Abstract:
A device to allow a single ball size to actuate at least two downhole tools. Typically when a large number of ball actuated devices are run in a single well the total number of devices is limited by the increasing size of the balls required to actuate each sequential device. By having a mechanism that allows at least two tools to be actuated by each ball size the total number of ball actuated devices may be at least doubled.

Description:
BACKGROUND 
       [0001]    As fewer hydrocarbon resources are available and global demand continues to increase, methods and devices to produce hydrocarbons efficiently are becoming increasingly crucial. 
         [0002]    One method of increasing efficiency and reducing the cost of producing hydrocarbons a technique is to drill a single wellbore that intercepts many zones. Once the well is drilled it may be necessary to stimulate each zone independently. Typically the stimulation process begins nearest the lower end of the well otherwise known as the toe of the well. 
         [0003]    In the past, the process began by drilling a well, during which, the number of formations that are to be stimulated is determined, keeping in mind the upper limit that can be run into a wellbore. 
         [0004]    In the past systems have been used that, may have for example 21 different stages. In turn, each stage needs a different ball size. Typically the lowermost stage will use the smallest ball size and each stage will use progressively larger ball sizes as the stimulation process moves from the toe of the well towards the surface. 
         [0005]    When running the twenty one zone system into the formation the various sliding sleeves and zone isolation packers are assembled on the surface, starting with the smallest sliding sleeve at the bottom so that the smallest ball will activate the smallest or lowermost sleeve. 
         [0006]    The production tubing is assembled on the surface. At the lowermost end of the tubing may be a fill shoe or it may have a pressure actuated sliding sleeve or toe sleeve. The toe sleeve is typically opened with tubing pressure alone and a ball is not necessary to actuate the sliding sleeve in the toe sleeve. At various intervals along the production assembly, zone isolation devices and corresponding sliding sleeve assemblies may be placed. 
         [0007]    Zone isolation may be accomplished by cementing the production tubing and sliding sleeve system into place. Other devices may be used for formation zone isolation such as wellbore packers, including swellable packers, hydraulic control line packers, and mechanically actuated packers. 
         [0008]    The zone isolation devices are located along the production assembly both above and below each sliding sleeve corresponding with each formation zone that is going to fraced or produced. Typically a ball actuated sliding sleeve is placed so that it is centrally located in a formation zone. Zone isolation devices are placed so that the production tubing is sealed to the wellbore below the formation zone and above the formation zone. Additionally it may be necessary to place anchoring devices at intervals along the length of the production tubular to prevent movement of the production tubular. Any movement of the production tubular could cause to zone isolation devices to shift so that they are no longer located above and below a formation zone or movement could cause erosion of the isolation packer&#39;s seal thereby causing the seal to fail. 
         [0009]    Each of the sliding sleeve assemblies starting just above the toe sleeve and moving towards the surface utilizes a successively larger ball. 
         [0010]    As the production tubular is assembled it is lowered into the wellbore. In those cases where a fill shoe is used the production tubing may be lowered at any rate that keeps the production tubing at least partially filled in order to reduce the buoyancy of the production tubular. In other instances the toe sleeve may be used to seal the lower end of the production tubular. When the lower end of the production tubular is sealed, mud or other fluid may be pumped into the production tubular from the surface. When the mud or other fluid is pumped into the production tubular from the surface the buoyancy of the production tubular may be controlled. By controlling the production tubular&#39;s buoyancy the production tubular may be floated into any relatively long horizontal sections of the wellbore. 
         [0011]    Practical issues related to the size of the larger and smaller balls tend to limit the number of sleeves in a system. While referring generally to a ball to engage each seat in the corresponding sliding sleeve, any object such as a dart or plug, that can move through the well and engage the seat in the sliding sleeve may be used. 
       SUMMARY 
       [0012]    A device and method is provided to actuate two or more sliding sleeves utilizing approximately the same sized ball. The device has a resettable seat in the upper sliding sleeve and a non-resettable seat in the lower sliding sleeve. A ball is dropped into a wellbore where it seats on the resettable seat in the upper sleeve forming a seal. Pressure is applied from the surface whereupon the resettable seat and an insert are shifted from a first position to a second position. Upon being shifted from the first position to the second position the resettable seat may release the ball. The ball then moves downward to the lower sliding sleeve where the ball may land upon the non-resettable seat to shift the insert open, sealing the wellbore and allowing the adjacent formation to be fraced. After the first ball is released from the upper sliding sleeve, a biasing device shifts the insert from the second position to a third position where the seat is reset to catch the next ball. A second but approximately same sized ball may then be dropped in to the wellbore where it lands upon the now reset first seat to shift the first insert open and to seal the wellbore whereupon the adjacent formation may be fraced. 
     
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
         [0013]      FIG. 1  depicts a schematic view of a well intersecting multiple formation zones. 
           [0014]      FIG. 2  depicts an upper sliding sleeve with a ball landed in the resettable seat. 
           [0015]      FIG. 2A  depicts a fluid pressure bias device for an upper sliding sleeve having a resettable seat. 
           [0016]      FIG. 2B  depicts a gas pressure bias device for an upper sliding sleeve having a resettable seat. 
           [0017]      FIG. 3  depicts an upper sliding sleeve with the insert in position 2 and the ball released. 
           [0018]      FIG. 4  depicts a upper sliding sleeve with the insert in position 3 and the resettable seat reset. 
           [0019]      FIG. 5  depicts a lower sliding sleeve with the ball landed on the seat. 
           [0020]      FIG. 6  depicts a lower sliding sleeve with the insert in position 2 and the ball landed on the seat. 
           [0021]      FIG. 7  depicts an upper sliding sleeve with the insert in position 3 and ball landed on the resettable seat. 
           [0022]      FIG. 8  depicts an upper sliding sleeve with the insert in position 4. 
       
    
    
     DETAILED DESCRIPTION 
       [0023]    The description that follows includes exemplary apparatus, methods, techniques, and instruction sequences that embody techniques of the inventive subject matter. However, it is understood that the described embodiments may be practiced without these specific details. 
         [0024]      FIG. 1  depicts a wellbore  10  that intersects several hydrocarbon formations  12 . A production tubular  20  is assembled on the surface  30  and lowered into the wellbore  10 . The production tubular  20  is assembled so that each sliding sleeve assembly  32 ,  34 ,  36 ,  38  is placed so that it will be adjacent to a formation zone  12 . Zonal isolation is accomplished by cementing the production tubular in place or by placing a packer  24  above each formation zone  12  and a packer  26  below each formation zone  12 . Typically a toe sleeve  42  is placed at the lowermost end of the production tubular  20 . 
         [0025]    The production tubular  20  is run into the wellbore  20  until each sliding sleeve assembly  32 ,  34 ,  36 ,  38  is adjacent to its designated formation zone  12 . Once the production tubular is in place each packer  24 ,  26  is set. Once the packers  24 ,  26  are set the operator may drop the smallest ball. The smallest ball will travel down the interior of production tubular  20  until it lands on a seat in sliding sleeve  38 . The operator continues to apply pressure from the surface  30 . The pressure will act on the ball and seat in sliding sleeve  38  to shift open an insert in sliding sleeve  38  to allow fluid access from the interior of the production tubular  20  and the formation zone. The ball remains on the seat in sliding sleeve  38  blocking any further fluid flow past the production tubular  20 . With formation zone  12  adjacent to the now open sliding sleeve  38  and isolated by packers  24  and  26 , fluid flow through the interior of production tubular  20  is blocked. The operator may then begin to stimulate formation zone  12  that is adjacent to sliding sleeve  38 . 
         [0026]    Once the formation zone  12  adjacent to sliding sleeve  38  is stimulated the operator may then begin operations to stimulate the next higher formation zone  12  adjacent to sliding sleeve  36 . 
         [0027]    Ball actuated stimulation operations begin at the lowermost formation zone since a large ball will block access to any lower formations. 
         [0028]      FIG. 2  depicts a sliding sleeve  100  with a resettable seat  110  and insert  120  in the first position. Ball  112  is landed on the resettable seat  110 . The resettable seat  110  is linked to insert  120 . The sliding sleeve has ports  114  that allow access from the throughbore  116  to the sliding sleeve exterior  118 . In position 1 insert  120  blocks fluid access through the port  114  between the throughbore  116  and the exterior of the sliding sleeve  118 . 
         [0029]    A bias device  166 , in  FIG. 2  a spring, is shown in its compressed position. Other bias devices known in the industry may be used as well. 
         [0030]      FIG. 2A  shows a piston  172 , such as a hydraulic piston, with a pressure chamber  170  and a pressure supply line  174  that may be used to supply bias force to move the insert  120  from the second position to the third position. Sleeve  176  contains the pressure as the attached pressure piston  172  moves downward. 
         [0031]      FIG. 2B  shows a piston  184  with a pressure chamber  182  where the pressure chamber is filled with a compressed gas to supply bias force to move the insert  120  from the second position to the third position. Sleeve  180  contains the pressure as the attached piston  184  moves downward. 
         [0032]    The resettable seat  110  is shown in a set position where the resettable seat  110  has an interior portion  128  that is capable of retaining an appropriately sized ball such as ball  112 . The resettable seat  110  has an exterior portion  124  that is supported by the interior of the sliding sleeve housing  126 . 
         [0033]    Typically the sliding sleeve  100  is run into the wellbore  10  in a first position with the insert  120  latched into position by a retaining device such as a shear pin  122 , a snap ring, or any other device provides sufficient resistance to retain the insert  120 . 
         [0034]    Once the ball  112  engages the resettable seat  110  the operator may then begin to apply pressure from the surface against the ball  112  and the resettable seat  110 . When sufficient pressure is exerted against the ball  112  and the resettable seat  110 , then the insert  120 , the ball  112 , and the resettable seat  110  will all shift together to a second position. 
         [0035]      FIG. 3  depicts a sliding sleeve  200  having a resettable seat  210  and insert  220  in the released or second position. The ball  212  is shown just downstream of resettable seat  210  after it has been released. 
         [0036]    Typically, insert  220  is biased so that it may only move downward. Initially retaining device  222  prevents any movement of the insert  222  while bias device  266  prevents any upward movement of the insert  220 . The retaining device  222  has been sheared and the insert  220  has moved in the only direction allowed, downward, a small amount to allow the resettable seat  210  to move outward into the recess  230  in the interior of the sliding sleeve housing  126 . With the exterior portion  224  of the resettable seat  210  in the recess  230 , the interior portion  228  of the resettable seat is no longer capable of retaining the appropriately sized ball  212 . 
         [0037]    In the second position the insert  220  has moved downward a small amount but not enough to uncover the ports  214 . In the second position fluid access from the throughbore  216  to the sliding sleeve exterior  218  is blocked. 
         [0038]    In the second position the insert  220  is not restrained from moving in the downward direction. The bias device  266  continues to apply force to the insert  220  causing it to continue to move to the third position. While bias device is shown as a spring any alternative device to apply pressure, such as a hydraulic piston, compressed gas, or hydrostatic pressure, could be used. 
         [0039]      FIG. 4  depicts a sliding sleeve  300  having a resettable seat  310  in a reset position and insert  320  in the third position. 
         [0040]    In the third position the resettable seat  310  has been reset due to the bias device  366  applying sufficient force to move the insert  320  down to allow a second shear device  332  attached to the insert  320  to come into contact with a shoulder  334  in the interior of the sliding sleeve housing  326 . When the second shear device  332  contacts the shoulder  334  further downward movement of the insert  320  ceases. 
         [0041]    When the insert  320  moves from the second position to the third position the resettable seat  310  is reset so that it will retain the next appropriately sized ball. As the resettable seat  310  moves downward the exterior portion  324  is forced out of the recess  330  and in towards the center of the sliding sleeve  300  so that the interior portion  328  of the resettable seat is once again capable of retaining an appropriately sized ball. 
         [0042]      FIG. 5  depicts a lower, single shot sliding sleeve  400  with a ball  212 . The ball  212  is the same ball that previously moved the upper sliding sleeve&#39;s resettable seat from a first position to a second position before the ball  212  was released downhole and landed on seat  410 . Seat  410  is linked to insert  420 . Sliding sleeve  400  has ports  414  that allow fluid access from throughbore  416  to sliding sleeve exterior  418 . In the first position insert  420  blocks fluid access between throughbore  416  and the exterior of sliding sleeve  418 . 
         [0043]    Typically the sliding sleeve  400  is run into the wellbore in the first position with the insert  420  latched into position by a retaining device such as a shear pin  422 , snap ring, or any other device that provides sufficient resistance to retain the insert  420 . 
         [0044]    As soon as ball  212  engages seat  410  the operator may then begin to apply pressure from the surface against ball  212  and seat  410 . When sufficient pressure is exerted against ball  212  and seat  410 , insert  420 , ball  212 , and seat  410  will all shift together to a second position. 
         [0045]      FIG. 6  depicts a lower, single shot sliding sleeve  500  with a ball  212  landed on the seat  510 . As shown the insert  520  is in the second position. In the second position the ball  212  on seat  510  prevents fluid from traveling downward and diverts the fluid traveling down the throughbore out to the exterior of the sliding sleeve  518  as shown by arrows  540 . By diverting fluid flow  540  from the throughbore  516  to the exterior of the sliding sleeve  518  and blocking fluid flow through the throughbore  516  past the ball  212  and seat  510 , the adjacent formation zone may now be stimulated. 
         [0046]    Once the formation adjacent to the lower sliding sleeve  510  has been stimulated a second ball, approximately the same size as the first ball, may be pumped down to land on the partially actuated, but with the ports still blocked, upper sliding sleeve as shown in  FIG. 7 . 
         [0047]      FIG. 7  depicts an upper sliding sleeve  700  with the insert  720  in position 3 and ball  760  landed on the resettable seat  710 . The ball  760  is approximately the same size ball that previously moved the upper resettable seat from a first position to a second position before the ball was released downhole and actuated the lower sliding sleeve. The seat  710  is linked to insert  720 . The sliding sleeve  700  has ports  714  that allow fluid access from the throughbore  716  to the sliding sleeve exterior  718 . In the third position insert  720  blocks fluid access between the throughbore  716  and the exterior of the sliding sleeve  718 . 
         [0048]    When the ball  760  seats the operator will see an increase in pressure and may then begin to increase the pressure from the surface against the ball  760  and the seat  710 . When sufficient pressure is exerted against the ball  760  and the seat  710  then the second shear device  732  will shear allowing the insert  720 , the ball  760 , and the seat  710  to shift together into a fourth position. 
         [0049]      FIG. 8  depicts an upper sliding sleeve  800  with the insert  820  in a fourth position where ball  860  remains on the resettable seat  810  forming a seal with the resettable seat  810  that blocks fluid flow downward past the upper sliding sleeve  800 . 
         [0050]    In the fourth position the ball  860  on resettable seat  810  prevents fluid from traveling downward and diverts the fluid traveling down throughbore  816  out to the exterior of the sliding sleeve  818  as shown by arrows  840 . By diverting fluid flow  840  from the throughbore  816  to the exterior of the sliding sleeve  818  and blocking fluid flow through the throughbore  816  past the ball  860  and resettable seat  810  the adjacent formation zone may now be stimulated. 
         [0051]    The insert  810  is locked into the fourth position by lock  850  that engages with another recess  852 . The lock  850  prevents fluid flow from below the well from causing the insert  820  to move back towards the top of the well where the insert  820  might block fluid flow through ports  814 . 
         [0052]    While the embodiments are described with reference to various implementations and exploitations, it will be understood that these embodiments are illustrative and that the scope of the inventive subject matter is not limited to them. Many variations, modifications, additions and improvements are possible. For example, the implementations and techniques used herein may be applied to any downhole tool that may be actuated by a ball or other flow blocking device. 
         [0053]    Plural instances may be provided for components, operations or structures described herein as a single instance. In general, structures and functionality presented as separate components in the exemplary configurations may be implemented as a combined structure or component. Similarly, structures and functionality presented as a single component may be implemented as separate components. These and other variations, modifications, additions, and improvements may fall within the scope of the inventive subject matter.