Abstract:
The present invention generally relates to an apparatus and method for operating a tool in a wellbore. In one aspect, the apparatus includes a hydraulically operated tool and a wellbore tubular both in communication with a pressure sensing line. The hydraulically operated tool is responsive to a combination of a fluid pressure in the pressure sensing line and a manipulation of the wellbore tubular, such response causing the tool to operate within the wellbore. In another aspect, the invention provides a method for anchoring a well tool in a wellbore. The method includes the steps of lowering the well tool into the wellbore on a tubular string, flowing fluid through the tubular string to begin anchoring the well tool, and manipulating the tubular string to complete the anchoring of the well tool.

Description:
BACKGROUND OF THE INVENTION  
         [0001]    1. Field of the Invention  
           [0002]    This invention relates generally to a method and an apparatus for operating a tool in a wellbore. More particularly, the invention relates to positioning a tool in a wellbore and setting the tool in a fixed position. Still more particularly, the invention relates to actuation of a downhole hydraulic tool by an actuation apparatus that uses a pressure differential in a conduit carrying a fluid flow to actuate the downhole hydraulic tool.  
           [0003]    2. Description of the Related Art  
           [0004]    Hydraulically-actuated tools such as packers and anchor assemblies have long been used in the drilling industry. A tool often used in conjunction with anchors or packers is a deflector, which is commonly called a whipstock. A deflector includes an inclined face and is typically used to direct a drill bit or cutter in a direction that deviates from the existing wellbore. The combination deflector and anchor (or packer) is frequently termed a sidetrack system. Sidetrack systems have traditionally been used to mill a window in the well casing, and thereafter to drill through the casing window and form the lateral wellbore.  
           [0005]    Originally, such a sidetrack operation required two trips of the drill string. The first trip was used to run and set the anchor or packing device at the appropriate elevation in the wellbore. With the anchor or packer in place, the drill string was then removed from the well and a survey was made to determine the orientation of a key on the upper end of the anchor-packer. With that orientation known, the deflector was then configured on the surface so that when the deflector engaged the anchor-packer in the wellbore, it would be properly oriented. So configured, the deflector, along with an attached cutter, was then lowered in the wellbore on the drill string and secured to the anchor-packer. Once connected to and supported by the packer, the deflector directed the cutter so that a window would be milled in the casing of the wellbore at the desired elevation and in the preselected orientation. This two-trip operation for setting the anchor-packer and then lowering the deflector and cutter is time-consuming and expensive, particularly in very deep wells.  
           [0006]    To eliminate the expense associated with two trips of the drill string, an improved sidetrack system was developed which required only a single trip. Such a system includes a deflector having an anchor-packer connected at its lower end, and a cutter assembly at its upper end connected by a shearable connection. Using such a system, the deflector is oriented by first lowering the apparatus into the cased wellbore on a drill string. A wireline survey instrument is then run through the drill string to check for the proper orientation of the suspended deflector. After the deflector is properly oriented in the wellbore, and the anchor-packer set, the drill string is then lowered causing the cutter assembly to become disconnected from the deflector. As the cutter is lowered further, the inclined surface of the deflector urges the rotating cutter against the well casing, causing the cutter to mill a window in the casing at the predetermined orientation and elevation.  
           [0007]    To be contrasted with wireline devices, there exist today a variety of systems that are capable of collecting and transmitting data from a position near the drill bit while drilling is in progress. Such measuring-while-drilling (“MWD”) systems are typically housed in a drill collar at the lower end of the drill string. In addition to being used to detect formation data, such as resistivity, porosity, and gamma radiation, all of which are useful to the driller in determining the type of formation that surrounds the wellbore, MWD tools are also useful in surveying applications, such as, in determining the direction and inclination of the drill bit. Present MWD systems typically employ sensors or transducers which, while drilling is in progress, continuously or intermittently gather the desired drilling parameters and formation data and transmit the information to surface detectors by some form of telemetry, most typically a mud pulse system. The mud pulse system creates acoustic signals in the drilling mud that is circulated through the drill string during drilling operations. The information acquired by the MWD sensors is transmitted by suitably timing the formation of pressure pulses in the mud stream. The pressure pulses are received at the surface by pressure transducers that convert the acoustic signals to electrical pulses, which are then decoded by a computer.  
           [0008]    MWD tools presently exist that can detect the orientation of the drill string without the difficulties and drawbacks described above that are inherent with the use of wireline sensors. However, known MWD tools typically require drilling fluid flow rates of approximately 250 gallons per minute to start the tool, and 350 to 400 gallons per minute to gather the necessary data and transmit it to the surface via the mud pulse telemetry system. The conventional bypass valves used in present-day sidetrack systems for circulating drilling fluid and transporting a wireline sensor to the deflector tend to close, and thereby actuate the anchor-packer, at flow rates of approximately 100 gallons per minute, or even less. Thus, while it might be desirable to combine MWD sensors in a sidetrack system, if drilling mud was circulated through the drill string at the rate necessary for the MWD tool to detect and communicate to the driller the orientation of the deflector, the bypass valve would close and the anchor-packer would be set prematurely, before the deflector was properly oriented. As described in the following paragraphs, there are several different methods for setting a downhole tool such as an anchor-packer.  
           [0009]    An improved apparatus for setting a hydraulically actuated downhole tool in a wellbore is disclosed in Bailey, U.S. Pat. No. 5,443,129, which is incorporated herein by reference in its entirety. The &#39;129 apparatus utilizes a bypass valve located in the run-in string below the MWD device and above the cutter. The valve is in an open position while the MWD device is operating thereby diverting fluid flow and pressure from the tubular to the annulus without creating a pressure sufficient to actuate a downhole tool. Upon completion of operation of the MWD device, the bypass valve is remotely closed. Thereafter, selectively operable ports in the cutter are opened and the tubular therebelow is pressurized to a point necessary to actuate the tool. While the apparatus of the &#39;129 patent allows operation of a MWD device without the inadvertent actuation of a downhole tool, the bypass valve is complex requiring many moving parts and prevents the continuous flow of fluid through the cutter. Additionally, the bypass valve may not function properly in a wellbore that contains little or no fluid. Finally, the fluid borne sediment tends to settle and collect in the cutter.  
           [0010]    An apparatus to actuate a downhole tool is disclosed in Brunnert, U.S. Pat. No. 6,364,037, which is incorporated herein by reference in its entirety. The &#39;037 invention provides an apparatus for actuating a downhole tool by utilizing a pressure differential created by fluid flowing through a conduit. The conduit is in communication with a pressure sensing line that is selectively exposed to areas of the conduit having different pressures. By exposing the pressure sensing line to a portion of the conduit having a predetermined pressure therein, the pressure sensing line causes actuation of a hydraulic tool therebelow. While the apparatus of the &#39;037 patent allows operation of a MWD device without the inadvertent actuation of a downhole tool, the apparatus is complex requiring many moving parts.  
           [0011]    A whipstock setting apparatus is disclosed in Braddick, U.S. Pat. No. 5,193,620, which is incorporated herein by reference in its entirety. The &#39;620 invention provides a whipstock setting apparatus that includes a whipstock and a mandrel. A downhole tool including a mechanical weight set packer and upper and lower cone and slip means are mounted on the mandrel above and below the downhole tool. The mandrel is releasably connected to the downhole tool to prevent premature longitudinal movement while accommodating the relative longitudinal movement at a predetermined point. The components of the whipstock assembly and downhole tool are secured to maintain alignment with the face of the whipstock while lowering the whipstock in the well tubular member. Thereafter, the mandrel is released and the whipstock is oriented in the well tubular member. Subsequently, the oriented whipstock and downhole tool are mechanically anchored in the well tubular member by longitudinal movement of the work string. While the apparatus of the &#39;620 patent actuates the downhole tool without any complex hydraulic mechanism, the manipulation of the piping string to initiate the sequence of events to set the whip stock setting apparatus may not be effective in a deviated wellbore due to the angle of the wellbore and frictional problems.  
           [0012]    A one-trip whipstock milling system is disclosed in Ross, U.S. Pat. No. 5,947,201, which is incorporated herein by reference in its entirety. The &#39;201 invention provides a bottomhole assembly that includes a whipstock milling system, a downhole tool, a whipstock and orientation instrumentation. After the bottomhole assembly is located in the wellbore, the wellbore is pressurized to actuate the downhole tool. Thereafter, the milling operation cuts a window in the surrounding casing. While the apparatus of the &#39;201 patent actuates the downhole tool without a complex hydraulic mechanism or mechanical manipulation of the piping string, the pressurizing of the wellbore is very costly and will not operate properly if there is little or no fluid in the wellbore.  
           [0013]    There is a need therefore, for a single trip sidetrack apparatus permitting a continuous flow of well fluid therethrough while allowing the actuation of a hydraulically actuated tool at a predetermined position in the borehole. There is a further need therefore, for a single trip sidetrack apparatus that does not depend on a value to prevent inadvertent actuation of a downhole tool. There is a further need for an actuation apparatus that allows fluid to flow therethrough before and during actuation of a downhole tool. There is yet a further need for actuating a hydraulically actuated tool in a wellbore that contains little or no wellbore fluid. Finally, there is a need for a single trip sidetrack apparatus that contains an actuation apparatus with no moving parts.  
         SUMMARY OF THE INVENTION  
         [0014]    The present invention generally relates to an apparatus and method for operating a tool in a wellbore. In one aspect, the apparatus includes a hydraulically operated tool and a wellbore tubular both in communication with a pressure sensing line. The hydraulically operated tool is responsive to a combination of fluid pressure in the pressure sensing line and manipulation of the wellbore tubular, such response causing the tool to operate within the wellbore.  
           [0015]    In another aspect, the wellbore tubular includes a mechanism to create a differential pressure, whereby a higher pressure is created in an upper region above the mechanism and a low pressure is created in a lower region below the mechanism. The mechanism comprises a restriction formed in the wellbore tubular and a seat for a hydraulic isolation device.  
           [0016]    In another aspect, the invention provides a method for anchoring a well tool in a wellbore. The method includes the steps of lowering the well tool into the wellbore on a tubular string, flowing fluid through the tubular string to begin anchoring the well tool, and manipulating the tubular string to complete the anchoring of the well tool.  
           [0017]    In yet another aspect, the invention provides a method of anchoring a tool in a wellbore that includes the step of lowering the tool on a wellbore tubular into the wellbore, the wellbore having a first portion substantially devoid of liquid. The method further includes the steps of locating the tool in the first portion and flowing fluid through the wellbore tubular to anchor the tool in the first portion. 
       
    
    
     BRIEF DESCRIPTION OF THE DRAWINGS  
       [0018]    So that the manner in which the above recited features of the present invention can be understood in detail, a more particular description of the invention, briefly summarized above, may be had by reference to embodiments, some of which are illustrated in the appended drawings. It is to be noted, however, that the appended drawings illustrate only typical embodiments of this invention and are therefore not to be considered limiting of its scope, for the invention may admit to other equally effective embodiments.  
         [0019]    [0019]FIG. 1 is an elevation view of a side track system disposed in a wellbore.  
         [0020]    [0020]FIG. 2 is a cross-sectional view illustrating one embodiment of an actuation apparatus for use in the sidetrack system.  
         [0021]    [0021]FIG. 3 is a cross-sectional view illustrating a downhole tool in a run-in position.  
         [0022]    [0022]FIG. 4 is a cross-sectional view illustrating the slips expanded radially outward into a surrounding casing to secure the downhole tool in the wellbore.  
         [0023]    [0023]FIG. 5 illustrates a packing element expanded into the surrounding casing to seal off a portion of the wellbore.  
         [0024]    [0024]FIG. 6 illustrates the deactivation of the downhole tool.  
         [0025]    [0025]FIG. 7 illustrates an alternative embodiment of a downhole tool in a run-in position.  
         [0026]    [0026]FIG. 8 is an enlarged view illustrating a large piston area prior to setting the slips.  
         [0027]    [0027]FIG. 9 illustrates the downhole tool after the packing element and slips are set in the surrounding casing.  
         [0028]    [0028]FIG. 10 is an enlarged view illustrating a small piston area after the slips are set.  
         [0029]    [0029]FIG. 11 is a cross-sectional view illustrating an alternative embodiment of an actuation apparatus in the run-in position.  
         [0030]    [0030]FIG. 12 is a cross-sectional view illustrating the flow rate through the actuation apparatus to operate a MWD device.  
         [0031]    [0031]FIG. 13 is a cross-sectional view illustrating the flow rate through the actuation apparatus to actuate the downhole tool.  
         [0032]    [0032]FIG. 14 is a cross-sectional view illustrating the flow rate through the actuation apparatus after the downhole tool is actuated.  
         [0033]    [0033]FIG. 15 is a cross-sectional view illustrating an alternative embodiment of an actuation apparatus.  
         [0034]    [0034]FIG. 16 is a cross-sectional view illustrating an alternative embodiment of an actuation apparatus.  
         [0035]    [0035]FIG. 17 is a cross-sectional view illustrating an alternative embodiment of an actuation apparatus with a hydraulic isolation device.  
         [0036]    [0036]FIG. 18 is a cross-sectional view illustrating the removal of the hydraulic isolation device from the actuation apparatus. 
     
    
     DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENT  
       [0037]    This invention provides a sidetrack system  10  useful for offsetting a wellbore by directing a drill bit or cutter at an angle from the existing wellbore. FIG. 1 is an elevation view of the sidetrack system  10  disposed in a wellbore  60 . The sidetrack system  10  is shown attached at the lower end of a tubular string  20  and run into the wellbore  60  lined with casing  30 . However, the invention is not limited to use in a cased wellbore, but is equally applicable to open, non-cased wellbores. Thus, throughout this disclosure, the term “wellbore” shall refer both to cased wellbore and open wellbore.  
         [0038]    The sidetrack system  10  generally includes a MWD device  25 , an upper actuation apparatus  100 , a window mill  125 , a deflector  50 , and a hydraulically operated downhole tool  200 . The MWD device  25  provides the driller with intelligible information at the surface of wellbore  60  that is representative of the orientation of the sidetrack system  10 , and provides a variety of other downhole measurements and data. Typically, the MWD  25  includes a conventional mud pulse telemetry system. The mud pulse telemetry system is well understood by those skilled in the art, thus only a brief description of the system is provided herein. Mud pumps located at the surface of the well circulate drilling mud into the top of the drill string. The mud is conducted through the drill string into the MWD  25  where it passes through a mud pulser that repeatedly interrupts the mud flow to produce a stream of pressure pulses in the circulating drilling mud that can be detected at the surface by pressure transducers. These signals are then analyzed by computer on a continuous basis to determine the inclination, azimuth and other pertinent information that is displayed to an operator by means of a monitor and recorded by a recorder.  
         [0039]    The operation of the MWD  25  can be performed without actuating the downhole tool  200  because a greater amount of flow is required to actuate the tool  200  than is required to operate the MWD  25 . After operation of the actuation apparatus  100 , the downhole tool  200  can be actuated prior to separation of the window mill  125  from the deflector  50 . Generally, the deflector  50  or whipstock comprises an elongated tubular member having an inclined face  55  that, once properly oriented in the wellbore  60 , is used to deflect the window mill  125  into the casing  30 . The deflector  50  is fixed to a bent sub  205  on the downhole tool  200 . The bent sub  205  is slightly bent at an angle to ensure the deflector  50  remains flush against the casing  30 , thereby allowing the inclined face  55  of the deflector  50  to be oriented to the low side of the casing  30 . In addition, the interior of deflector  50  includes a pressure sensing line (not shown) for transmitting pressure from the actuation apparatus  100  to the downhole tool  200  as will be described fully herein. Additionally, the bent sub  205  functions as a point of disconnect between the deflector  50  and the tool  200  in the event the tool  200  becomes immobilized downhole.  
         [0040]    In the embodiment illustrated, the downhole tool  200  includes two subassemblies a packer and an anchor. Generally, the packer is a mechanically actuated subassembly that, upon actuation, attaches to the wellbore casing  30  at a predetermined elevation to seal a portion of the wellbore  60  below the packer from a portion above it. While the anchor subassembly is a hydraulically actuated mechanism which, upon delivery of a pressurized fluid at a predetermined pressure becomes set in the casing  30  so as to support deflector  50 . The anchor subassembly generally includes a set of slips and cones that fix the sidetrack system  10  in the wellbore  60  as will be described fully herein.  
         [0041]    In the preferred embodiment, the downhole tool  200  is actuated by sequential actions of the actuation apparatus  100  and mechanical force supplied by the drill string  20 . The components making up the actuation apparatus  100  are visible in FIG. 2. The actuation apparatus  100  is installed in a tubular member  105  above window mill  125 . The window mill  125  includes a plurality of cutters  130  and flow ports  135  which provide an exit for fluids pumped through tubular member  105  from the well surface.  
         [0042]    [0042]FIG. 2 is a cross-sectional view illustrating one embodiment of the actuation apparatus  100  for use with the sidetrack system  10 . As shown, a sand tube  110  is disposed in the tubular member  105  and secured in place by set screw  165 . The sand tube  110  acts as a sand screen to prevent sand from clogging up a pressure port  140  formed in the tubular member  105 . The sand tube  110  includes a slit  115  located in region  155  to communicate the change in pressure through an annular area  170  and subsequently into the pressure port  140 . The purpose of the annular area  170  is to create a tortuous path and a still space to allow communication of pressure while minimizing any particulate matter entering the port  140 . Additionally, the sand tube  110  includes restriction  120  in the inner diameter thereof, which serves to restrict the flow of fluid through tubular member  105 . As fluid passes through the actuation apparatus  100  and encounters restriction  120 , the pressure of the fluid drops in a region  160  directly below restriction  120  and increases in the region  155  directly above restriction  120 , thereby creating a pressure differential between the two regions  155 ,  160 . Conversely, the velocity of the fluid decreases in area  155  and increases in area  160 . Formed in a wall of tubular member  105  is the pressure port  140 . Connected in fluid communication to pressure port  140  through a fitting  145  is a pressure sensing line  150 .  
         [0043]    In order to actuate the tool (not shown), fluid at a predetermined flow rate is applied through the tubular member  105 . As fluid moves through restriction  120 , a higher pressure is created in region  155 . The higher pressure is communicated into the slit  115  in the sand tube  110  through the annular area  170  into the pressure port  140  and subsequently through the pressure sensing line  150  into the tool. The tool  200  as illustrated in FIG. 3 is constructed and arranged to hydraulically actuate a plurality of slips  275  based upon the pressure differential communicated through the pressure sensing line  150 . It should be noted that the pressure differential may be created by compressible fluid such as a foam or incompressible fluid such as drilling fluid.  
         [0044]    [0044]FIG. 3 is a cross-sectional view illustrating the downhole tool  200  in a run-in position. In the preferred embodiment, the fluid pressure in the actuation apparatus  100  is communicated through the pressure sensing line  150  to the downhole tool  200 , thereby allowing the piston  245  to be hydrostatically balanced. Generally, the fluid pressure is communicated through the center of the tool  200  through a flow path consisting of a sub bore  210 , a stinger bore  310 , and a lower body bore  225 . Thereafter, the fluid pressure enters cavity  240  through body port  235  that is formed at the lower end of the lower body  230 . A force is created on a lower piston surface  246  as the fluid pressure builds in the cavity  240 . At the same time, an opposite force is created on the upper piston surface  248  by a hydrostatic pressure that is communicated from an annulus  70  through a housing port  260  into a housing cavity  255 . As the force on the lower piston surface  246  becomes greater than the force on the upper piston surface  248 , the pressure differential on the piston  245  begins the setting sequence of tool  200 . Typically, the annulus  70  in the wellbore  60  contains wellbore fluid, thereby allowing the fluid to be communicated through the housing port  260  to create a fluid pressure against the upper piston surface  248 . However, the tool  200  may be hydraulically activated when the annulus  70  does not contain wellbore fluid.  
         [0045]    [0045]FIG. 4 is a cross-sectional view illustrating the slips  275  expanded radially outward into the surrounding casing  30  to secure the downhole tool  200  in the wellbore  60 . Generally, the more fluid pressure communicated down the center of the tool  200 , the more force acting against lower piston surface  246  until a point is reached where the fluid pressure in the tool  200  becomes larger than the pressure acting against the upper piston surface  248 . At this point, the fluid pressure in the tool  200  urges the piston  245  upwards toward the bent sub (not shown).  
         [0046]    The upward movement of the piston  245  causes a collet housing  250  and lower cone  265  to move upward, thereby shearing pin  270 . After the pin  270  fails, the lower cone  265  continues to move upward to act against slips  275 . Subsequently, the slips  275  are urged upward to act against housing  285 . At a predetermined force, pin  280 , which secures the housing  285  to an upper cone  290  fails and allows the upper portion of the slips  275  to ride up a tapered portion  292  of the upper cone  290 . As additional fluid force is generated, the force acting on the lower piston surface  246  continues to increase, thereby causing the pin  295  to fail. At this point, a tapered portion  267  on the lower cone  265  is wedged under the slips  275  causing the slips  275  to move radially outward engaging the casing  30 . In this manner, the slips  275  are set into the casing  30  securing the tool  200  downhole.  
         [0047]    [0047]FIG. 5 illustrates a packing element  305  expanded into the surrounding casing  30  to seal off a portion of the wellbore  60 . After the tool  200  is secured within the casing  30  by the slips  275 , the packing element  305  may be expanded. Generally, an uphole mechanical force is applied axially downward on the drill string (not shown) and subsequently applied to the sidetrack system (not shown), which includes the downhole tool  200 . As the mechanical force is applied to the downhole tool  200 , the slips  275  hold the lower portion of the tool  200  stationary while the bent sub  205  and a stinger  220  are urged axially downward compressing packing element  305  against a cone extension  315 . Thereafter, the packing element  305  is urged radially outward into contact with the surrounding casing  30 . In this manner, expanding the packing element  305  may seal off the wellbore  60 .  
         [0048]    [0048]FIG. 6 illustrates the deactivation of the downhole tool  200 . The downhole tool  200  may be removed from the wellbore  60  after the milling operation is complete. Typically, the window mill (not shown), actuation apparatus (not shown), and MWD (not shown) are removed from the wellbore  60  after the milling operation, while the deflector (not shown) and the tool  200  remain downhole. Subsequently, a drill string and fishing tool (not shown) are employed in the well to attach to the deflector. Soon after attachment, the drill string and fishing tool are pulled axially upward causing the deflector to move axially upward and create an axially upward force on the downhole tool  200 . At a predetermined force, the tool  200  releasing sequence begins as a plurality of shear screws  320  fail, thereby allowing the stinger  220 , which is connected to the bent sub  205 , to move axially upward. The stinger  220  continues to move axially upward until a stinger shoulder  325  reaches the retainer shoulder  330 . At this point, the lower end of the stinger  220  is pulled out from a plurality of collet fingers  340 , thereby allowing the collet fingers  340  to collapse inward. As the releasing sequence unfolds, the bent sub  205  and the stinger  220  act as one upward moving unit causing the packing element  305  to relax, thereby releasing the seal on the surrounding casing  30 . At the same time, the tapered portion  292  on the upper cone  290  is pulled axially upward out from under the slips  275  while the slips  275  are pulled off the tapered portion  267  on the lower cone  265 , thereby allowing the slips  275  to move radially inward releasing the slips  275  from the surrounding casing  30 . In this manner, the downhole tool  200  is released from the surrounding casing  30 , thereby allowing the deflector and the tool  200  to be removed from the wellbore  60 .  
         [0049]    [0049]FIG. 7 illustrates an alternative embodiment of a downhole tool  400  in a run-in position. As shown, downhole tool  400  has similar components as downhole tool  200 . Therefore, for convenience, similar components in downhole tool  400  will be illustrated with the same number used in the downhole tool  200 . The tool  400  will be actuated by the actuation apparatus (not shown) in the same manner as described for tool  200 . Therefore, the pressure differential is communicated through the pressure sensing line  150  into tool  400 . The differential pressure travels down the center of the tool  400  through the sub bore  210  and a mandrel bore  375  then exits out port  235  into cavity  380 . As the fluid pressure builds up in the cavity  380 , a force is created which acts upon a large piston area  360  that is formed between a plurality of outer O-rings  355  disposed on the outer surface of a piston  385  and a plurality of inner O-rings  345  disposed between the inner mandrel  370  and the piston  385 .  
         [0050]    [0050]FIG. 8 is an enlarged view illustrating the large piston area  360  prior to setting the slips  275 . As illustrated on FIG. 8, the inner O-rings  345  create a fluid tight seal between the piston  385  and mandrel  370 . However, the piston  385  does not initially move because an opposite force created by the hydrostatic pressure outside the tool  400  is communicated into a cavity  395  through a port  405  formed in the piston  385  and acts against an inner piston surface  390 . As more fluid pressure is communicated down the center of the tool  400 , the force acting against large piston area  360  increases until a point is reached when the fluid pressure force acting against the large piston area  360  becomes larger than the hydrostatic pressure force acting against the inner piston surface  390 . At this point, the fluid pressure force in the tool  400  causes a shear pin  410  to fail and urges the piston  385  towards the bent sub (not shown).  
         [0051]    [0051]FIG. 9 illustrates the downhole tool  400  after the packing element  305  and slips  275  are set in the surrounding casing  30 . As illustrated, the piston  385  has moved up against slips  275  and housing  285 . At a predetermined force, pin  415 , which secures the housing  285  to an upper cone  290  fails allowing the upper portion of the slips  275  to ride up the tapered portion  292  of the upper cone  290 . As additional fluid force is pumped into the tool  400 , the force acting on the large piston area  360  continues to increase, thereby causing the pin  420  to fail. At this point, a tapered portion  425  on the piston  385  is wedged under the slips  275  causing the slips  275  to move radially outward engaging the surrounding casing  30 . In this manner, the slips  275  are set into the casing  30  securing the tool  400  downhole.  
         [0052]    After the tool  400  is secured within the casing  30 , the packing element  305  may be expanded, thereby sealing off a portion of the wellbore  60 . Generally, an uphole mechanical force is applied axially downward on the drill string (not shown) and subsequently to the downhole tool  400  in the same manner as previously described. As the mechanical force is applied to the downhole tool  400 , the slips  275  hold the lower portion of the tool  400  stationary while the bent sub  205  and the mandrel  370  are urged axially downward compressing packing element  305  against the cone extension  315 . Thereafter, the packing element  305  is urged radially outward into contact with the surrounding casing  30 . In this manner, expanding the packing element  305  may seal off the wellbore  60 .  
         [0053]    [0053]FIG. 10 is an enlarged view illustrating a small piston area  365  after the slips  275  are set. In addition to expanding the packing element  305 , the downward mechanical force changes the location of the mandrel  370 , thereby changing the piston area from the large piston area  360  to the small piston area  365 . The small piston area  365  is formed between the plurality of outer O-rings  355  disposed on the outer surface of the piston  385  and a middle O-ring  350  disposed on the mandrel  370 . As shown on FIG. 10, the mandrel  370  has moved axially toward the lower end of the tool  400 . The downward movement of mandrel  370  creates a gap  430  between the inner O-rings  345  and the mandrel  370 . In other words, the gap  430  breaks the fluid tight seal created between the mandrel  370  and the piston  385 , thereby allowing fluid communication past the inner O-rings  345  into the cavity  380 . Additionally, the middle O-ring  350  disposed on the mandrel  370  contacts an inner surface  435  to create a fluid tight seal between the piston  385  and the mandrel  370 . Therefore, any fluid in the cavity  380  no longer acts upon the large piston area  360  but rather acts upon a small piston area  365 . In this respect, the smaller piston area  365  reduces the forces on the tool  400 , such as the shear release when the tool  400  is under pressure. In other words, the small piston area  365  allows the tool  400  to operate in high downhole pressure where there is a large pressure differential between the internal and the external portions of the tool  400 . Additionally, the sealing element  305  and slips  275  are shear released from the surrounding casing by shearing pin  440  in a similar manner as described for downhole tool  200 , thereby allowing the downhole tool  400  to be removed from the wellbore  60 .  
         [0054]    [0054]FIG. 11 is a cross-sectional view illustrating an alternative embodiment of an actuation apparatus  500  in the run-in position. As shown, actuation apparatus  500  has similar components as actuation apparatus  100 . Therefore, for convenience, similar components in actuation apparatus  500  will be illustrated with the same number used in the actuation apparatus  100 . The apparatus  500  includes an inner sleeve  515  that moves between a first position and a second position. A biasing member called an inner spring  505  biases the inner sleeve  515  upward in the first position. The spring  505  is constructed and arranged to shift inner sleeve  515  to the second position at a predetermined flow rate through the actuation apparatus  500 . The force exerted upon the inner spring  505  is determined by the flow rate and pressure of fluid through apparatus  500 .  
         [0055]    Inner sleeve  515  includes restriction  120  in the inner diameter thereof, which serves to restrict the flow of fluid through tubular member  105 . As fluid passes through actuation apparatus  500  and encounters restriction  120 , the pressure of the fluid drops in the region  160  directly below restriction  120  and increases in a region  155  directly above restriction  120  thereby creating a pressure differential between the two regions  155 ,  160 . Conversely, the velocity of the fluid decreases in area  155  and increases in area  160 . The inner sleeve  515  further includes O-rings  540 ,  545  disposed on the outer surface of the inner sleeve  515  to create a fluid tight seal between the inner sleeve  515  and an outer sleeve  520 . Additionally, the pressure port  140  is formed in a wall of tubular member  105 . Connected in fluid communication to pressure port  140  through the fitting  145  is the pressure sensing line  150 . As depicted in FIG. 11, when the upper actuation apparatus  500  is not activated, the pressure sensing line  150  is in communication with lower pressure region  160  below the restriction  120 .  
         [0056]    The outer sleeve  520  is disposed on the inner surface of the actuation apparatus  500 . The outer sleeve  520  is shifts between a first and a second position. As illustrated, the outer sleeve  520  is biased in the first position by an outer spring  510 . The outer spring  510  is constructed and arranged to allow the outer sleeve  520  to shift to the second position at a predetermined flow rate through the actuation apparatus  500 . As depicted, O-rings  530 ,  535  are disposed around the outer surface of the outer sleeve  520  to create a fluid tight seal between the outer sleeve  520  and the tubular member  105 . Additionally, an upper port  525  and a lower port are formed in the outer sleeve  520  to allow fluid communication between regions  155 ,  160  and the port  140 .  
         [0057]    [0057]FIG. 12 is a cross-sectional view illustrating the flow rate through the actuation apparatus  500  to operate the MWD device (not shown). The actuation apparatus  500  is constructed and arranged to pass a flow rate of fluid therethrough sufficient to operate a MWD device located in a running string without actuating a hydraulically operated tool (not shown) therebelow. During operation of the MWD, fluid is pumped through the actuation apparatus  500  at a level that creates a force in the restriction  120  sufficient to overcome the inner spring  505 , causing the inner sleeve  515  to move to the second position. At this point, the fluid communication through the lower port  550  and the port  140  is blocked as illustrated on FIG. 12. In this manner, the MWD may be operated without actuating the downhole tool. After operation of the MWD, the flow rate may be increased to that level that creates a force sufficient to overcome the outer spring  510  as shown in FIG. 13.  
         [0058]    [0058]FIG. 13 is a cross-sectional view illustrating the flow rate through the actuation apparatus  500  to actuate the downhole tool (not shown). In order to actuate the apparatus  500 , fluid at a predetermined flow rate is applied through tubular member  105 . As the fluid moves through restriction  120 , pressure rises in region  155 . At a predetermined flow rate, the force at restriction  120  is adequate to overcome the outer spring  510 . Thereafter, the outer sleeve  520  will move to the second position against shoulder  530  as illustrated in FIG. 13. At the same time, the actuation apparatus  500  places the pressure sensing line  150  in fluid communication with region  155  above the restriction  120 . In this respect, the pressure sensing line  150  is exposed to the higher pressure created by the flow of fluid through restriction  120 . The pressure sensing line  150  communicates the higher pressure in the same manner as described in the actuation apparatus  100 .  
         [0059]    [0059]FIG. 14 is a cross-sectional view illustrating the flow rate through the actuation apparatus  500  after the downhole tool (not shown) is actuated. As the flow rate decreases, the force in the restriction  120  becomes insufficient to overcome the outer spring  510 , causing the outer sleeve  520  to move from the second position to the first position. As further illustrated, the port  140  remains isolated to prevent the possibility of erosion and damage to the downhole tool during the milling operation. Subsequently, the flow rate is further decreased allowing the apparatus  500  to return to the run-in position as illustrated on FIG. 11.  
         [0060]    [0060]FIG. 15 is a cross-sectional view illustrating an alternative embodiment of an actuation apparatus  600 . As shown, actuation apparatus  600  has similar components as actuation apparatus  100 . Therefore, for convenience, similar components in actuation apparatus  600  will be illustrated with the same number used in the actuation apparatus  100 . As previously discussed for tool  200 , the hydrostatic pressure enters the housing port  260  from wellbore fluid in the annulus (not shown). Alternatively, the hydrostatic pressure may be communicated to the housing port  260  through a low-pressure line  605 . The low-pressure line  605  is connected to a fitting  615  housed in a low-pressure port  610  formed in a wall of tubular member  105 . The low-pressure port  610  is in fluid communication with region  160  directly below restriction  120 . In this respect, the actuating apparatus  600  completely eliminates any effective pressure drop across the mill face, thereby providing an effective means of actuating the tool  200 .  
         [0061]    [0061]FIG. 16 is a cross-sectional view illustrating an alternative embodiment of an actuation apparatus. As shown, actuation apparatus  700  has similar components as actuation apparatus  100 . Therefore, for convenience, similar components in actuation apparatus  700  will be illustrated with the same number used in the actuation apparatus  100 . As previously discussed for actuation apparatus  100 , the tool (not shown) is activated or triggered by a differential pressure in regions  155 ,  160  created by fluid flow through the restriction  120 . However, flow rate may vary due to pulsing of the pumps and other restrictions in the flow line. Therefore, the embodiment illustrated in actuation apparatus  700  contains a control feature that allows the tool to be activated or triggered at a predetermined pressure. As shown, a single use valve or a rupture disk  705  is placed in the pressure port  140 . In addition, a fluid port  710  fluidly connects region  160  to the pressure port  140  to form a Y block. In the embodiment shown, the single use valve is a rupture disk to permit activation of the tool at a predetermined pressure. However, other forms of single use valves may be employed, such as a pressure relief valve, so long as they are capable of allowing activation of the tool at a predetermined pressure. In operation, the actuation apparatus  700  functions in the same manner as previously discussed for actuation apparatus  100 . However, the rupture disk  705  in the actuation apparatus  700  buffers out fluid pulses created by the pumps by requiring a threshold trigger pressure to be reached prior to activation of the tool. In this respect, the actuation apparatus  700  provides an external control feature to activate the tool rather than relying on the shear screws internal to the tool.  
         [0062]    [0062]FIG. 17 is a cross-sectional view illustrating an alternative embodiment of an actuation apparatus  800  with a hydraulic isolation device  805 . As shown, actuation apparatus  800  has similar components as actuation apparatus  100 . Therefore, for convenience, similar components in actuation apparatus  800  will be illustrated with the same number used in the actuation apparatus  100 . In this embodiment, the restriction  120  is used as a seat  810  for a hydraulic isolation device  805 . In the embodiment shown, the hydraulic isolation device  805  is a ball. However, other forms of hydraulic isolation devices may be employed, such as a dart, so long as they are capable of restricting the flow of fluid through the tubular member  105 . The hydraulic isolation device  805  may be dropped from the surface of the wellbore (not shown) into the drill string (not shown). Thereafter, the hydraulic isolation  805  device would flow through the tubular member  105  and land in the seat  810 . As fluid is pumped through the drill string and subsequently through the actuation apparatus  800 , the hydraulic isolation device  805  would restrict the flow through the tubular member  105  and create a pressure in the region  155 . The higher pressure is communicated through the slit  115  of the sand tube  110  to the pressure port  140  and subsequently through the pressure sensing line  150  to activate the tool (not shown) as described in the previous paragraph.  
         [0063]    [0063]FIG. 18 is a cross-sectional view illustrating the removal of the hydraulic isolation device  805  from the actuation apparatus  800 . After the tool (not shown) has been hydraulically actuated, the fluid flow rate may be increased to remove the hydraulic isolation device  805  from the seat  810 . For example, if the isolation device  805  is a ball, the flow rate may be increased to create a force on the ball, whereby at a predetermined force the ball explodes and the residue is washed out through the flow ports  135  as illustrated in FIG. 18.  
         [0064]    In operation, a sidetrack system is disposed in a wellbore. The sidetrack system is useful for offsetting a wellbore by directing a drill bit or cutter at an angle from the existing wellbore. The sidetrack system typically includes a window mill, an actuation apparatus, a MWD, a deflector and a downhole tool such as an anchor-packer. To operate the sidetrack system and actuate the downhole tool fluid is pumped from the surface of the wellbore through a drill string and subsequently through the actuation apparatus. As fluid passes through the actuation apparatus and encounters a restriction, the pressure of the fluid drops in a region directly below the restriction and increases in the region directly above the restriction, thereby creating a pressure differential between the two regions. The pressure differential is communicated into a slit in the sand tube through the annular area into the pressure port and subsequently through the pressure sensing line into the center of the tool. Thereafter, the fluid pressure enters a cavity through a body port that formed at the lower end of the lower body. As the fluid pressure builds up in the cavity a force is created which acts upon a lower piston surface.  
         [0065]    Generally, the more fluid pressure communicated down the center of the tool, the more force acting against lower piston surface until a point is reached when the force on the lower piston surface becomes larger than the opposite force acting against the upper piston surface. At this point, the piston is urged upwards toward the bent sub. The movement of the piston causes a plurality of shear members to fail and subsequently urges the tapered portions on the lower cone and upper cone to wedge under the slips causing the slips to move radially outward into contact with the casing. Thereafter, an uphole mechanical force is applied axially downward on the drill string and subsequently applied to the downhole tool. As the mechanical force is applied to the downhole tool, the slips hold the lower portion of the tool stationary while a bent sub and a stinger are urged axially downward compressing the packing element against the cone extension, thereby causing the packing element radially outward into contact with the surrounding casing. In this manner, the downhole tool is operated in the wellbore.  
         [0066]    The downhole tool may be removed from the wellbore after the milling operation is complete. Typically, the window mill, actuation apparatus, and MWD are removed from the wellbore after the milling operation, while the deflector and the downhole tool remain in the wellbore. Subsequently, a drill string and fishing tool are employed in the well to attach to the deflector. Soon after attachment, the drill string and fishing tool are pulled axially upward causing the deflector to move axially upward and create an axially upward force on the downhole tool. The axially upward force causes the packing element and slips to release allowing the downhole tool and the deflector to be removed from the wellbore.  
         [0067]    While the foregoing is directed to embodiments of the present invention, other and further embodiments of the invention may be devised without departing from the basic scope thereof, and the scope thereof is determined by the claims that follow.