressurized fluid from the tubular string or awaiting depressurization of the first isolated formation zone. The method may further comprise: containing the pressurized fluid within the tubular string, moving the tubular string within the wellbore, sealing a second length of the wellbore to define a second isolated formation zone, flowing a pressurized fluid through the tubular string into the second isolated formation zone, and/or equalizing pressure between the sealed first length and an unsealed portion of the wellbore. In an embodiment, the method is performed in a single trip into the wellbore. The service operation may comprise fracturing a coal bed methane formation, and the pressurized fluid may comprise nitrogen, water, acid, chemicals, or a combination thereof. 
   In another aspect, the present disclosure relates to a method for performing a service operation within a wellbore extending into a formation comprising: running an assembly comprising a valve into the wellbore on a tubular string, fixing the assembly within the wellbore to define a first isolated formation zone, flowing a pressurized fluid through the valve into the first isolated formation zone, and closing the valve to contain the pressurized fluid within the tubular string. The method may further comprise: moving the assembly without venting the pressurized fluid from the tubular string or awaiting depressurization of the first isolated formation zone, equalizing pressure across the assembly before moving the assembly, re-fixing the assembly within the wellbore to define a second isolated formation zone, opening the valve, and/or flowing the pressurized fluid through the valve into the second isolated formation zone. In an embodiment, fixing the assembly comprises activating an upper seal and a lower seal within the wellbore to straddle the first isolated formation zone. In another embodiment, fixing the assembly further comprises activating an upper anchor and a lower anchor within the wellbore to straddle the first isolated formation zone. The method may further comprise bypassing pressure around the upper anchor when running the assembly into the wellbore. 
   In yet another aspect, the present disclosure relates to a method for performing a service operation within a wellbore extending into a formation comprising: running an assembly into the wellbore on a tubular string, engaging a wellbore wall with the assembly, setting down on the tubular string to activate upper and lower seals of the assembly against the wellbore wall to define an isolated formation zone, additional setting down on the tubular string to open a valve of the assembly, flowing a pressurized fluid through the valve into the isolated formation zone, and picking up on the tubular string to close the valve and contain the pressurized fluid within the tubular string. The method may further comprise additional picking up on the tubular string to move the assembly without venting the pressurized fluid from the tubular string or awaiting depressurization of the isolated formation zone. In various embodiments, the additional picking up opens a bypass flow path, the setting down on the tubular string activates a lower anchor of the assembly against the wellbore wall, and/or the additional setting down on the tubular string activates an upper anchor of the assembly against the wellbore wall. 
   In still another aspect, the present disclosure relates to an assembly connected to a tubular string for performing a service operation in a wellbore, the assembly comprising: a mandrel with a flowbore in fluid communication with the tubular string, an upper sealing device, a lower sealing device, a selectively operable valve that enables or prevents fluid communication between the flowbore and the wellbore, and a selectively closeable bypass flow path. The tubular string may comprise coiled tubing, and at least one of the sealing devices may comprise a plurality of sealing elements. The assembly may further comprise a continuous J-slot, drag blocks, an upper anchor, and/or a lower anchor. The upper anchor may comprise a plurality of spring-loaded buttons activated by pressure when the bypass flow path is closed, and the lower anchor may comprise a slip and cone system. 

   
     BRIEF DESCRIPTION OF THE DRAWINGS 
     For a more detailed description of the present invention, reference will now be made to the accompanying drawings, wherein: 
       FIG. 1  provides a schematic side view, partially in cross-section, of a representative operational environment depicting a coiled tubing work string lowering one embodiment of a wellbore fluid saver assembly into a cased wellbore; 
       FIG. 2  provides a schematic side view of a wellbore fluid saver assembly located at a desired depth within the cased wellbore, with its upper and lower sealing elements set above and below a production zone, respectively; 
       FIGS. 3A through 3H , when viewed sequentially from end-to-end, provide a cross-sectional side view from top to bottom of one embodiment of a wellbore fluid saver assembly; 
       FIGS. 4A through 4F , when viewed sequentially from end-to-end, provide a cross-sectional side view of the wellbore fluid saver assembly of  FIG. 3  in a run-in configuration; 
       FIGS. 5A through 5F , when viewed sequentially from end-to-end, provide a cross-sectional side view of the wellbore fluid saver assembly positioned at a desired depth in the wellbore and ready to set; 
       FIGS. 6A through 6F , when viewed sequentially from end-to-end, provide a cross-sectional side view of the wellbore fluid saver assembly anchored within the wellbore, a bypass flow path open, upper and lower sealing elements set, and a valve partially open; 
       FIGS. 7A through 7F , when viewed sequentially from end-to-end, provide a cross-sectional side view of the wellbore fluid saver assembly with the valve fully opened during fracturing; 
       FIGS. 8A through 8F , when viewed sequentially from end-to-end, provide a cross-sectional side view of the wellbore fluid saver assembly after fracturing is complete and the assembly has been picked up to be moved to the next formation zone; and 
       FIG. 9  provides a schematic cross-sectional side view of a J-slot and an interacting lug that form part of the wellbore fluid saver assembly. 
   

   NOTATION AND NOMENCLATURE 
   Certain terms are used throughout the following description and claims to refer to particular assembly components. This document does not intend to distinguish between components that differ in name but not function. In the following discussion and in the claims, the terms “including” and “comprising” are used in an open-ended fashion, and thus should be interpreted to mean “including, but not limited to . . . ”. 
   As used herein, the term “tool” refers to the entire wellbore fluid saver assembly. 
   Reference to up or down will be made for purposes of description with “up”, “upper”, or “upstream” meaning toward the earth&#39;s surface or toward the entrance of a wellbore; and “down”, “lower”, or “downstream” meaning toward the bottom or terminal end of a wellbore. 
   In the drawings, the cross-sectional side views of the wellbore fluid saver assembly should be viewed from top to bottom, with the upstream end toward the top and the downstream end toward the bottom of the drawing. 
   DETAILED DESCRIPTION 
   A single embodiment of a wellbore fluid saver assembly, also referred to herein as “tool”, and its method of operation will now be described with reference to the accompanying drawings, wherein like reference numerals are used for like features throughout the several views. There is shown in the drawings, and herein will be described in detail, a specific embodiment of the tool that connects to a coiled tubing work string to inject high pressure fluid, such as nitrogen, into a formation for fracturing. It should be understood that this disclosure is representative only and is not intended to limit the wellbore fluid saver assembly to use with a coiled tubing work string, to nitrogen as the pressurized fluid, or to fracturing as the only wellbore service operation, as illustrated and described herein. One skilled in the art will readily appreciate that the wellbore fluid saver assembly disclosed herein may be connected to any type of work string for wellbore servicing in general, and not only for fracturing. Furthermore, one skilled in the art will understand that other wellbore servicing liquids and gases could be used instead of nitrogen, such as, for example, water, acid, chemicals, or a combination thereof. 
     FIG. 1  and  FIG. 2  depict one representative wellbore servicing environment for the wellbore fluid saver assembly  200 .  FIG. 1  depicts a coiled tubing system  100  on the surface  170  and one embodiment of a wellbore fluid saver assembly  200  being lowered on coiled tubing  150  into a wellbore  160  extending into a surrounding formation F. The coiled tubing system  100  may include a power supply  110 , a surface processor  120 , and a coiled tubing spool  130 . An injector head unit  140  feeds and directs the coiled tubing  150  from the spool  130  into the wellbore  160 . 
     FIG. 2  depicts the wellbore fluid saver assembly  200  of  FIG. 1  after it has been lowered to a desired depth and positioned in the wellbore  160 . Specifically, upper sealing elements  17  and lower sealing elements  61 , as well as anchoring upper buttons  9  and anchoring lower slips  45 , are shown set against a casing  165  lining the wellbore  160 . As set in this position, the tool  200  straddles a production zone “A” of interest, which has previously been perforated  300  through the casing  165  and cement  167  into the surrounding formation F. The upper sealing elements  17  and the lower sealing elements  61  of the tool  200  seal against the casing  165  to isolate the production zone A prior to fracturing. 
   Referring now to  FIGS. 3A through 3H , these cross-sectional side views depict the individual components of one embodiment of a wellbore fluid saver assembly  200 . In particular, when viewed from end to end,  FIGS. 3A through 3H  represent a cross-sectional side view of the tool  200  from top to bottom. The assembly  200  comprises three partially concentric tubular systems  210 ,  220 ,  230  that reciprocate axially with respect to one another, and a lug assembly  68  at its lower end. An inner tubular system  210  comprises a threaded coupling  1 , a top mandrel  2 , a ported mandrel  30 , and a lower collet  36  as depicted in  FIGS. 3A through 3F . The threaded coupling  1  includes a box end  11  for connecting to the coiled tubing  150  and threads into the upper end of the top mandrel  2 , which in turn threads into a lock ring  25  and the upper end of the ported mandrel  30  as shown in  FIG. 3D . An upper collet ring  26  surrounds the lower end of the top mandrel  2  and axially resides between the lock ring  25  and the ported mandrel  30 , which threads at its lower end into the lower collet  36  as shown in  FIG. 3E . The ported mandrel  30  comprises valving ports  60 , bypass ports  66  and a flow blocking section  31  that terminates an inner flowbore  15  extending through the threaded coupling  1 , the top mandrel  2 , and the ported mandrel  30 . 
   A middle tubular system  220  surrounds the inner tubular system  210  and comprises a top sleeve cap  3 , a top sleeve  4 , a hold down body  8 , a seal element mandrel  23 , and an upper collet  28  as shown in  FIGS. 3A through 3D . The top sleeve cap  3  threads into the top sleeve  4 , which in turn threads onto the hold down body  8 . The lower end of the hold down body  8  threads into a first gauge ring  16  and onto the seal element mandrel  23 . The hold down body  8  includes a plurality of recesses within which are disposed piston buttons  9  biased to a retracted position by piston springs  10 . The opposite end of the seal element mandrel  23  is threaded into the upper collet  28  as shown in  FIG. 3D . The seal element mandrel  23  supports an upper set of sealing elements  17 , with each individual sealing element  17  separated by spacers  18 . The set of sealing elements  17  and spacers  18  reside axially between first and second gauge rings  16 ,  14  as shown in  FIGS. 3B and 3C . 
   Referring now to  FIGS. 3C through 3H , an outer tubular system  230  surrounds a portion of the middle tubular system  220  and a portion of the inner tubular system  210 . The outer tubular system  230  comprises a spring housing  20 , a sleeve cap  22 , a connecting sleeve  29 , a valve body  33 , a ported sub  34 , a lower collet housing  35 , a bottom nipple  41 , a lower packer top sub  42 , a lower packer mandrel  55  and a bottom sub  56 . The spring housing  20  threads into the second gauge ring  14 , and a Belleville spring  21  is positioned axially between the spring housing  20  and the upper end of the sleeve cap  22  as shown in  FIG. 3C . The lower end of the sleeve cap  22  threads into the connecting sleeve  29 , which in turn threads onto the upper end of the valve body  33  as shown in  FIGS. 3C and 3D . The lower end of the valve body  33  threads to the ported sub  34 , which in turn threads into the lower collet housing  35  as shown in  FIG. 3E . The lower end of the lower collet housing  35  threads onto the bottom nipple  41 , and a lower collet ring  37  is shown axially positioned between the bottom nipple  41  and a shoulder  32  on the inner surface of the lower collet housing  35  as shown in  FIG. 3F . A shear ring  38  receives a shear screw  39 , which extends through the bottom nipple  41  to lock the outer tubular system  230  with respect to the inner tubular system  210 . 
   As depicted in  FIGS. 3F and 3G , the bottom nipple  41  is provided with lower threads  46  to connect into a box end  48  of the lower packer top sub  42 . A third gauge ring  43  threads between the lower packer top sub  42  and the lower packer mandrel  55 . A fourth gauge ring  51  threads onto a cone  44  that is used to activate one or more slips  45 . A lower set of sealing elements  61  resides between the third gauge ring  43  and the fourth gauge ring  51  with element spacers  18  provided between each of the individual sealing elements  61 . A continuous J-slot  62  is formed into the outer surface of the lower packer mandrel  55  as shown in  FIG. 3G . The lower end of the lower packer mandrel  55  threads into the bottom sub  56  as shown in  FIG. 3H . The wellbore fluid saver assembly  200  also comprises a plurality of O-rings  6  for sealing between components of the tubular systems  210 ,  220 ,  230 , as well as a plurality of set screws  7  for locking the various components of the tubular systems  210 ,  220 ,  230  together as depicted in  FIG. 3A through 3H . 
   Referring again to  FIG. 3H , the lug assembly  68  comprises a slip cage  47 , a lug ring  49  and a drag block body  54  containing a drag block  52  and a spring  53 . The lug assembly  68  is disposed about the lower packer mandrel  55  and connects to the J-slot  62  by a lug  50  extending from the lug ring  49 . The drag block body  54  threads into the slip cage  47 , and the slips  45  extend upwardly from the slip cage  47  for interaction with the cone  44 . The drag block  52  is attached to the drag block body  54  and biased radially outwardly by a drag block leaf spring  53  that is located in a cavity between the drag block body  54  and the drag block  52 . The lug ring  49  and the lug  50  reside in recesses along the inner surface of the drag block body  54 , with the lug  50  extending to engage the continuous J-slot  62 . The interaction between the lug  50  and the continuous J-slot in various configurations of the tool  200  is also depicted in  FIG. 9  and will be discussed in more detail herein. 
   Referring again to  FIGS. 3B through 3E , the wellbore fluid saver assembly  200  also comprises a number of ports that provide various flow paths through the assembly  200 . As shown in  FIG. 3E , the ported mandrel  30  comprises inner valving ports  60  and the ported sub  34  comprises outer valving ports  63 . As such, the ported mandrel  30  and ported sub  35  comprise a valve  67  that is open when the inner valving ports  60  and the outer valving ports  63  are at least partially aligned, and that is closed when these ports  60 ,  63  are totally out of alignment. Accordingly, when the valving ports  60 ,  63  are aligned, they allow communication of pressurized nitrogen  180  from the flowbore  15  to the surrounding wellbore  160 . 
   The ported mandrel  30  also includes bypass ports  66  that interact with the outer valving port  63  when the valve  67  is closed to allow fluid communication along a lower bypass flow path  12  between a lower flowbore  24  and the wellbore  160 . Referring to  FIGS. 3B through 3D , an upper bypass flow path  69  is provided in a gap between the inner tubular system  210  and the middle tubular system  220 , and this upper bypass flow path  69  is defined by bypass ports  70 ,  71 , and  72  that are located in the top sleeve  4 , the upper collet  28 , and the connecting sleeve  29 , respectively. Like the lower bypass flow path  12 , the upper bypass flow path  69  is also open when the valve  67  is closed. 
   As shown in  FIGS. 3B and 3E , in addition to the components introduced above, there are also three molded seals  5 ,  64 ,  65  that are important for directing the flow of pressurized nitrogen  180  through the bypass flow paths  12 ,  69 , or through the valve  67 , or both. The upper molded seal  5  is located near the interface between the top sleeve  4  and the hold down body  8  as shown in  FIG. 3B . When the upper bypass flow path  69  is open, namely, when flow is permitted through ports  72 ,  71  and  70 , the upper molded seal  5  prevents such flow from actuating the piston buttons  9 . The central molded seal  64  is located between the valve body  33  and the ported sub  34 , and the lower molded seal  65  is located near the interface between the ported sub  34  and the lower collet housing  35  as shown in  FIG. 3E . Both of these molded seals  64 ,  65  prevent the loss of pressurized nitrogen  180  from the valve  67  when the valve  67  is open and the bypass flow paths  12 ,  69  are closed. 
   The wellbore fluid saver assembly  200  assumes various operational configurations during fracturing of the formation F surrounding the wellbore  160 , which include not only the actual fracturing process, but also run-in and movement of the tool  200  from one production zone to the next. The remaining figures illustrate the sequential operational configurations of the wellbore fluid saver assembly  200  during wellbore fracturing. In general, as will be described in more detail herein,  FIGS. 4A through 4F  depict the wellbore fluid saver assembly  200  as configured during run-in;  FIGS. 5A through 5F  depict the assembly  200  located adjacent to the production zone of interest and ready to set;  FIGS. 6A through 6F  show the tool  200  anchored, the upper and lower sets of sealing elements  17 ,  61  set, and the valve  67  partially open to allow communication of the pressurized fluid  180  between the flowbore  15  and the surrounding wellbore  160 ;  FIGS. 7A through 7F  depict the valve  67  fully open, as it will be during the fracturing operation; and  FIGS. 8A through 8F  depict the valve  67  closed after completion of the fracturing operation with the tool  200  being moved by the coiled tubing  150  to the next production zone or being removed from the wellbore  160 . 
   Referring now to  FIGS. 4A through 4F , the tool  200  is shown in its run-in configuration, i.e. the configuration of the tool  200  as it is lowered or “run-in” to the wellbore  160  to a desired depth adjacent to a production zone A shown in  FIG. 4D . During run-in, the operator may elect to begin pumping pressurized nitrogen  180  to fill the coiled tubing  150 . Valve  67  is closed, because the inner valving ports  60  and outer valving ports  63  are totally out of alignment, and the flow blocking section  31  is blocking flow of the nitrogen  180  through outer valving ports  63  as shown in  FIG. 4D . Thus, the pressurized nitrogen  180  being pumped into the coiled tubing  150  at the surface  170  is contained within the coiled tubing  150  and prevented from communicating with the surrounding formation F. As the assembly  200  is run-in, the drag blocks  52  shown in  FIG. 4F  are in continuous contact with the casing  165 , providing a centralizing effect as the tool  200  is lowered into the wellbore  160 . 
   As shown in  FIGS. 4B through 4D , during run-in the bypass flow paths  12 ,  69  are open, as indicated by the position of bypass ports  66 ,  70 ,  71  and  72  relative to the upper, middle, and lower molded seals  5 ,  64  and  65 . As the wellbore fluid saver assembly  200  is run-in, a differential pressure distribution develops along the length of the tool  200 . The faster the speed of run-in, the higher the differential pressure along the tool  200 . If this pressure differential is high enough, the fluid pressure can compress or set the upper set of sealing elements  17  and the lower set of sealing elements  61 . Therefore, to equalize the pressure distribution along the tool  200 , and thereby prevent compression of the upper set of sealing elements  17  and the lower set of sealing elements  61 , wellbore fluid bypasses both sets of elements  17 ,  61 . Specifically, as shown in  FIGS. 4C and 4D , the wellbore fluid flows upwardly through a lower flowbore  24  in the tool  200  that is blocked at its upper end by the flow blocking section  31  in the ported mandrel  30 , and then through the bypass ports  66  into the lower bypass flow path  12  and out into the wellbore  160  through outer valving ports  63 . Simultaneously, as shown in  FIGS. 4A through 4C , the wellbore fluid is routed along the upper bypass flow path  69  by flowing into ports  72 , through ports  71 , and out of ports  70  into the wellbore  160 . This bypass flow does not actuate the piston buttons  9  due to the position of the upper molded seal  5 , which prevents the piston buttons  9  from being exposed to internal pressure. The piston buttons  9  are pressure-actuated to extend outwardly and act as a locking device near the upper set of sealing elements  17 . During run-in, it is desirable to avoid locking the tool  200  in this manner. 
   Referring to  FIGS. 4D through 4F , also during run-in, it is desirable to avoid inadvertent anchoring of the tool  200  near the lower set of sealing elements  61 . The cone  44  and the slips  45 , when engaged, anchor the tool  200  against the casing  165 . Therefore, to prevent the cone  44  from inadvertently engaging the slips  45 , a shear ring  38  and shear screw  39  shown in  FIG. 4D  are provided to lock the lower collet  36  to the bottom nipple  41  such that these components do not move relative to each other during run-in. The force exerted on the coiled tubing  150  during run-in is insufficient to sever the shear screw  39 . As long as the shear screw  39  engages the shear ring  38 , the cone  44  is prevented from moving relative to and sliding under the slips  45 . The shear ring  38  and shear screw  39  also prevent excessive wear on the lower collet  36 , which would otherwise bear the load carried by the shear ring  38 . Referring to  FIG. 4F , the interaction between the continuous J-slot  62  and the lug  50  similarly prevents the lug assembly  68  from pushing the slips  45  upward relative to the cone  44  and engaging the cone  44 . As shown in  FIG. 9 , lug  50  is located in slot  80  during run-in. This slot  80  is a shorter slot designed to prevent the lug assembly  68  from pushing the slips  45  upward relative to the cone  44  and engaging the cone  44 . Due to the position of the lug  50  within slot  80 , the lug assembly  68  is dragged along the casing  165  as the coiled tubing  150  lowers the wellbore fluid saver assembly  200  downhole. 
   After run-in is complete and the tool  200  has reached a desired depth adjacent to a production zone A, the operator prepares the tool  200  to set.  FIGS. 5A through 5F  show the tool  200  in its ready to set configuration. To move the tool  200  from the run-in configuration of  FIGS. 4A through 4F  to the ready to set configuration, the operator simply picks up the coiled tubing  150 , and therefore the attached tool  200 . During this lifting process, the shear screw  39  and shear ring  38  remain intact as shown in  FIG. 5D , the valve  67  remains closed as shown in  FIG. 5C , thus keeping nitrogen  180  contained within the coiled tubing  150 , and the bypass flow paths  12 ,  69  remain open. As shown in  FIG. 5F , when the tool  200  is picked up, the resistance provided by the drag blocks  52  at the casing  165  allow the coiled tubing  150 , the inner tubular system  210 , the middle tubular system  220 , and the outer tubular system  230  to travel upwards relative to the stationary lug assembly  68  until the bottom sub  56  contacts the lower end of the drag block body  54 . Simultaneously, as represented in  FIG. 9 , the continuous J-slot  62  slides from an initial position at the top of slot  80  downwardly along lug  50  until the lug  50  contacts angled channel  84  of the continuous J-slot  62 , thereby causing the lug ring  49  to rotate. The rotation of the lug ring  49  shifts lug  50  downwardly into the adjacent slot  81  along the continuous J-slot  62  to prepare for the next operational step of the tool  200 , which is to set and anchor. 
     FIGS. 6A through 6F  show the tool  200  in its set and anchored position. To move the tool  200  from the ready to set configuration of  FIGS. 5A through 5F  to the set and anchored position, the operator slacks off weight, meaning a downward force is applied to the coiled tubing  150 . Referring again to  FIG. 9 , with the lug  50  in slot  81  at the onset of slack off, the downward force on the tool  200  causes slot  81  of the continuous J-slot  62  to slide along lug  50  until the lug  50  contacts angled channel  85  of the J-slot  62 , thereby causing the lug ring  49  to rotate and the lug  50  to shift from slot  81  to adjacent slot  82 . Referring again to  FIGS. 6A through 6F , as slack off continues, the cone  44  engages the slips  45  to extend the slips  45  outwardly into engagement with the casing  165  as shown in  FIG. 6F , thus anchoring the tool  200  near the lower set of sealing elements  61 . 
   Further slack off compresses the upper set of sealing elements  17  as shown in  FIG. 6B  and the lower set of sealing elements  61  as shown in  FIG. 6E , severs the shear screw  39  so that it no longer engages the shear ring  38  as shown in  FIGS. 6D and 6E , and causes the lower collet  36  to overcome the lower collet ring  37  as shown in  FIG. 6D . Referring to  FIG. 6D , the lower molded seal  65  is positioned to block the lower bypass flow path  12  such that flow is no longer permitted to bypass the lower set of sealing elements  61  by flowing through the bypass ports  66  outwardly through the outer valving ports  63  into the wellbore  160 . Also, as shown in  FIG. 6B , due to the position of the upper molded seal  5  relative to bypass ports  70  in the top sleeve  4 , flow is no longer permitted to travel along the upper bypass flow path  69  to bypass the upper set of sealing elements  17  and the piston buttons  9 . As shown in  FIG. 6D , the valve  67  is partially open because the inner valving ports  60  and outer valving ports  63  are partially aligned, so high pressure nitrogen  180  therefore flows from the coiled tubing  150  through the flowbore  15  and outwardly through the valve  67 . This pressure activates the piston buttons  9 , which “grip” the casing  165 , thus locking the tool  200  against the casing  165  near the upper set of sealing elements  17  as shown in  FIG. 6B . Thus, in summary,  FIGS. 6A through 6F  show the tool  200  anchored by slips  45  and piston buttons  9  and sealed against the casing  165  by the upper set of sealing elements  17  and the lower set of sealing elements  61 , with the bypass flow paths  12 ,  69  closed, and the valve  67  partially open. In this configuration, the tool  200  has isolated production zone A. An extension  90  may be required in the assembly  200  to provide the proper spacing between the upper set of sealing elements  17  and the lower set of sealing elements  61 , depending upon the length of the production zone A to be isolated. 
   Next, valve  67  will be fully opened and the fracturing operation performed.  FIGS. 7A through 7F  show the tool  200  with the valve  67  fully open as depicted in  FIG. 7D , as the valve  67  would be during fracturing. To fully open the valve  67  by completely aligning the inner valving ports  60  and the outer valving ports  63 , additional set down weight is applied. The approximate amount of weight equals the amount of force required to cause the upper collet ring  26  to overcome the upper collet  28  as shown in  FIG. 7C . This amount of force is applied to the coiled tubing  150 . Once the upper collet ring  26  overcomes the upper collet  28 , valve  67  is near its fully open position. Slack off continues as the operator monitors the nitrogen pressure within the coiled tubing  150  for a pressure spike that indicates valve  67  is fully open. Once that pressure spike is observed, the operator ceases to slack off. During this slacking off process, the lug assembly  68 , the middle tubular system  220  and the outer tubular system  230  of the tool  200  remain stationary while the inner tubular system  210  moves downwardly until extensions  75  on the ported mandrel  30  engage a shoulder  76  on the top sleeve  4  as shown in  FIG. 7B . 
   With the valve  67  fully open, fracturing can take place. During fracturing, the upper set of sealing elements  17  may tend to slip downwardly, causing some loss of sealing capacity and nitrogen pressure. To prevent such slippage from occurring, the Belleville springs  21  are provided to exert an additional force on the upper set of sealing elements  17 , thereby holding them in place against the casing  165  as shown in  FIG. 7B . 
   Once fracturing is complete, the tool  200  can be moved to the next production zone or removed from the wellbore  160 . Before moving the tool  200 , it must be unlocked. Unlike existing downhole cup-style straddle-packers where the nitrogen pressure must be vented or the formation pressure must be bled down until the cups relax, there is no such requirement to unlock the wellbore fluid saver assembly  200 . Instead, an open lower bypass flow path  12  via bypass ports  66  in the ported mandrel  30  communicating with outer valving ports  63 , and an open upper bypass flow path  69  via the bypass ports  70 ,  71 ,  72 , provide pressure equalization across the tool  200  while the valve  67  is closed to contain the nitrogen  180  within the tool  200  and coiled tubing  150 . 
     FIGS. 8A through 8F  depict the tool  200  when it has been unlocked and it is being moved. To achieve this unlocked configuration, the operator simply picks up on the coiled tubing  150  and the attached tool  200 . By picking up the tool  200 , the inner tubular system  210  moves up until the extensions  75  on ported mandrel  30  engage a shoulder  77  on the top sleeve cap  3  as shown in  FIG. 8A  to pull the middle tubular system  220  upwardly. Thus, the load on the upper set of sealing elements  17  is removed, allowing these sealing elements  17  to relax or un-set. Continued tension on the coiled tubing  150  causes the upper collet ring  26  to travel upwards until it passes over the upper collet  28  as shown in  FIG. 8B . Due to this relative movement, the inner valving ports  60  and the outer valving ports  63  are no longer aligned, thereby closing valve  67  as shown in  FIG. 8C . At the same time, the lower bypass flow path  12  is opened due to the position of the bypass ports  66  in the ported mandrel  30  relative to the lower molded seal  65 . Because valve  67  is now closed, high pressure nitrogen  180  is contained within the coiled tubing  150  and the tool  200  and no longer applies a pressure load to the piston buttons  9 . Hence, the piston buttons  9  are retracted by the biasing piston spring  10  as shown in  FIG. 8A . Continued tension to the coiled tubing  150  causes the lower collet  36  to pass over the lower collet ring  37  as shown in  FIG. 8C , similar to what has already transpired with the upper collet  28 . The lower set of sealing elements  61  then relax or un-set as shown in  FIG. 8E . Referring now to  FIG. 9 , the continuous J-slot  62  slides along lug  50  as lug  50  shifts from slot  82  to slot  83 . J-slot  62  continues to travel upwards relative to lug  50  until lug  50  reaches the end of slot  83  and no further movement of J-slot  62  relative to the lug assembly  68  is permitted. Finally, as shown in  FIGS. 8E and 8F , the cone  44  disengages from the slips  45 . This relative movement is possible, again, because the drag block  52  continuously engages the casing  165  to provide resistance to the tension load on the coiled tubing  150 . 
   The tool  200  is now ready to be moved. Valve  67  is closed, the upper set of sealing elements  17  and the lower set of sealing elements  61  are unset, the tool  200  is unanchored at both ends, and the bypass flow paths  12 ,  69  are open. After the tool  200  is moved to the next frac zone, such as production zone “B” shown in  FIG. 2 , for example, the entire operational sequence is repeated. Specifically, the tool  200  is moved to the ready to set configuration, if not already in this configuration, as shown in  FIGS. 5A through 5F . Then the tool  200  is anchored, the upper set of sealing elements  17  and lower set of sealing elements  61  are set, and the valve  67  is partially opened, as depicted in  FIGS. 6A through 6F , and so on. In this manner, multiple production zones may be fractured during a single trip downhole. Furthermore, fracturing of the wellbore  160  is completed in a minimal amount of time and with minimal waste of pressurized nitrogen  180 . 
   The foregoing description of the wellbore fluid saver assembly  200  which, upon completion of a wellbore service operation can be moved without venting nitrogen  180  to the surface  170  or waiting for the formation F to bleed down, has been presented for purposes of illustration and description and is not intended to be exhaustive or to limit the invention to the precise form disclosed. Obviously many other modifications and variations of the wellbore fluid saver assembly  200  are possible. In particular, another frac fluid could be used, instead of nitrogen. For example, frac fluids used in acidizing are compatible with this tool. Also, the sealing elements  17 ,  61  may be replaced with other types of sealing devices. A different number or combination of components may be employed, and other variations are possible. 
   While a single embodiment of the wellbore fluid saver assembly  200  has been shown and described herein, modifications may be made by one skilled in the art without departing from the spirit and the teachings of the invention. The embodiment described is representative only, and are not intended to be limiting. Many variations, combinations, and modifications of the application disclosed herein are possible and are within the scope of the invention. Accordingly, the scope of protection is not limited by the description set out above, but is defined by the claims which follow, that scope including all equivalents of the subject matter of the claims.