Abstract:
The present invention provides for an apparatus and method to actuate a tool in a well based on one or more issued commands being interpreted and implemented by the apparatus.

Description:
[0001]     This application claims the benefit of U.S. Provisional Application 60/521,395 filed on Apr. 16, 2004. 
     
    
     BACKGROUND  
       [0002]     1. Field of Invention  
         [0003]     The present invention pertains to a setting tool used in a well, and particularly to a setting tool for hydraulically actuated devices.  
         [0004]     2. Related Art  
         [0005]     It is often desirable to actuate a downhole tool such as a packer, valve, or test device, for example, after placing the tool in a desired location in a well. Typical prior art devices require a separate intervention run using a tool such as a mechanical actuator run on a slickline or an electrical actuator run on a wireline. Other existing tools require a communication link to the surface such as a hydraulic or electrical control line run in with the tool.  
       SUMMARY  
       [0006]     The present invention provides for an apparatus and method to actuate a tool in a well based on one or more issued commands being interpreted and implemented by the apparatus.  
         [0007]     Advantages and other features of the invention will become apparent from the following description, drawings, and claims.  
     
    
     BRIEF DESCRIPTION OF DRAWINGS  
       [0008]      FIG. 1  shows a block diagram of a setting tool for hydraulically actuated devices constructed in accordance with the present invention.  
         [0009]      FIG. 2  shows a schematic view of an example completion assembly having the setting tool of  FIG. 1 .  
         [0010]      FIG. 3  shows a schematic view of an embodiment of the setting tool of  FIG. 1 .  
         [0011]      FIG. 4  shows a schematic view of an embodiment of a control command compartment used in the setting tool of  FIG. 1 .  
         [0012]      FIG. 5  shows a schematic view of an embodiment of a power generation module used in the setting tool of  FIG. 1 .  
         [0013]      FIG. 6  shows a schematic view of an embodiment of a trigger device used in the setting tool of  FIG. 1 .  
         [0014]      FIG. 7  shows a schematic view of an alternative embodiment of a power generation module used in the setting tool of  FIG. 1 .  
         [0015]      FIG. 8  shows a schematic view of an alternative embodiment of a power generation module used in the setting tool of  FIG. 1 .  
         [0016]      FIG. 9  shows a schematic view of an alternative embodiment of a power generation module used in the setting tool of  FIG. 1 .  
         [0017]      FIG. 10  shows a schematic view of an alternative embodiment of a power generation module used in the setting tool of  FIG. 1   
         [0018]      FIG. 11  shows a schematic view of an alternative embodiment of a power generation module used in the setting tool of  FIG. 1 .  
         [0019]      FIG. 12  shows a schematic view of an alternative embodiment of a power generation module used in the setting tool of  FIG. 1 .  
     
    
     DETAILED DESCRIPTION  
       [0020]      FIG. 1  shows a setting tool  10 . Setting tool  10  is preferably a modular tool designed to actuate a completion element or downhole device such as a packer, valve, sampler, or other downhole apparatus without intervention. This may be achieved, for example, using signals such as pressure pulses, electric or electromagnetic signals, or by delivering pressure downhole. Other input signals such as acoustic or seismic signals could be used. Setting tool  10  can respond to those various inputs and can be used in a large number of applications. The input signals may be sent through tubing, through fluid in the tubing or annulus (including air), through a control line or fluid in the control line, through earth formations, or through casing. Setting tool  10  can be used in a variety of environments, with different sized casings, and across various ranges of hydrostatic pressure and temperature.  
         [0021]     Setting tool  10  is preferably not integral with a specific application tool such as the packer  15  shown in  FIG. 2 , though it could be so incorporated if desired. The embodiment shown in  FIG. 1  has a sensing and actuation module  12  and a power generation module  14 . Sensing and actuation module  12 , when present, senses the input command and initiates actuation of the downhole device via the actuation module. The actuation module causes power generation module  14  to act as described further below, thereby activating the desired downhole device. This allows a wide range of functionality for setting tool  10 . Setting tool  10  can operate in a wide range of hydrostatic pressures, and can be sensitive, say, to a pressure pulse of only a few hundred pounds per square inch. Setting tool  10  can be variously conveyed into the well, including on tubing  16 . Setting tool  10  may also be used having just the power generation module  14 , using, for example, a system of rupture discs that allow power generation module  14  to actuate the downhole device upon rupture of the discs.  
         [0022]      FIG. 3  shows an embodiment of setting tool  10  having three main modules: a command compartment  18 , a trigger  20 , and a power module or intensifier  22 . Command compartment  18  ( FIG. 4 ) preferably comprises batteries  21 , sensors  23  such as pressure gauges, and microprocessors  25  or other electronic devices. Trigger  20  can be strategically placed in the well to increase the reliability of setting tool  10 . Trigger  20  can be electronically controlled to actuate the completion element or downhole device at some desired time.  
         [0023]     Intensifier  22  ( FIG. 5 ) can have a series of atmospheric chambers  27 , preferably in series, to produce a multiplier effect on the pressure delivered. In some embodiments, intensifier  22  is linked to the hydrostatic pressure acting on it and delivers a multiple of that pressure as its output. The pressure delivered may also be increased or decreased depending on the number of pistons  89  used and the hydrostatic pressure conditions. As shown in  FIG. 12 , a system of rupture discs  91  ( 91   a ,  91   b , and  91   c ) may be used to allow the tool to operate intelligently and reduce operator error. The discs  91  act as plugs dependent on the hydrostatic pressure and allow the desired number of pistons  89  ( 89   a ,  89   b , and  89   c ) to be used with no operator intervention. At low pressures, all pistons  89  are used. As the hydrostatic pressure increases, rupture disc  91  a ruptures, thereby flooding chamber  27   a  and deactivating piston  89   a . As the hydrostatic pressure further increases, rupture disc  91   b  ruptures and only piston  89   c  is used in actuation. In this manner, the operator does not have to choose which piston to use. Rather, the rupture discs will allow proper selection of the pistons per downhole conditions.  
         [0024]     Trigger  20  is preferably a normally closed valve with a cartridge-actuated device that may be opened when desired. It is preferably located between intensifier  22  and the completion element or downhole tool to be set. That placement allows setting tool  10  to always operate in a “safe” mode as it sets the completion element.  FIG. 6  is an example of one embodiment of trigger  20 . If trigger  20  fails to operate, rupture discs  91  may be used to enable the completion element to be set by simply pressuring up the tubing.  
         [0025]     The power module  22  shown in  FIG. 7  is a module that is generally placed below a hydraulically-actuated device and operates in response to hydrostatic pressure upon rupturing a burst (rupture) disc. A first burst disc  29  is ruptured with surface activation pressure. The hydrostatic pressure plus the applied pressure enters a first chamber  31  and pushes a piston  43  such that it tries to collapse a second (atmospheric) chamber  33 . Since the piston area of first chamber  31  is larger than the piston area in a third chamber  35 , the pressure in third chamber  35  is intensified. The intensified pressure from third chamber  35  is communicated to the hydraulically-actuated device via a control line  37 .  
         [0026]     A thermal compensation feature  39  allows for fluid expansion as transport fluid heats up on the way downhole, and is achieved by ensuring there is sufficient room for piston  43  to move (to the right) as fluid in third chamber  35  expands (e.g., with temperature). To create this piston travel distance, a spring  41  is placed in chamber  31 . Spring  41  may also be activated during assembly if third chamber  35  is overfilled. In this case, when the pressure in third chamber  35  is released, spring  41  pushes piston  43  back to the proper position so that minimum travel is assured.  
         [0027]     A full throttle feature  45  is an option shown in  FIG. 8 , and allows setting through large ports  47 . When the first burst disc  29  is ruptured, piston  43  and a full throttle piston  49  travel away from each other. Full throttle piston  49  moves to the right, collapsing a fourth chamber  51  and at the same time opening up greater access to setting piston  43  via ports  47 . This allows the stroking of setting piston  43  to be accomplished in the “full throttle mode” as opposed to setting through the ruptured burst disc port  53 .  
         [0028]     In the embodiments shown in  FIGS. 7 and 8 , the internal pistons  43 ,  49  are balanced so there are no undue stresses acting on the internal seals (O-rings). This increases the reliability of setting tool  10 . All chambers have a test port to verify the seals are functional prior to running in hole.  
         [0029]     A secondary setting feature  55  is shown in  FIG. 7  as an arrangement of check valve  57  and a second burst disc  59 . Check valve  57  protects second burst disc  59  from internal pressure from control line  37 . Also the arrangement maintains a small, trapped atmospheric chamber between check valve  57  and second rupture disc  59 . This makes it possible to rupture second burst disc  59  with minimal applied pressure. Without the trapped atmospheric pressure, the full rating of second burst disc  59  would need to be applied at the surface. In many applications that may not be possible.  
         [0030]     An adjustable setting area feature  61  that allows the ratio of pressure intensification of intensifier  22  to be adjusted is shown in  FIG. 9 . This design splits the piston into two portions having a small piston  63  and at least one large piston  65 . The embodiment shown has multiple large pistons  65 . Through a port  67  in a housing  69  of intensifier  22 , a rod  71  is installed into one or more of the large pistons  65 . Depending on the length of rod  71 , various pistons  65  are restrained from movement. That allows the pressure intensification to be easily adjusted.  
         [0031]     An adjustable protection sleeve  73  is shown in  FIG. 10 . This feature is an option for use in high-pressure applications. Protection sleeve  73  isolates burst disc  29  in high hydrostatic pressure conditions (such as may result from heavy fluid or a pressure test). Typically, the last step prior to setting a packer presents the highest-pressure condition: the tubing hanger pressure test. Prior to running setting tool  10  downhole, protection sleeve  73  can be set to a position corresponding to the anticipated hydrostatic and test pressure conditions by compressing or extending an adjustment spring  75 . The C-ring  77  keeps protection sleeve  73  in a closed position. Under the high-pressure hydrostatic conditions adjustment spring  75  provides sufficient force to keep protection sleeve  73  in the closed state, isolating first burst disc  29 . However, during the tubing hanger pressure test, the hydrostatic and applied pressures overcome the spring force and move protection sleeve  73  to the left, dropping C-ring  77  into a recess  79 . When pressure is released, first burst disc  29  is uncovered and intensifier  22  works as described above.  
         [0032]     The embodiment shown in  FIG. 11  shows an open port concept in which chamber  35  is in fluid communication with the exterior of intensifier  22  via autofill port  81 . A filter  82  may be placed in port  81  to prevent particulates in the well fluid from entering chamber  35  and control line  37 . A velocity valve  85  near the end of piston  43  may be used to avoid premature setting of the downhole tool. Equalizing port  87  prevents an atmospheric chamber from becoming trapped in chamber  33 .  
         [0033]     Although only a few exemplary embodiments of this invention have been described in detail above, those skilled in the art will readily appreciate that many modifications are possible in the exemplary embodiments without materially departing from the novel teachings and advantages of this invention. Accordingly, all such modifications are intended to be included within the scope of this invention as defined in the following claims. In the claims, means-plus-function clauses are intended to cover the structures described herein as performing the recited function and not only structural equivalents, but also equivalent structures. Thus, although a nail and a screw may not be structural equivalents in that a nail employs a cylindrical surface to secure wooden parts together, whereas a screw employs a helical surface, in the environment of fastening wooden parts, a nail and a screw may be equivalent structures. It is the express intention of the applicant not to invoke 35 U.S.C. § 112, paragraph 6 for any limitations of any of the claims herein, except for those in which the claim expressly uses the words ‘means for’ together with an associated function.