Patent Abstract:
The apparatus consists of a tubular housing carried into the well on a workstring. A series of spaced isolation modules is provided for each zone and carried into the well on a tubular conduit. The first, or most downstream module includes first and second sealing mechanisms to isolate the first zone to be treated. A full bore valve is provided that is activated to closed position by an activating component in response to a source of a first level of pressure to isolate the first zone from other parts of the well bore. A port within the housing is initially blocked but selectively opened concurrently with the activation of the first sealing means to manipulate the second sealing mechanism to fully isolate the selected zone and the module. As the module is activated, a second full bore valve is activated to seal the interior of the housing upstream of the first module by manipulation of the tubular string.

Full Description:
CROSS-REFERENCE TO RELATED APPLICATION AND CLAIM OF PRIORITY 
       [0001]    This is a utility application claiming priority from U.S. provisional patent application No. 61/305,621, filed Feb. 18, 2010, entitled “Method and Apparatus For Single-Trip Wellbore Treatment”, Gregg W. Stout, inventor. 
     
    
     BACKGROUND OF THE INVENTION 
       [0002]    1. Field of the Invention 
         [0003]    The present invention relates to apparatus and methods for oil and gas wells to enhance the production of subterranean wells, either open hole or cased hole, and more particularly to improved multizone stimulation systems. 
         [0004]    2. Brief Description of the Prior Art 
         [0005]    Wells are drilled to a depth in order to intersect a series of formations or zones in order to produce hydrocarbons from beneath the earth. The drilled wells are cased and cemented to a planned depth and then may cased and cemented or a portion left open hole. Producing formations intersected with the well bore in order to create a flow path to the surface. Stimulation processes, such as fracing or acidizing or other chemicals or proppants, are used to increase the flow of hydrocarbons through the formations. The formations may have reduced permeability due to mud and drilling damage or other formation characteristics. In order to increase the flow of hydrocarbons through the formations, it is desirable to treat the formations to increase flow area and permeability. This is done most effectively by setting either open-hole packers or cased-hole packers at intervals along the length of the wellbore. These packers isolate sections of the formations so that each section can be better treated for productivity. Between the packers is a frac port and in some cases a sliding sleeve or a gravel pack screen with sliding sleeves. In order to direct a treatment fluid through a frac port and into the formation, a seat may be placed either on top of a sliding sleeve or below a frac port. A ball or plug may be dropped to land on the seat in order to direct fluid through the frac port and into the formation. 
         [0006]    One method places a series of ball seats below the frac ports with each seat size accepting a different ball size. Smaller diameter seats are at the bottom of the completion and the seat size increases for each zone as you go up the well. For each seat size there is a ball size so the smallest ball is dropped first to clear all the larger seats until it reaches the appropriate seat. In cases where many zones are being treated, maybe as many as 20 zones, the seat diameters have to be very close. The balls that are dropped have less surface area to land on as the number of zones increase. With less seat surface to land on, the amount of pressure you can put on the ball, especially at elevated temperature, becomes less and less. This means you can&#39;t get adequate pressure to frac the zone or the ball is so weak, the ball blows through the seat. Furthermore, the small ball seats reduce the I.D. of the production flow path which creates numerous other problems. The small I.D. prevents re-entry of other downhole devices, i.e., plugs, running and pulling tools, shifting tools for sliding sleeves, perforating gun size (smaller guns, less penetration), and of course production rates. In order to remove the seats, a milling run is needed to mill out all the seats and any balls that remain in the well. 
         [0007]    The size of the ball seats and related balls limits the number of zones that can be treated in a single trip. It would be advantageous to replace the use of the ball seats with a workstring actuated isolation device, such as a flapper or rotating ball, to allow the treatment of an unlimited number of zones in a single trip. 
         [0008]    Another method is that disclosed in U.S. Pat. No. 7,543,634 B2. This method places sleeves in the I.D. of the tubing string. These sleeves cover the frac ports and packers are placed above and below the frac ports. Varying sizes of balls or plugs are dropped on top of the sleeves and when pressing down the tubing, the pressure acts on the ball and the ball forces the sleeve downward. Once again you have the restriction of the ball seats and theoretically, and most likely in practice, when the ball shifts the sleeve downward, the frac port opens and allows the force due to pressure diminish off before the sleeve is fully opened. If the ball and sleeve remain in the flow path, the flow path is restricted for the frac operation. 
         [0009]    It would be advantageous to have a system that had no ball seats that restrict the I.D. of the tubing and to eliminate the need to spend the time and expense of milling out the ball seats, not to mention the debris created by the milling operation. Also it would be beneficial to have a system that fully opens the sliding sleeve before sleeve activating pressure bleeds down, to assure the sleeve is fully opened before treating the formation. 
         [0010]    Furthermore, it would be greatly advantageous to eliminate the time and logistics required for dropping numerous balls into the well, one at a time, for each zone in the well to be treated. 
         [0011]    In some well completions the operator may want to perforate below the packer. If the completion has small I.D. ball seats, the maximum O.D. of the perforating guns must drift through the ball seats. Small I.D. ball seats mean small O.D. perforating guns. It is well known in the industry that the smaller the O.D. of the perforating gun, the less the penetrating performance of the gun. It would be very advantageous to be able to run the largest O.D. gun possible inside of the tubing to achieve the greatest penetration through the tubing and casing walls to get the deepest penetration into the formation. 
         [0012]    Some zones in the formation are very close together or water is nearby. Fracturing programs sometimes want to limit the length of the zone to be treated so isolation packers with sliding sleeves need to be set very close together. To achieve this it would be beneficial to have a short compact packer-sliding sleeve assembly where several assemblies could be stacked closely together. One of the advantages of the present invention is to integrate to components of the packer and sliding sleeve to produce a reduced overall length apparatus to address the completion of closely positioned zones. 
       SUMMARY OF THE INVENTION 
       [0013]    A single trip multizone well treating method and apparatus provides a means to progressively stimulate individual zones through a cased or open hole well bore. The need to drop and mill balls and seats for each zone or run hydraulic control lines from the surface to actuate a series of isolation devices has been eliminated. Also, the I.D. restriction created by balls and seats has been eliminated to provide a full bore completion. The full bore completion allows use of larger perforating guns when thru-tubing perforating is desired. A unique feature of this system is that the operator can progressively treat each zone up the hole by moving the workstring up and down a short distance to release a flapper valve selectively for each zone. Applied pressure to the flapper both opens a sliding sleeve and sets a packer and then shifts the flapper below the frac port so a pumping treatment can commence. The apparatus is presented as a “Frac Module” that consists of three major components, a packer, a sliding sleeve, and a workstring actuated fluid isolation device which are integrated together in an assembly that would be shorter in length for closely placed zones. One Frac Module is used per zone and the frac module is stacked with tubing spacers through all zones that need treatment and zonal isolation. 
         [0014]    Stated a slightly different way, the invention provides a full bore, single trip multizone subterranean well treating apparatus. The apparatus is carried into the well on a tubular workstring, which may also be later used as the production tubing. A tubular housing is defined on the workstring and includes a central first fluid passageway therethrough. A plurality of treatment modules are provided on the housing, each module being pre-determinedly spaced on the housing for operable alignment with a zone in the well. Each module includes a tubular housing member with a treatment fluid port therein and a control chamber selectively communicable with the port. First and second spaced sealing mechanisms, such as packers, are provided to isolate the selected zone from other portions of the well. A first full bore valving mechanism is initially positioned in the housing in open position and is selectively activatable to closed position to block fluid under pressure from being transmitted within the tubular housing and across the valving member. Activation means are provided for the first valving means and responsive to a first level of pressure applied through the workstring to open the port and place a chamber in fluid communication with a fluid passageway within the housing. Pressure within the housing member above the first level further activates the a first sealing means, or packer, to set position. A second fluid flow passageway in the housing includes a blocked port opening to the interior of the housing, and the port is opened during activation of the first sealing means, or packer. A second activation means, such as a sleeve, is responsive to a pressure level in said tubing in excess of that required to set the second sealing means and to open a treatment port. In each of the modules upstream of the module used to isolate the first zone to be treated, there is provided a full bore valve in initial open position but shiftable to closed position by mechanical manipulation of the workstring to block fluid flow across the valve. 
         [0015]    This invention provides an improved multizone stimulation system to improve the conductivity of the well formations with reduced rig time and no milling. The equipment for all zones can be conveyed in single workstring trip and frac units can stay on location one time to treat all zones. 
         [0016]    In a preferred embodiment, work string weight is set down and pressure is applied to the lowermost isolation device, such as a flapper. The flapper is released and allowed to close. The flapper is mounted on a sleeve that is shear pinned. A low initial pressure shifts the flapper and sleeve downward to open a pressure port. Tubing pressure enters the port to shift the sliding sleeve downward to an open position to uncover the frac port and simultaneously begin setting a packer located immediately above the frac port. The setting motion within the packer opens a port to the tubing to allow tubing pressure to travel up a control line to the next upper zone to activate a flapper release mechanism, but the next upper flapper does not close at this point. Tubing pressure is increased to fully set the packer and the flapper/sleeve shears and shifts downward to a position below the frac port. In this position, the flapper/sleeve then rests on top of the sliding sleeve. With the frac port now fully open, the first zone is treated while the workstring remains in the set-down position. After the stimulation of the lower zone, the work string is picked up a short distance to release the flapper only in the next upper zone so the next upper zone can be treated. All upper zones are then progressively treated using the same process. A set-down and pickup type packer can be used above all of the frac Modules and above the uppermost set of perforations, assuming all zones were perforated initially. A production packer can be run in the string above the set-down packer, if desired, and be set after all zones are completed. Once the well is nippled-up the well can be put on production. If flapper valves are used, they will open and allow flow. It is also possible to make a trip into the well and break the frangible flapper discs. If sliding sleeves are used, shifting tools can be run in to open or close the sliding sleeves. 
     
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
         [0017]      FIGS. 1   a ,  1   b , and  1   c  placed end-to-end make up a schematic view of the present invention. 
           [0018]      FIG. 2  is a schematic view of three Frac Modules assembled in tandem in a well completion. 
           [0019]      FIG. 3  is a schematic view of three cased and perforated zones isolated with a completion string of tools. 
       
    
    
     DESCRIPTION OF THE PREFERRED EMBODIMENTS 
       [0020]    With reference to  FIG. 1   a , a schematic of the present invention shows a 90 degree lengthwise cross-section of the apparatus. This portion of the apparatus is the packer with only a packing element. A packer may be used that has a slip system added and a packer may be used that has a release devise added. Top sub  1  has a connecting thread at the top end  2 , an internal thread  3 , and o-ring seals  4  and  5 . Shear Screws  6  shearably connect Top Sub  1  to Shear Ring  7 . Shear Screws  8  shearably connect the Top Sub  1  to Push Sleeve  12 . The hole  9  communicates with hole  13 . A fitting  10  seals in hole  9  and also connects to hydraulic control line  11 . Hole  13  is located inside of Flow Body  14 . Seals  15 ,  16 ,  4 ,  5  seal between the Top Sub  1  and the Flow Body  14  to isolate flow paths  9  and  13  from pressure inside the tool  22  or outside the tool  23 . Port  20  has Seals  17  and  18  to seal off Port  20  with Push Sleeve  12 . Seals  18  and  19  with Push Sleeve  12  seal off port  21  to prevent pressure in tool  22  from entering port  20 . Seals  24  and  25  in Flow Body  14 , seal with Packer Mandrel  26 . 
         [0021]    Thread  27  attaches Flow Mandrel  14  to Packer Body  26 . Packing Element  28  rests on the Packer Mandrel  26  and between faces  30  and  31 . Gage Ring  29  is attached to Piston  32  with thread  37 . Piston  32  slides between Piston Housing  38  and Mandrel  26  and seals  33  and  34  act as piston seals. Body Lock Ring  35  threadably engages Piston Housing threads  44  so items  35  and  44  move together. Body Lock Ring  35  sets on smooth S surface  45  and at a later point in time engages Piston threads  46 . Screw  36  prevents rotation of Body Lock Ring  35  relative to Piston  32 . Connector  43  is attached to Mandrel  26  with thread  39  and seals  41  and  42  create a seal between items  25  and  43 . Hole  40  in Connector  43  communicates with Piston  32 . 
         [0022]    With reference to  FIG. 1   b , Connector  43  and hole  40  continue in the apparatus. Lower Pickup Sleeve  49  is attached to Connector  43  with thread  53  and seals  47  and  48  seal between the items  43  and  49 . Hole  40  communicates with chamber  54 . Release Sleeve  55  slides within Connector  43  and seal surface  52  seals at O-rings  50  and  51 . Upper Pickup Sleeve  56  slides inside of Lower Pickup Sleeve  49 . Surfaces  57  and  58  engage during pickup while surfaces at location  70  make contact during set-down. 
         [0023]    Dynamic Seals  59 ,  60 , and Static Seals  61 , and  62  seal on seal surface  63  of the Upper Pickup Sleeve  56 . Upper Pickup Sleeve  56  is connected to Housing  65  with threads  64 . 
         [0024]    Housing  65  attaches to Frac Port Housing  66  with thread connection  67  and seals  68  and  69  seal between items  65  and  66 . Seals  72  and  73  are positioned on Release Sleeve  55  and form a seal on Frac Port Housing  66  at seal surface  71 . Shear Ring  74  is shearably connected to Release Sleeve  55  with shear screws  75 . Shear Ring  74  is trapped in pocket  76  so Release Sleeve  55  can&#39;t move up or down. Shifting Profile  77  inside of Release Sleeve  55  engages a shifting tool (not shown) so that the shifting tool can engage the profile  77  and move the Release Sleeve  55  upward. 
         [0025]    The bottom of Release Sleeve  55  has a finger  78  attached. The finger  78  engages the Flapper  79  at location  84 . The Flapper  79  is affixed to Flapper Seat Sleeve  81  with axle  80  so the Flapper  79  is free to pivot around axle  80 . Flapper Seat Sleeve  81  is attached to Seat Housing  83  with shear pin  82 . Flapper Seat Sleeve  81  can slide downward into Seat Housing  83  until faces  84  and  85  come into contact. Seat Housing  83  is shear pinned to Frac Port Housing  66  with Shear Pins  86 . Seals  87 ,  88 ,  89 , and  90  are positioned in Barrel  91  and prevent pressure from moving from location  22  to location  23  or vice-versa. 
         [0026]    One or more Frac Ports  92  are located in Frac Port Housing  66 . The ports  92  go completely through the wall of the Frac Port Housing  66 . The Frac Port Housing has gun drilled hole  93  and  94  that do not intersect the Frac Ports  92  or Shear Screw hole  86 . Gun drilled hole  93  and  94  are isolated from each other by plug  95  and seals  96 ,  97 ,  98 ,  99 , and  102 . Port  100  communicates with gun drilled hole  93  and Port  101  communicates with gun drilled hole  94 , or vice-versa. 
         [0027]    Gun Drilled Hole  93  communicates with chamber  103  and acts on seals  104  and  105  located inside of Housing  65  and Release Sleeve  55 . Seals  104  and  105  are located on the I.D. and O.D. for Shift Piston  106 . Therefore, pressure in gun drilled hole  93  acts on Shift Piston  106  and is isolated from pressures  22  and  23 . 
         [0028]    Shift Piston  106  is shearably attached to Upper Pickup Sleeve  56  with shear pin  111 . Expanding Lock Dogs  107  and  109  are located in retaining slots on Shift Piston  106 . Lock Dog  107  is designed to engage in groove  108  inside of Lower Pickup Sleeve  49  and Lock Dog  109  is designed to engage in groove  110  on the O.D. of Release Sleeve  55 . Locking Keys  112  fit into slots  115  that are located in Upper Pickup Sleeve  56 . The Locking Keys  112  have teeth that expand into the I.D. thread profile  114  of Lower Pickup Sleeve  49 . Extended portion  113  of Shift Piston  106  slides under Locking Keys  112  in order to expand and engage the teeth into profile  114  thus locking the Lower Pickup Sleeve  49  to the Upper Pickup Sleeve  56  during the run-in configuration. 
         [0029]    With reference to  FIG. 1   c , note the continuation of gun drilled holes  93  and  94  in Frac Port housing  66 . In this figure, Gun Drilled Hole  93  communicates with control line  116  which attaches control line  117  which communicates with Shift Piston  106 . Control Line  117  becomes the same control line as Control Line  11  in  FIG. 1   a  so that Frac Modules in a lower zone can act on Shift Piston  106 . 
         [0030]    Gun Drilled Hole  94  communicates with chamber  118  and chamber  118  is adjacent to Sliding Sleeve Piston  121 . The Sliding Sleeve Piston  121  is positioned between Frac Port Housing  66  and Sliding Sleeve  124  and seals between the two with seals  119  and  120 . The Sliding Sleeve Piston  121  is shearably attached to Sliding Sleeve  124  with Shear Screws  122 . The Sliding Sleeve Piston  121  houses a Lock Ring  123  which engages shoulder  127 . Chamber  128  is below the Sliding Sleeve Piston  121  and communicates with ports  129  which communicate with pressure  23 . In summary, port  101  communicates with chamber  118  to communicate with Sliding Sleeve Piston  121  and the lower side of the Piston communicates with pressure  23 . 
         [0031]    Frac Port Housing  66  is connected to Sleeve Housing  130  with thread  131 . Bottom Sub  135  is connected to Sleeve Housing  130  with thread  132  and seals  133  and  134  create a seal between the two. The Bottom Sub  135  has pin thread  136  facing down. 
         [0032]    Sliding Sleeve  124  always isolates chamber  128  from pressure  22  with upper and lower seals  125  and  126 . The Sliding Sleeve  124  has collets  138  and  139  machined into the sleeve. These collets either engage in recess  144  or recess  143  to hold the Sliding Sleeve  124  in either the open or closed position. Anti-rotation Keys  137  slide in slot  130  and set in slots  145  located in the Sliding Sleeve  124 . Key  137  shoulder  141  engages Bottom Sub  135  shoulder  142  to limit downward movement of Sliding Sleeve  124  so that Collets  138  and  139  are not loaded in compression. Collets  138  and  139  engage a shifting tool, not shown, used to either shift the Sliding Sleeve  124  open or closed. 
         [0033]    With reference to  FIG. 2 , Frac Module  146  is comprised of the apparatus described in the combination of  FIGS. 1   a ,  1   b , and  1   c . This illustration shows three Frac Modules  146   a ,  146   b , and  146   c  placed around producing zones  147  and  148  and inside casing  149  with the casing surrounded by cement  150 . Perforations  151  and  152  are in communication with the Frac Port Windows  92  shown in  FIG. 1   b . Packing Elements  153  seal on the I.D. of casing  149  in order to isolate zones  147  and  148  from each other. Obviously, this can be done on many zones located in the well bore. Control lines  117  allow pressure communication from Frac Module  146   c  to Frac Module  146   b  and then from Frac Module  146   b  to Frac Module  146   a  and so on for every zone to be treated. 
       Description of Preferred Operation 
       [0034]    With reference to the example in  FIG. 3 , a typical completion is shown but many variations of this occur as know by those who are familiar with the variations that occur in configuring well completions. 
         [0035]    A well has been drilled, cased, cemented, and perforated, although this system may be used in open hole completions with selection of the appropriate packers. Casing  149  is shown in this example with perforations  151 ,  152 , and  154  in the casing. A sump packer  155  is properly located and set below the lowermost zone  154 . 
         [0036]    A “completion string” is run into the well consisting of a Locator Snap Latch Seal Assembly  156 , Tubing Spacer  160 , Frac Module  146   c , Tubing Spacer  159 , Frac Module  146   b , Tubing Spacer  159 , Frac Module  146   a , Tubing Spacer  161 , Service/Production Packer  157 , and releasable work string  158  where a production string can be run to replace to workstring at a later date in the completion. The length of Tubing Spacers  159  and  160  are made to position the Frac Modules  146  between the producing zones  162 ,  163 , and  164 . The Service/Production Packer  158  can be of the straight pick-up and set-down style where no rotation is required to move the packer up the hole and re-seal. 
         [0037]    The single trip completion string is landed in sump packer  155 . The location of Sump Packer  155  was based on logs of the zones so that all equipment could be spaced out properly. Therefore, by locating the completion assembly on the Sump Packer  155 , all Frac Modules  146  will be properly positioned in the well. Snap Latch Seal Assembly  156  can be used to verify position of the system before setting any of the above packers. The Locator Snap Latch Seal Assembly  156  seal in the sump packer  155  and will locate on the bottom of the Sump Packer, although “top of the packer” snap latch seal assemblies can be used as well. The Locator Snap Latch Seal Assembly  156  is designed to allow pulling of the Work String  158  to get a load indication on the Sump Packer  155  and then snap back in and put set-down weight on the Sump Packer  155 . The load required to snap out is recorded so an operator can know how much to pull with the workstring before snapping out. Collets on the Locator Snap Latch Seal Assembly  156  can be designed to snap at specified loads. The above steps are common in the art of completing wells. 
         [0038]    To explain operation of the Frac Modules, this discussion will begin with stimulation of the lower-most zone  164 . The lowermost Frac Module  146   c  is assembled slightly different from all the above frac Modules  146   b ,  146   a , and  146   z, z  being any number of zones. In Frac Module  146   c , referring to  FIG. 1   b , the Flapper  79  will be installed in the released position, i.e., finger  78  will be disengaged from location  84 , so the Flapper  78  is free to go to the closed position against Flapper Seat Sleeve  81  and also be free to allow fluid from below the Flapper  79  to open the Flapper  79  to allow the work string  158  to fill with well fluid during tripping into the well and stinging into Sump Packer  155  with Locator Snap Latch Seal Assembly  156 . Also control line hole  93  is plugged at fitting  116 . 
       Reference Point to Repeat Process 
       [0039]    After set-down weight is placed on the sump packer  155 , maybe 10,000 to 20,000 pounds, the Service Packer  157  will be set with set-down weight, and the Hydrils can be closed on the workstring  158 . Frac lines can be attached at the surface and pressure can be applied down the workstring  158  against the Flapper  79  in Frac Module  146   c.    
         [0040]    Referring to  FIG. 1   a ,  1   b , and  1   c  it will be explained 1) how the packing element  28 , or a packing element plus a slip system (not shown), is actuated, and 2) how the Sliding Sleeve  124  is opened, and 3) how the Flapper/Seat Assembly, items  79 , 80 , 81 , 83 , moves downward below the Frac Port  92  and lands on top of the Sliding Sleeve  124 , and 4) how the Lower Pickup Sleeve  49  is unlocked, and 5) how the Flapper  79  in Frac Module  146   b , in the next upper zone  163 , is put into the prepare for release mode. 
         [0041]    In operation, the workstring  158  pressure  22  acts on the closed Flapper  79  in Frac Module  146   c . Shear pin  82  is set at a lower shear value than shear screw  86  so pressure  22  acts on seal  98  and Flapper  79  and Flapper Seat Sleeve  81  causing Shear Pin  82  to shear. Face  82  moves downward to contact face  85  so that the Flapper Seat Sleeve  81  shifts below ports  100  and  101 . Pressure  22  travels thru port  101  and into Gun Drilled Hole  94  to act on Sliding Sleeve Piston  121 . Hole  94  is plugged with plug  95  so pressure only acts on piston  121 . The piston  121  leads shear screw  122  which loads Sliding Sleeve  124  and shifts the Sliding Sleeve  124  downward to the full open position where the shoulder  141  of Key  137  contacts Bottom Sub shoulder  142 . Frac Port  79  is now open and pressures  22  and  23  communicate. 
         [0042]    Pressure  22  also travels through port  100  and up Gun Drilled Hole  93  to act on seals  104  and  105  of Shift Piston  106  to shear pins  111  and move Shift Piston  106  upward. Upward movement of Shift Piston  106  releases Locking Keys  112  so that Lower Pickup Sleeve  49  and Upper Pickup Sleeve  56  are free to move until surfaces&#39; 57  and  58  make contact. Although, surfaces  57  and  58  will not make contact at this time because the operator has put set-down weight on the “completion string” and also because internal pressure  22  will not pump the tool open, or faces  57  and  58  apart, because seals  50 , 51 ,  72 , and  73  on Release Sleeve  55  balance the effects of internal pressure  22 . As pressure  22  continues to act on Piston  106 , Piston  106  continues to move upward until Expanding Lock Dogs  107  engage groove  108  and so Piston  106  is now locked to Lower Pickup Sleeve  49  and they will move together. Simultaneously, Lock Dog  109  engages groove  110  located in Release Sleeve  55 . The shoulder  166  of Lock Dog  109  does not push on shoulder  165  of groove  110  of the Release Sleeve  55  at this time because shoulder  168  of lock dog  107  contacts shoulder  165  of groove  108  of the Lower Pickup Sleeve  49 . 
         [0043]    In Frac Module  146   c , the piston length is such that when Piston  106  is locked in groove  108 , pressure  22  is allowed to pass seal  104 , move into chamber  54 , and travel up hole  40  of Piston Housing  38 . Pressure  22  can now act on seals  33  and  34  of Piston  32  to begin setting the packer or packing element  28 . The Piston  32  causes face  31  of the Gage Ring  29  to begin compressing packing element  28  against face  30  of Push Sleeve  12 . Compressive loads to compress packing element  28  can vary from as low as 10,000 pounds up to 50,000 pounds depending on the casing size and type of packer. This load is transmitted into Push Sleeve  12  to shear pins  8  and surface  30  moves up until Push Sleeve face  170  contacts Shear Ring  7  at face  171 . At this point, recess  172  of Push Sleeve  12  allows pressure  22  to enter port  21 , travel through recess  172  and into port  20  and into gun drilled hole  13 . Gun drilled hole  13  is isolated with seals  4 , 5 , 15 , 16  and connects to hole  9  in Top Sub  1 . Hole  9  has connector  10  that connects control line  11  which is the same as control line  117  that travels up to Frac Module  145   b , see  FIG. 3 , and connects to fitting  116  and travels into hole  93 , see  FIG. 1   c . Pressure  22  travels all the way up to Shift Piston  106  located in Frac Module  146   b.    
         [0044]    In Frac Module  146   b , pressure  22  acts on seals  104  and  105  of Shift Piston  106  to shear pins  111  and move Shift Piston  106  upward. Upward movement of Shift Piston  106  releases Locking Keys  112  so that Lower Pickup Sleeve  49  and Upper Pickup Sleeve  56  are free to move until surfaces  57  and  58  make contact. 
         [0045]    Although in Frac Module  146   b , surfaces  57  and  58  will not make contact at this time because the operator has put set-down weight on the “completion string” and also because internal pressure  22  will not pump the tool open, or faces  57  and  58  apart, because seals  50 ,  51 ,  72 , and  73  on Release Sleeve  55  balance the effects of internal pressure  22 . As pressure  22  continues to act on Piston  106 , Piston  106  continues to move upward until Expanding Lock Dogs  107  engage groove  108  and so Piston  106  is now locked to Lower Pickup Sleeve  49  and they will move together. Simultaneously, Lock Dog  109  engages groove  110  located in Release Sleeve  55 . The shoulder  166  of Lock Dog  109  does not push on shoulder  165  of groove  110  of the Release Sleeve  55  at this time because shoulder  168  of lock dog  107  contacts shoulder  165  of groove  108  of the Lower Pickup Sleeve  49 . In this Frac Module the length of Shift Piston  106  does not allow pressure  22  to pass seals  104  and  105 , therefore the packer in Frac Module does not begin to set until workstring pickup occurs that allows pressure  22  to pass the seals  104  or  105  to get pressure to the packer setting piston. At this point the  146   b  Frac Module has been prepared for pickup to release the Flapper  79 . 
         [0046]    Going back to Frac Module  146   c , pressure  22  is increased against the Flapper 79  until packer setting load increases enough to shear Screws  6  in Ring  7 . Push Sleeve  12  moves upward until faces  30  and  169  line up to create an anti-extrusion surface for packing element  28 . Also, port  21  is isolated with seals  18  and  19 . Pressure  22  is increased until full setting pressure  22  of the packer is reached. Full setting pressure  22  is controlled by Shear screws  86  that engage Seat Housing  83 . 
         [0047]    At this point, the Sliding Sleeve is fully opened and the packer is fully set and the upper Frac Module has an activated Flapper Release sleeve  55 . 
         [0048]    Pressure  22  is increased until Shear Screws  86  shear and the Flapper Assembly  79 ,  80 ,  81 ,  83  and related seals and shear pins, shift downward below the Frac Port  92  and set on top of Frac Sleeve  124  at a position below the bottom edge of the Frac Port windows. The flow path to and thru the Frac Ports is now fully open and zone  164  is ready for stimulation. 
         [0049]    Once the stimulation is complete, it&#39;s time to treat the next upper zone  163 . The workstring is picked up a distance “X”. This is when shoulders  57  and  58  make contact and during the movement thru distance “X” Lock Dog Shoulder  166  engages Release sleeve shoulder  165  which shifts Release Sleeve  55  upward. The Release Sleeve Finger  78  disengages Flapper  79  and allows Flapper  79  to close. The operator is now ready to begin operations on zone  163  as described above beginning at Reference point to repeat process. 
         [0050]    The above process repeats for all zones. The pickup length “X” can be measured at the rig floor by marking pipe for each zone. The occurrence of length “X′ at the surface verifies that the Flapper  79  has been released in each zone. As zones are treated, “X” increases at the rig floor. If a Flapper  79  does not release, the Release Sleeve  55  may be shifted upward to release the Flapper  79  using a shifting tool that locates in profile  77  of Release Sleeve  55 .

Technology Classification (CPC): 4