Abstract:
An expandable downhole tool comprises a tubular body, at least one moveable arm disposed within the tubular body and being radially translatable between a retracted position and a wellbore engaging position, and at least one piston operable to mechanically support the at least one moveable arm in the wellbore engaging position when an opposing force is exerted. A method of reaming a formation to form an enlarged borehole in a wellbore comprising disposing an expandable reamer in a retracted position in the wellbore, expanding at least one movable arm of the expandable reamer radially outwardly into engagement with the formation, reaming the formation with the at least one moveable arm to form the enlarged borehole; and mechanically supporting the at least one moveable arm in the radially outward direction during reaming.

Description:
CROSS-REFERENCE TO RELATED APPLICATIONS 
   The present application claims the benefit under 35 U.S.C. § 119 of U.S. provisional application Ser. No. 60/468,767 filed May 8, 2003 and entitled “Concentric Expandable Reamer”, hereby incorporated herein by reference for all purposes. 

   STATEMENT REGARDING FEDERALLY SPONSORED RESEARCH OR DEVELOPMENT 
   Not Applicable. 
   BACKGROUND OF THE INVENTION 
   1. Field of the Invention 
   The present invention relates generally to expandable downhole tools. More particularly, the present invention relates to a concentric expandable downhole tool having fewer components and thus a shorter length than conventional expandable tools. Still more particularly, the present invention relates to a robust, concentric expandable reamer having an advanced cutting structure and a mechanical/hydraulic activation mechanism. 
   2. Description of the Related Art 
   In the drilling of oil and gas wells, a plurality of casing strings are installed concentrically and then cemented into the borehole as drilling progresses to increasing depths. Thus, each new casing string is supported within the previously installed casing string, such that the largest diameter casing string is disposed at the uppermost end of the borehole and the smallest diameter casing string is disposed at the lowermost end of the borehole. 
   As successively smaller diameter casing strings are suspended, the annular area between the casing and the borehole wall is increasingly limited for the cementing operation. Further, as successively smaller diameter casing strings are suspended, the flow area for the production of oil and gas is reduced. Therefore, to increase the annular space for the cementing operation, and to increase the production flow area, it is often desirable to enlarge the borehole below the terminal end of the previously cased borehole. By enlarging the borehole, a larger annular area is provided for subsequently installing and cementing a larger casing string than would have been possible otherwise. Further, by enlarging the borehole, the bottom of the formation can be reached with comparatively larger diameter casing, thereby providing a larger flow area for the production of oil and gas. 
   Various methods have been devised for passing a drilling assembly through an existing cased borehole and enlarging the borehole below the casing. One such method includes using a winged reamer behind a conventional drill bit. In such an assembly, a conventional pilot drill bit is disposed at the lowermost end of the drilling assembly with a winged reamer disposed at some distance behind the drill bit. The winged reamer generally comprises a tubular body with one or more longitudinally extending “wings” or blades projecting radially outwardly from the tubular body. Once the winged reamer has passed through any cased portions of the wellbore, the pilot bit rotates about the centerline of the drilling axis to drill a lower borehole on center in the desired trajectory of the well path, while the eccentric winged reamer follows the pilot bit and engages the formation to enlarge the pilot borehole to the desired diameter. 
   Another method for enlarging a borehole below a previously cased borehole section includes using a bi-center bit, which is a one-piece drilling structure that provides a combination reamer and pilot bit. The pilot bit is disposed on the lowermost end of the drilling assembly, and the eccentric reamer bit is disposed slightly above the pilot bit. Once the bi-center bit has passed through any cased portions of the wellbore, the pilot bit rotates about the centerline of the drilling axis and drills a pilot borehole on center in the desired trajectory of the well path, while the eccentric reamer bit follows the pilot bit and engages the formation to enlarge the pilot borehole to the desired diameter. The diameter of the pilot bit is made as large as possible for stability while still being capable of passing through the cased borehole. Examples of bi-center bits may be found in U.S. Pat. Nos. 6,039,131 and 6,269,893. 
   As described above, winged reamers and bi-center bits each include reamer portions that are eccentric. A number of disadvantages are associated with this design. In particular, due to directional tendency problems, these eccentric reamer portions have difficulty reliably enlarging the borehole to the desired diameter. With respect to a bi-center bit, the eccentric reaming section tends to cause the pilot bit to wobble and undesirably deviate off center, and any off-center rotation will cause the reaming section to drill an enlarged borehole that is undersized. A similar problem is experienced with respect to winged reamers, which only enlarge the borehole to the desired diameter if the pilot bit remains centralized in the borehole during drilling. Accordingly, it is desirable to provide a reamer that remains concentrically disposed in the borehole while enlarging the previously drilled borehole to the desired diameter. 
   There are several different types of concentric reamers, which are used in conjunction with a conventional pilot drill bit positioned below or downstream of the reamer. The pilot bit drills the borehole while the reamer follows to enlarge the borehole formed by the bit. One type of concentric reamer is a fixed-blade reamer, which includes a plurality of concentric blades (sometimes also referred to as arms) with cutters on the ends extending radially outwardly and spaced azimuthally around the circumference of the reamer housing. The outer edges of the blades contact the wall of the existing cased borehole, thereby defining the maximum reamer diameter that will pass through the casing, and also defining the maximum diameter of the enlarged borehole. Thus, although a fixed-blade reamer remains concentrically disposed as it rotates to enlarge the borehole, it is limited to enlarging the borehole only to the drift diameter of the existing cased borehole, whereas winged reamers and bi-center bits can enlarge the borehole beyond the drift diameter of the casing. Accordingly, a fixed-blade reamer often will not enlarge the borehole to the desired diameter. 
   More recently, concentric expandable reamers have been developed. Most expandable reamers have two operative states—a closed or retracted state, where the diameter of the tool is sufficiently small to allow the tool to pass through the existing cased borehole, and an open or expanded state, where one or more arms with cutters on the ends thereof extend from the body of the tool. In this latter position, the reamer enlarges the borehole diameter to the required size as the reamer is rotated and lowered in the borehole. 
   Expandable reamers are available in a variety of configurations, each having different activation mechanisms and blade configurations. One type of expandable reamer includes hinged arms with roller cone cutters attached thereto. This type of reamer may utilize swing out cutter arms that are pivoted at an end opposite the cutting end of the arms. The cutter arms are actuated by mechanical or hydraulic forces acting on the arms to extend or retract them. Typical examples of this type of reamer are found in U.S. Pat. Nos. 3,224,507; 3,425,500 and 4,055,226, and they have several disadvantages. First, the pivoted arms may break during the drilling operation, requiring that the arms be removed or “fished” out of the borehole before the drilling operation can continue. Accordingly, due to the limited strength of the pivoted arms, this type of reamer may be incapable of underreaming harder rock formations, or may have unacceptably slow rates of penetration. Further, if the pivoted arms do not fully retract, the drill string may easily hang up when attempting to remove it from the borehole. Therefore, it would be advantageous to provide a reamer that is more robust and has improved blade retraction mechanisms. 
   Other expandable reamers are activated by weight-on-bit to extend the blades. With such designs, the internal components of the reamer rather than the reamer body support the weight of drilling assembly components extending below the reamer. Accordingly, if too much weight is applied to the internal components, the reamer may not have enough hydraulic power to lift the weight below the reamer, and the reamer will not open. Further, it may not be possible to set weight-on-bit when the reamer should be activated to extend the blades. Also, during drilling, the weight-on-bit is sometimes unevenly distributed, and a false indication may be provided to the surface that the reamer blades are expanded when they are not. 
   Still other types of expandable reamers are activated by hydraulic or differential pressure, sometimes in combination with a mechanical component. With such designs, there is no certainty that all of the blades will be fully extended because the blades do not activate in unison. Therefore, one blade might extend while another blade is stuck in a partially extended position. Further, in some embodiments, drilling fluid pressure is the only force holding the blades in an extended position. Thus, if the strength of the formation is greater than the fluid pressure, the blades will partially retract and drill an undersized borehole. Some embodiments include a mechanical component, such as, for example, a piston with a continuously tapered surface that engages the blades to drive them radially outwardly as the piston moves downwardly. In such embodiments, the piston is activated by hydraulic pressure to drive the blades radially outwardly, but if the strength of the formation is greater than the fluid pressure, the blades will tend to retract along the continuously tapered surface. Thus, existing expandable reamers raise such concerns as whether the tool will expand to the desired borehole diameter when required, whether the tool will remain in the expanded position to enlarge the borehole to the desired diameter, and whether the tool will reliably retract prior to re-entering the casing as the drilling assembly is removed from the borehole. 
   Further, most expandable tools include a large number of moving parts, thereby increasing the probability of malfunction. The number of moving parts also affects the tool length, which may be up to 14 feet long, for example. There are also disadvantages associated with existing reamer blades. Specifically, to adjust the expanded diameter of the reamer, the entire arm must be removed and replaced, or in some cases, a different reamer may be required. Further, most blades fail to include pads on the gage configuration for stability and durability, or if pads are included, the blades fail to include active cutting structures near the pads. 
   The present invention addresses the deficiencies of the prior art. 
   SUMMARY OF THE INVENTION 
   In various embodiments, the concentric expandable tool that may be used as a reamer to enlarge the diameter of a borehole below a restriction, or alternatively, may be used as any other type of downhole expandable tool, such as a stabilizer, for example, depending upon the configuration of the blades. 
   An expandable downhole tool is disclosed for use with a drilling assembly in a wellbore comprising a tubular body, at least one moveable arm disposed within the tubular body and being radially translatable between a retracted position and a wellbore engaging position, and at least one piston operable to mechanically support the at least one moveable arm in the wellbore engaging position when an opposing force is exerted. In an embodiment, the piston is axially translatable in response to a differential pressure between an axial flowbore within the tool and the wellbore. In an embodiment, the moveable arm includes at least one set of cutting structures for reaming the wellbore in the wellbore engaging position. The moveable arm may also comprise a back-reaming cutter. The expandable downhole tool may further comprise at least one gage pad for stabilizing the drilling assembly in the wellbore engaging position. The gage pad may be removable and replaceable. Cutters may also be provided adjacent the at least one gage pad. In an embodiment, the tool further comprises a sliding sleeve biased to isolate the at least one piston from the axial flowbore, thereby preventing the at least one moveable arm from translating between the retracted position and the wellbore engaging position. A droppable or pumpable actuator may be provided for aligning the sliding sleeve to expose the at least one piston to the axial flowbore. In an embodiment, the tool further comprises at least one nozzle disposed adjacent the at least one moveable arm. 
   Also disclosed is a method of reaming a formation to form an enlarged borehole in a wellbore comprising disposing an expandable reamer in a retracted position in the wellbore, expanding at least one movable arm of the expandable reamer radially outwardly into engagement with the formation, reaming the formation with the at least one moveable arm to form the enlarged borehole; and mechanically supporting the at least one moveable arm in the radially outward direction during reaming. The method may further comprise back-reaming the formation with the at least one moveable arm. In an embodiment, the method further comprises flowing a fluid through the expandable reamer, and selectively driving the at least one movable arm radially outwardly in response to the flowing fluid. The method may further comprise mechanically retracting the at least one moveable arm radially inwardly. In an embodiment, the method further comprises flowing a portion of the fluid across a wellbore engaging portion of the at least one moveable arm. The method may further comprise providing a pressure indication during or after the at least one moveable arm is expanded radially outwardly. In an embodiment, the method further comprises providing stability and gage protection as the reaming progresses. The method may further comprise removing and/or replacing a formation engaging portion of the expandable reamer without removing the at least one moveable arm. In an embodiment, the expanding step is performed without substantially axially moving the expandable reamer within the wellbore. 
   Further, an expandable downhole tool is disclosed for use in a drilling assembly positioned within a wellbore comprising a tubular body including an axial flowbore extending therethrough, a piston disposed within the axial flowbore having at least one cam portion with a substantially flat surface, and at least one moveable arm engaging the piston, wherein the piston is axially translatable in response to a differential pressure between the axial flowbore and the wellbore, and wherein the at least one moveable arm is radially translatable between a retracted position and an expanded position. In an embodiment, the substantially flat surface on the cam portion engages a substantially flat surface on the at least one moveable arm in the expanded position. The at least one cam portion may further comprise a tapered piston surface that engages a tapered blade surface on the at least one moveable arm as the at least one moveable arm is radially translated from the retracted position to the expanded position. In an embodiment, the piston comprises a plurality of cam portions separated by at least one notch. The at least one moveable arm may comprise at least one blade portion that resides in the at least one notch in the retracted position. 
   The expandable downhole tool may further include a biasing spring to bias the at least one moveable arm to the retracted position. The biasing spring may comprise at least one radial spring. In various embodiments, the biasing spring is disposed in a spring chamber filled with fluid from the wellbore or in an oil-filled spring chamber. The at least one moveable arm may further comprise a tapered surface to engage a casing and radially translate the arm from the expanded position to the retracted position. The at least one moveable arm may include a plurality of cylindrical blades. In an embodiment, the blades comprise a fixed blade portion and a removeable blade portion. In various embodiments, the at least one moveable arm includes at least one set of cutting structures, at least one gage pad, a back-reaming cutter, or a combination thereof. In an embodiment, the tool comprises three moveable arms each having a gage surface area, which may include at least one cutting structure and at least one gage pad area. The combination of the gage surface areas of the three moveable arms may comprise a complete overlap of an aggressive cutting structure and a complete overlap of a smooth gage pad. 
   The tool may further comprise ports in fluid communication with the flowbore and the piston. In an embodiment, the tool further comprises a sliding sleeve biased to close the ports, thereby preventing the at least one moveable arm from translating between the retracted position and the expanded position in response to the differential pressure. A bullet actuator may be provided for aligning the sliding sleeve to open the ports. In an embodiment, the at least one moveable arm is radially translatable between the retracted position and the expanded position via a combination of hydraulic and mechanical activation. The tool may further comprise shear pins that prevent the at least one moveable arm from radially translating to the expanded position until the differential pressure is sufficient to break the shear pins. In an embodiment, the tool further comprises at least one nozzle disposed adjacent the at least one moveable arm. The tool may be shorter than about 14-feet, and in an embodiment, the tool is approximately 4-feet long. 
   Also disclosed is a drilling assembly comprising an expandable downhole tool wherein the tool is positionable anywhere on the drilling assembly upstream of the drill bit. 
   Thus, the concentric expandable tool comprises a combination of features and advantages that enable it to overcome various problems of prior devices. The various characteristics described above, as well as other features, will be readily apparent to those skilled in the art upon reading the following detailed description of the preferred embodiments of the invention, and by referring to the accompanying drawings. 

   
     BRIEF DESCRIPTION OF THE DRAWINGS 
     For a more detailed description of the various embodiments of the concentric expandable tool, reference will now be made to the accompanying drawings, wherein: 
       FIG. 1  is a cross-sectional side view of one embodiment of a concentric expandable tool with removeable arms in the retracted position; 
       FIG. 2  is an external perspective view of the expandable tool of  FIG. 1  in the retracted position; 
       FIG. 3  is a cross-sectional side view of the expandable tool of  FIG. 1 , with the moveable arms in the expanded position; 
       FIG. 4  is an external perspective view of the expandable tool of  FIG. 1  in the expanded position; 
       FIG. 5  is an enlarged, cross-sectional side view of a piston engaging blades on a moveable arm of the expandable tool of  FIG. 1 ; 
       FIG. 6  is a cross-sectional side view of another embodiment of a concentric expandable tool with a pressure compensation system, with the moveable arms in the retracted position; 
       FIG. 6A  is an enlarged, cross-sectional side view of a portion of  FIG. 6 ; 
       FIG. 7  is a cross-sectional side view of the concentric expandable tool of  FIG. 6 , with the moveable arms in the expanded position; 
       FIG. 7A  is an enlarged, cross-sectional side view of a portion of  FIG. 7 ; 
       FIG. 8  is an enlarged cross-sectional side view of one embodiment of a moveable arm; 
       FIG. 9  is an enlarged cross-sectional side view of another embodiment of a moveable arm having removable blade portions; 
       FIG. 10  is an enlarged cross-sectional side view of the moveable arm of  FIG. 9 , with the removable blade portions separated from fixed blade portions; 
       FIG. 11  is top plan view of three moveable arms with one embodiment of a gage configuration; 
       FIG. 12  is a cross-sectional side view of an exemplary bullet activation mechanism before a bullet has landed on a sliding sleeve; 
       FIG. 13  is a cross-sectional side view of the bullet activation mechanism of  FIG. 12  with the bullet seated on the sliding sleeve; 
       FIG. 14  is a cross-sectional side view of the bullet activation mechanism of  FIG. 12  with the bullet driven downwardly to open fluid ports leading to the tool piston; 
       FIG. 15  is a cross-sectional side view of the bullet activation mechanism of  FIG. 12  with the tool piston moved downwardly to expand the tool arms; 
       FIG. 16  is a cross-sectional side view of an exemplary centrifugal activation mechanism in the locked position; 
       FIG. 17  is a cross-sectional side view of the centrifugal activation mechanism of  FIG. 16  in the unlocked position to open fluid ports leading to the tool piston; and 
       FIG. 18  is a cross-sectional side view of the centrifugal activation mechanism of  FIG. 16  in the unlocked position and with the tool piston moved downwardly to expand the tool arms. 
   

   DETAILED DESCRIPTION 
   The concentric expandable tool is susceptible to embodiments of different forms. There are shown in the drawings, and herein will be described in detail, specific embodiments of the tool with the understanding that the disclosure is to be considered an exemplification of the principles of the tool, and is not intended to limit the tool to that illustrated and described herein. 
   In particular, various embodiments of the concentric expandable tool provide a number of different constructions and methods of operation. Each of the various embodiments may be used to enlarge a borehole, or to perform another downhole function with an expandable tool, such as stabilization, for example. Thus, the concentric expandable tool may be utilized as a reamer, a stabilizer, or as any other type of expandable tool. The various embodiments of the tool also provide a plurality of methods for use in a drilling assembly. It is to be fully recognized that the different teachings of the embodiments disclosed herein may be employed separately or in any suitable combination to produce desired results. 
     FIG. 1  depicts a cross-sectional side view of one embodiment of an expandable tool, generally designated as  100 , in the retracted position, and  FIG. 2  depicts a perspective external view of the retracted tool  100 . Similarly,  FIG. 3  depicts a cross-sectional side view of the tool  100  in the expanded position, and  FIG. 4  depicts a perspective external view of the expanded tool  100 .  FIG. 1  and  FIG. 3  depict the tool  100  in a wellbore  50  thereby forming a wellbore annulus  75  between the tool  100  and the wellbore  50 . The tool  100  comprises an upper section  110  with a flowbore  114  extending therethrough, a generally cylindrical tool body  120  with a flowbore  152  extending therethrough, and an internal sleeve  130  with a flowbore  132  extending therethrough. The flowbores  114 ,  152 ,  132  align axially to form a single flowbore  105  extending through the tool  100 . 
   The upper section  110  includes upper and lower connection portions  116 ,  118  for connecting to a drill string (not shown) and the tool body  120 , respectively. The tool body  120  includes upper and lower connection portions  124 ,  126  for connecting to the upper section  110  via threads  119  and a drilling assembly (not shown), respectively. The sleeve  130  is disposed within the lower connection end  126  of the tool body  120 . 
   One or more outer pockets  127  are formed through the wall  122  of the body  120  and spaced apart azimuthally around the circumference of the body  120  to accommodate the radial movement of one or more moveable tool arms  160 . Each pocket  127  stores one moveable arm  160  in the retracted position as shown in  FIGS. 1-2 . The arms  160  are biased inwardly to the retracted position by radial springs (not shown) disposed behind dovetail blocks  170 ,  172  that may have flow ports  174 ,  176  extending therethrough to allow fluid flow between the wellbore annulus  75  and the pockets  27 . The flow ports  174 ,  176  may also be provided in other locations. Thus, the dovetail blocks  170 ,  172  retain radial springs that bias the arms  160  radially inwardly to the retracted position of  FIGS. 1-2 . In another embodiment, the dovetail blocks  170 ,  172  are eliminated, and the tool body  120  forms a solid section in the vicinity of the arms  160 . In this embodiment, the arms  160  are biased inwardly to the retracted position by radial springs (not shown) disposed between the solid section of the tool body  120  and the arms  160 . Preferably, the expandable tool  100  includes three moveable arms  160  disposed within three pockets  127 , and spaced apart azimuthally at 120° from one another. In the discussion that follows, the one or more pockets  127  and the one or more arms  160  may be referred to in the plural form, i.e. pockets  127  and arms  160 . Nevertheless, it should be appreciated that the scope of the present invention also comprises one pocket  127  and one arm  160 . 
   The body  120  further includes an internal axial recess  128  to accommodate the axial movement of in internal piston  150  having an upper tapered surface  154  that engages the upper section  110  and connecting at its lower end to the sleeve  130  via threads  159 . The piston  150  includes cam portions  153 ,  155 ,  157  that provide a drive mechanism for the moveable tool arms  160  to move radially outwardly to the expanded position of  FIGS. 3-4 . The piston  150  further includes a leg portion  156  that will engage a shoulder  129  at the lower end of the recess  128  in the body  120  when the piston  150  travels. Thus, the shoulder  129  limits the axial movement of the piston  150 . The piston  150  sealingly engages the body  120  at  102 ,  104 ,  106 , and the sleeve  130  sealingly engages the body  120  at  108 ,  109 . The uppermost seal  102  and the lowermost seal  109  are pressure containing to prevent fluid from the flowbore  105  from getting into the internal recesses  128  and  142 , respectively. 
   A biasing spring  140  is provided to bias the piston  150  upwardly, thereby moving the cam portions  153 ,  155 ,  157  away from engagement with the arms  160  so that the radial springs behind the dovetail blocks  170 ,  172  can bias the arms  160  to the retracted position of  FIG. 1 . Thus, the arms  160  are moved inwardly in a separate operation from the upward axial movement of the piston  150 . The biasing spring  140  is disposed within a spring chamber  142  surrounding the sleeve  130 , which is filled with drilling fluid that enters the spring chamber  142  from the wellbore annulus  75  via ports  144  extending through the wall  122  of the body. Because drilling fluid can enter the spring chamber  142  through ports  144 , there is no need for a pressure compensation system for the biasing spring  140 . Thus, as the biasing spring  140  collapses or expands, the ports  144  allow for volume changes within the spring chamber  142 , as needed. The lower end of the biasing spring  140  engages a stop  146 , and the upper end of the biasing spring  140  engages a shoulder  134  on the sleeve  130 . 
   Below the moveable arms  160 , one or more nozzles  125  extend at an angle through the wall  122  of the body  120 . The number and position of nozzles  125  may correspond to the number and position of the arms  160 , for example, or the nozzles  125  may be positioned away from the arms  160 . The piston  150  includes apertures  158  that extend therethrough. With the tool  100  in the retracted position of  FIGS. 1-2 , the piston  150  blocks flow to the nozzles  125 . However, when the tool  100  is in the expanded position of  FIGS. 3-4 , the apertures  158  in the piston  150  align with the nozzles  125  to allow fluid communication between the piston flowbore  152  and the wellbore annulus  75 . Seals  104 ,  106  are provided around the apertures  158  to prevent fluid from flowing above and below the seals  104 ,  106  when the apertures  158  are aligned with the nozzle  125 . 
   The moveable arms  160  include cylindrical blades  162 ,  164 ,  166  that fit within notches  151  in the piston  150  when the tool  100  is in the retracted position of  FIGS. 1-2 . The blades  162 ,  164 ,  166  are provided with structures  180 ,  190  that engage the borehole  50  when the arms  160  are extended outwardly to the expanded position of the tool  100  shown in  FIGS. 3-4 . In the expanded position, the arms  160  will ream the borehole  50  and/or stabilize the drilling assembly, depending upon how the blades  162 ,  164 ,  166  are configured. In the configuration of  FIGS. 1-4 , cutting structures  180  on blades  164 ,  166  ream the borehole  50 , while a gage pad  190  on blade  162  provides stabilization and gage protection as the reaming progresses. Although the embodiment of tool  100  depicted in  FIGS. 1-4  comprises three blades  162 ,  164 ,  166 , a different number of blades may be provided on each arm  160 . Providing three blades  162 ,  164 ,  166  with cutting structures  180  on two of the blades  164 ,  166  increases the cutting capacity of the tool  100  as compared to conventional tools, which typically have only one blade. All three of the blades  162 ,  164 ,  166  may include cutting structures  180  so that back-reaming capabilities are provided. Alternatively, the expandable tool  100  could easily be converted into a concentric, expandable stabilizer by providing gage pads  190  on all three blades  162 ,  164 ,  166  rather than cutting structures  180  on blades  164 ,  166 . 
   During assembly, the arms  160  are positioned within the pockets  127  of the body  120 . Then the piston  150  is installed so that the blades  162 ,  164 ,  166  reside within notches  151  between cam portions  153 ,  155 ,  157  on the piston  150 . The sleeve  130  is threaded onto the piston  150  at  159  with the biasing spring  140  surrounding the sleeve  130 . The biasing spring  140  pushes the piston  150  upwardly until the piston  150  engages the upper section  110 , such that the biasing spring  140  is set to a certain preload. Then, radial springs (not shown) are provided between the cylindrical blades  162 ,  164 ,  166 , and dovetail blocks  170 ,  172  are installed over the radial springs to hold the arms  160  into the retracted position. 
   In operation, the tool  100  is run into the borehole  50  through casing in the retracted position of  FIGS. 1-2 . In one embodiment, shear pins  107  are positioned through the body  120  around the blades  162 ,  164 ,  166  to retain the arms  160  in the retracted position as depicted in  FIG. 1  until drilling fluid is pumped downhole at a pressure sufficient to break the shear pins  107 . After the shear pins  107  break, the differential pressure between the flowbore  105  and the wellbore annulus  75  must overcome the force of the biasing spring  140 . Then drilling fluid engaging the tapered surface  154  of the piston  150  will cause the piston  150  to move downwardly to expand the arms  160  as depicted in  FIG. 3 . The design of the shear pins  107  is rig dependent, such that the shear pin material and the number of shear pins  107  will be determined based upon the desired expansion pressure of a particular tool  100 . In another embodiment, there are no shear pins  107  so that when pressurized drilling fluid reaches the tool  100 , the piston  150  will move downwardly to extend the arms  160 . Thus, the concentric expandable tool  100  will actuate when the differential pressure exceeds the force of the biasing spring  140  that pushes the piston  150  and the sleeve  130  upwardly. 
   Unlike conventional tools, the expandable tool  100  of  FIGS. 1-4  utilizes hydraulic force as well as mechanical force to cause the arms  160  to extend outwardly from the retracted position of  FIGS. 1-2  to the expanded position of  FIGS. 3-4 , and to maintain the arms  160  in the expanded position. When the drilling fluid flows through the flowbore  105  at a pressure sufficient to break the shear pins  107 , and when the differential pressure between the flowbore  105  and wellbore annulus  75  is adequate to overcome the force of the biasing spring  140 , then the piston  150  will move downwardly, thereby creating a gap  205  between the upper tapered surface  154  of the piston  150  and the upper section  110  as shown in  FIG. 3 . Each of the dovetail blocks  170 ,  172  has a port  174 ,  176  extending therethrough that allows fluid from the wellbore annulus  75  to flow into the recess  128  of the body  120 . Therefore, the outer surface of the piston  150  is exposed to wellbore annulus pressure while the piston bore  152  is exposed to pump pressure from the surface. This difference in pressure drives the piston  150  downwardly within the recess  128 , and as the piston  150  moves, the biasing spring  140  compresses, while the piston cam portions  153 ,  155 ,  157  push against the blades  162 ,  164 ,  166  to drive the arm  160  radially outwardly. 
   In more detail,  FIG. 5  depicts an enlarged view of the piston  150  engaging a tool arm  160  in the extended position. Referring first to the piston  150 , the cam portions  153 ,  155 ,  157  each preferably include a steep tapered surface  251 ,  254 ,  258 , respectively, and a substantially flat surface  253 ,  255 ,  257 , respectively. The steep tapered surfaces  251 ,  254 ,  258  may have a 20° taper, and the substantially flat surfaces  253 ,  255 ,  257  may have a slope ranging from approximately 0-5°, for example. With respect to the arms  160 , the blades  162 ,  164 ,  166  each preferably include a tapered surface  261 ,  263 ,  265 , respectively, and a substantially flat bottom surface  262 ,  264 ,  266 , respectively. As depicted in  FIG. 1 , the blades  162 ,  164 ,  166  reside in notches  151  between the piston cam portion  153 ,  155 ,  157  when the arm  160  is in the retracted position. However, when the piston  150  begins to move downwardly, tapered blade surfaces  261 ,  263 ,  265  engage steep tapered piston surfaces  251 ,  254 ,  258 , respectively to begin moving the arm  160  radially outwardly. The piston  150  will continue to move downwardly until the piston leg  156  engages the shoulder  129  within the body recess  128 , which corresponds to the fully expanded position of the arm  160 . Thus, the biasing spring  140  does not entirely support the weight of the piston  150 , but rather the body  120  also supports the weight of the piston  150  at shoulder  129 . 
   When the blades  162 ,  164 ,  166  are in the expanded position of  FIG. 3  and  FIG. 5 , substantially flat surfaces  253 ,  255 ,  257  of the piston cam portions  153 ,  155 ,  157 , respectively, engage substantially flat bottom surfaces  262 ,  264 ,  266  of the cylindrical blades  162 ,  164 ,  166 , respectively. Thus, the substantially flat surfaces  253 ,  255 ,  257  of the piston  150  exert a mechanical force against the flat bottom surfaces  262 ,  264 ,  266  to hold the blades  162 ,  164 ,  166  in the expanded position. In contrast to conventional expandable tools that rely entirely on hydraulic pressure to hold the blades against the formation, the concentric expandable reamer  100  relies on hydraulic pressure to push the piston  150 , but substantially flat surfaces  253 ,  255 ,  257  on the piston  150  mechanically act against the blades  162 ,  164 ,  166  to hold them in place as they cut into the formation. Thus, in terms of activation, the hydraulic pressure does not act directly on the arms  160  but rather acts on the piston  150 , which then mechanically acts on the arms  160  to move them to the expanded position as well as maintain the arms  160  in the expanded position to ream the borehole  50 . 
   In the expanded position of  FIGS. 3-4 , the nozzles  125  that extend at an angle through the wall  122  of the body  120  allow fluid to flow from the flowbore  105  into the wellbore annulus  75 , and this achieves two purposes. Namely, when the piston  150  is moved downwardly to extend the arms  160 , the piston apertures  158  align with the nozzles  125  in the body wall  122  so that fluid flows outwardly from the flowbore  105  of the tool to the wellbore annulus  75 . Because the nozzles  125  are angled, fluid will flow across the blades  164 ,  166  to cool and clean the cutting structures  180 . In addition, the operator at the surface will get an indication that the tool  100  is in the expanded position due to the pressure drop caused by the alignment of the apertures  158  and the nozzles  125  to allow fluid communication between the flowbore  105  and the annulus  75 . 
   Once the surface pumps are shut off to remove the pressure on the expandable tool  100 , the biasing spring  140  will exert a force upwardly against the shoulder  134  of the sleeve  130  to push the sleeve  130  and piston  150  upwardly. The cam surfaces  153 ,  155 ,  157  of the piston  150  thereby move upwardly so that the substantially flat portions  253 ,  255 ,  257  of the piston  150  no longer act against the substantially flat bottom surfaces  262 ,  264 ,  266  of the blades  162 ,  164 ,  166 . The piston  150  moves to a position where the notches  151  are aligned with the blades  162 ,  164 ,  166 , thereby providing a space for the arm  160  to move back into the retracted position of  FIGS. 1-2 . The radial springs (not shown) below the dovetail blocks  170 ,  172  actually force the arm  160  back into the retracted position. Thus, the piston  150  and sleeve  130  combination moves upwardly due to the force of biasing spring  140 , and the arms  160  retract separately via another set of radial springs behind the dovetail blocks  170 ,  172 . 
   The expandable tool  100  described above has several important features and advantages. For example, it solves the problems experienced with bi-center bits and winged reamers because it is designed to remain concentrically disposed within the borehole  50 . In particular, the tool  100  preferably includes three extendable arms  160  spaced apart circumferentially at the same axial location on the tool  100 . In one embodiment, the circumferential spacing would be 120° apart. This three-arm design provides a full gage reaming tool  100  that remains centralized in the borehole  50  at all times. Another feature of the expandable tool  100  is the ability to provide a hydraulic indication to the surface, thereby informing the operator whether the tool  100  is in the retracted position shown in  FIGS. 1-2  or the expanded position shown in  FIGS. 3-4 . Further, the tool  100  has very few moving parts. In particular, only the piston  150 , the sleeve  130 , and the arms  160  move in contrast to other tools that may have as many as forty (40) moving parts. Thus, because there are comparatively fewer parts, and also because the arms  160  move radially rather than both radially and axially, the expandable tool  100  can be significantly shorter than conventional expandable tools. For example, the expandable tool  100  may be approximately 4-feet long as compared to other tools, which range up to approximately 14-feet long. Further, the tool  100  does not rely solely on a single activation technique to expand the arms  160  but instead combines hydraulic and mechanical activation techniques to provide a more robust activation mechanism. Since the tool  100  does not function solely by hydraulic pressure, the formation strength must overcome the mechanical strength of the blades  162 ,  164 ,  166  acting against the piston  150  in order to collapse the arms  160 . Further, the blades  162 ,  164 ,  166  extend in unison because the piston  150  has three cam portions  153 ,  155 ,  157  that simultaneously engage the three cylindrical blades  162 ,  164 ,  166 . In addition, the tool  100  is activated completely independently of weight-on-bit, such that the tool  100  components are not required to operate and support any devices beneath them simultaneously with expanding the tool  100 , and allowing for the tool  100  to be placed anywhere within the drilling assembly. 
   Referring now to  FIGS. 6-7 , cross-sectional side views are depicted of a second embodiment of the present invention, generally designated as  500 , in the retracted and expanded positions, respectively.  FIG. 6A  and  FIG. 7A  depict enlarged cross-sectional side views of a portion of  FIG. 6  and  FIG. 7 , respectively, depicting the pressure-compensating features of the tool  500 . Many components of the tool  500  are the same as the components of the first embodiment of the tool  100 , and those components maintain the same reference numerals. There are, however, several differences, some of which may be incorporated into the first embodiment of the tool  100  as well. In particular, instead of a one-piece body  120  with a connection portion  126  for connecting to a drilling assembly component (not shown), either embodiment of the expandable tool  100 ,  500  may comprise a tool body  520  connected via threads  522  to a lower section  525 . The lower section  525  includes a lower connection portion  528  for connecting via threads  526  to another component of the drilling assembly (not shown). When mating the tool  500  to another drilling assembly component, the lower section  525  or the threads  526  on the connection portion  528  could be damaged. When such damage occurs, the lower section  525  can easily be removed from the body  520  and replaced without having to replace the body  520  itself. Therefore, the lower section  525  is provided as a replaceable component that protects the tool body  520  from damage. 
   Further, instead of shear pins  107  being positioned at the arms  160 , either embodiment of the expandable tool  100 ,  500  may include a shear sleeve  590  disposed within the tool body  520  below the spring sleeve  130  to retain shear pins  107 . As shown in  FIGS. 6 and 6A , when the tool  500  is in the retracted position, the shear pins  107  extend radially outwardly from the shear sleeve  590  to engage an upper surface  529  of the lower section  525 . 
   In addition, instead of a one-piece piston  150 , either embodiment of the expandable tool  100 ,  500  may comprise three separate components: a piston driver  550 , a piston coupling  540 , and an o-ring sleeve  530 . The piston driver  550  connects to the piston coupling  540  via threads  542 , and the o-ring sleeve  530  connects to the piston coupling  540  via threads  534 . The piston driver  550  includes the cam portions  153 ,  155 ,  157  that drive the arms  160  outwardly, the piston coupling  540  includes the ports  158  that align with the nozzles  125  when the tool  500  is in the expanded position, and the o-ring sleeve  530  sealingly engages the tool body  520  at o-ring seals  104 ,  106 ,  108 . Thus, these three piston components  550 ,  540 ,  530  are provided separately for ease of manufacturing and act together to perform essentially the same functions as the piston  150  depicted in  FIGS. 1-4 . 
   Unlike the tool  100  of  FIGS. 1-4 , the pressure-compensated tool  500  is entirely sealed and filled with oil rather than with drilling fluid from the wellbore annulus  75 . Thus, rather than having ports  144  that extend through the wall  122  of the body  120  into the spring chamber  142  as depicted in  FIGS. 1-4 , the pressure-compensated tool  500  comprises a pressure compensation assembly  565  having a spring base  560  on the upper end, a compensation sleeve  580  on the lower end, and a floating compensation piston  570  therebetween. The spring base  560  connects via threads  562 ,  564  to the tool body  520  and to the compensation sleeve  580 , respectively. The compensation sleeve  580  sealingly engages the tool body  520  and the spring sleeve  130  at seals  582 ,  584 , respectively. The floating piston  570  sealingly engages the tool body at seal  572  and sealingly engages the compensation sleeve  580  at seals  574 ,  576 . 
   The floating piston  570  comprises an upper surface  573  exposed to an oil-filled chamber  542  and a lower surface  575  exposed to fluid from the wellbore annulus  75  that enters the tool  500  through a port  544  extending through the tool body  520  above the compensation sleeve  580 . Oil fills the tool  500  from the upper surface  573  of the floating piston  570 , through the spring chamber  142 , and through a gap  532  in the o-ring sleeve  530 , into the pockets  127  and axial recess  128  within the tool body  520  to surround the piston driver  550 . The port  544  allows for fluid from the wellbore annulus  75  to enter and exit the tool  500  to allow for volume changes in the oil-filled portion of the tool  500  as the arms  160  are expanded and retracted. The floating piston  570  has a certain stroke length within the chamber  542  to allow for volume displacement as the biasing spring  140  moves within the oil-filled spring chamber  142 . Thus, the pressure compensation assembly  565  compensates for wellbore pressure and volumetric changes between the retracted position of the tool  500  as depicted in  FIGS. 6 and 6A , and the expanded position of the tool  500  as depicted in  FIGS. 7 and 7A . 
   In operation, the tool  500  is run into the wellbore  50  in the retracted position of  FIG. 6 and 6A , and because the lower surface  575  of the floating piston  570  is exposed to wellbore annulus pressure via port  544 , a force is exerted on the floating piston  570 , thereby compressing the oil inside the tool  500 . As drilling fluid is introduced from the surface into the flowbore  105  of the tool  500 , differential pressure between the tool flowbore  105  and the wellbore annulus  75  will cause the piston driver  550 , piston coupling  540 , and spring sleeve  130  to exert a downward force on the shear sleeve  590  until the differential pressure is sufficient to break the shear pins  107 . The shear sleeve  590  will then move downwardly into an enlarged bore area  527  of the lower section  525  as depicted in  FIGS. 7 and 7A , thereby providing a gap  595  between the spring sleeve  130  and the shear sleeve  590 . Meanwhile, the broken portions of the shear pins  107  will be trapped within an area  585  provided between the lower section  525  and the compensation sleeve  580 . Then, as the piston driver  550  and piston coupling  540  move downwardly against the biasing spring  140  to extend the arms  160  as depicted in  FIG. 7 , oil from the spring chamber  142  flows into the oil-filled chamber  542  to exert pressure on the floating piston  570 . Thus, the floating piston  570  will move axially while pushing drilling fluid out through the ports  544  into the annulus  75  to compensate for the volume change in the spring chamber  142 . 
   When removing either embodiment of the expandable tool  100 ,  500  from the borehole  50 , one of the failsafe mechanisms is the ability for the arms  160  to be collapsed should the radial springs behind the dovetail blocks  170 ,  172  fail. As best depicted in  FIG. 3  and  FIG. 7 , the upper cylindrical blade  162  includes an upper tapered surface  161  that will engage casing if the arm  160  is still in the extended position as the tool  100 ,  500  is being raised out of the borehole  50 . By engaging the casing on the tapered surface  161 , the arm  160  will be forced inwardly as the tool  100 ,  500  is pulled upwardly through the casing. 
   Another failsafe withdrawal option would be to extend a grappling mechanism on a wireline through the tool bore  105  to attach to the lower end  136  of the spring sleeve  130  in case the biasing spring  140  should fail. The wireline pulls the piston  150  and spring sleeve  130 , or alternatively, the piston driver  550 , piston coupling  540  and spring sleeve  130  upwardly to align the piston notches  151  with the blades  162 ,  164 ,  166 , thereby allowing the arms  160  to retract via the radial springs behind the dovetail blocks  170 ,  172 . 
   If the substantially flat piston surfaces  253 ,  255 ,  257  are disposed at a slope greater than 0°, such as 5° for example, the arms  160  can be collapsed if the biasing spring  140  fails, or the radial springs fail, or both. In more detail, when the expandable tool  100 ,  500  is raised out of the borehole  50 , the upper cylindrical blades  162  will engage the casing at tapered surface  161 , and the force of the casing on the arms  160  will cause the blades  162 ,  164 ,  166  to act against the piston surfaces  253 ,  255 ,  257  having a 5° slope. The piston  150  or piston driver  550  will thereby be forced upwardly to align the piston notches  151  with the blades  162 ,  164 ,  166  so that the arms  160  may be retracted either by the radial springs or, if the radial springs have failed, by the force of the casing as the tool  100 ,  500  is pulled upwardly through the casing. 
   Accordingly, in various embodiments, the expandable tool  100 ,  500  is specifically designed not to get hung up in the borehole  50  or stuck in the expanded position. 
   Referring now to  FIG. 8 , a cross-sectional side view of the moveable arm  160  is depicted in more detail. The arm  160  comprises a structural support beam  165  with one-piece blades  162 ,  164 ,  166  connected thereto. O-ring grooves  163  are provided on each of the blades  162 ,  164 ,  166 .  FIG. 9  depicts a cross-sectional side view of another embodiment of a moveable arm  300  that may be utilized instead of the moveable arm  160  in either embodiment of the expandable tool  100 ,  500 . The moveable arm  300  comprises the same structural support beam  165 , but instead of one-piece blades  162 ,  164 ,  166  connected thereto, the moveable arm  300  comprises fixed blade portions  302 ,  304 ,  306  connected to the support beam  165  and removable blade portions  312 ,  314 ,  316  connected to the fixed blade portions  302 ,  304 ,  306 . Thus, the support beam  165  and fixed blade portions  302 ,  304 ,  306  form an internal arm  310  disposed within the body  120 ,  520  and the removable blade portions  312 ,  314 ,  316  can be detached from the internal arm  310  as shown in  FIG. 10 . There are several advantages to the alternative moveable arm  300 . First, the removable blade portions  312 ,  314 ,  316  provide another possible failsafe for removing the tool  100 ,  500  from the borehole should the tool  100 ,  500  get stuck in the expanded position. In particular, by pulling the tool  100 ,  500  upwardly in the borehole  50 , the removable blade portions  312 ,  314 ,  316  would engage the casing and simply shear off from the internal arm  310  so that the tool  100 ,  500  could then be removed. 
   The moveable arms  300  also allow for more flexibility to expand the tool  100 ,  500  to a different diameter. The internal arm portion  310  always moves radially outwardly by the same distance; whereas, the removable blade portions  312 ,  314 ,  316  may extend past the body  120 ,  520  and can be provided in different sizes depending upon the desired enlarged diameter of the reamed borehole. Thus, rather than replacing the entire standard moveable arm  160  every time an enlarged borehole diameter change is required, the operator could simply change the removable blade portions  312 ,  314 ,  316 , and an inventory of various diameter sizes could be provided at the rig site. The removable blade portions  312 ,  314 ,  316  are comparatively small and inexpensive versus replacing an entire one-piece arm  160 . For exemplary purposes, if the diameter of a standard expandable tool  100 ,  500  is approximately 8½ inches drift diameter, the tool  100 ,  500  may be capable of enlarging a borehole to approximately 9⅞ inches in diameter. To create a larger sized borehole, the removable blade portions  312 ,  314 ,  316  may extend past the body  120 ,  520  such that the drift diameter is in the range of 9⅞ inches, in which case the borehole could be enlarged to approximately 12¼ inches in diameter, for example. Thus, the moveable arms  300  always expand the same distance, but depending upon the size of the removable blade portions  312 ,  314 ,  316 , the diameter of the reamed borehole can be changed accordingly. 
   Still another advantage of the alternative moveable arm  300  is that the pads  190  and cutting structures  180  can be optimized for a particular formation since the removable blade portions  312 ,  314 ,  316  can be removed and replaced easily. Accordingly, the removable blade portions  312 ,  314 ,  316  of the alternative moveable arms  300  could comprise a variety of structures and configurations utilizing a variety of different materials. When the tool  100 ,  500  is used in a reaming function, a variety of different cutting structures  180  could be provided, depending upon the formation characteristics. Preferably, the cutting structures  180  for reaming and back reaming are specially designed for the particular cutting function. More preferably, the cutting structures  180  comprise the cutting structures disclosed and claimed in co-pending U.S. patent application Ser. No. 09/924,961, filed Aug. 8, 2001, entitled “Advanced Expandable Reaming Tool,” assigned to Smith International, Inc., which is hereby incorporated herein by reference for all purposes. 
     FIG. 11  illustrates another feature of the expandable tool  100 ,  500 . In particular, unlike conventional expandable tools that either fail to include a gage pad  190 , or fail to include cutting structures, such as cutters  192 , near the gage pad  190 , the present expandable tool  100 ,  500  allows excellent durability and stability. In particular, proper gage pads  190  are provided while also providing aggressive cutting structures  192  near the gage pad  190  so that either embodiment of the moveable arms  160 ,  300  can move from the retracted to the expanded position while the tool  100 ,  500  remains in the same axial location in the wellbore  50 . 
   In more detail,  FIG. 11  depicts a top plan view of three exemplary arms  160 A,  160 B,  160 C disposed side by side for illustrative purposes. However, these arms  160 A,  160 B,  160 C would actually be spaced apart azimuthally around the circumference of a tool body  120 ,  520 . For the arms  160 A,  160 B,  160 C to extend without drilling ahead in the borehole  50 , an aggressive side cutting structure  192  must be provided. However, it is not desirable for the entire gage section provided by the combination of surfaces  162 A,  162 B,  162 C to comprise an aggressive side-cutting structure  192  since this can lead to poor durability. Thus,  FIG. 11  depicts one exemplary gage configuration designed to achieve aggressive side cutting while retaining good gage pad area for stability and durability. In particular, the gage surface  162 A of expandable arm  160 A includes an upper gage pad area  190 A, two cutters  192 A in the middle, and a lower gage pad area  190 A. The gage surface  162 B of expandable arm  160 B includes a gage pad area  190 B above two cutters  192 B. The gage surface  162 C of expandable arm  160 C includes an upper gage pad area  190 C, a single middle cutter  192 C, and a lower gauge pad area  190 C. Thus, the gage surfaces  162 A,  162 B,  162 C of arms  160 A,  160 B,  160 C, when combined, comprise a complete overlap of an aggressive cutting structure  192  and a complete overlap of a smooth gage pad  190  for stability and durability. In another embodiment, the gage surfaces  162 A,  162 C of arms  160 A,  160 C, respectively, could comprise all gage pad area  190 , while the gage surface  162 B of arm  160 B could comprise all cutters  192 . Various other configurations may also be provided to achieve the same purpose. Regardless of the configuration of the gage surfaces  162 A,  162 B,  162 C, back-reaming cutters  194 A,  194 B,  194 C may also be provided on upper tapered surfaces  161 A,  161 B,  161 C of the three arms  160 A,  160 B,  160 C, respectively. As one of ordinary skill in the art will readily understand, instead of the moveable arms  160 A,  160 B,  160 C described above, the alternative moveable arms  300  could also be utilized. 
     FIGS. 12-15  depict enlarged cross-sectional side views of one embodiment of an exemplary bullet activation mechanism  600  for selectively expanding either embodiment of tool  100 ,  500  without using shear pins  107 . In particular,  FIGS. 13-16  depict a series of activation steps for the exemplary bullet activation mechanism  600 , which is disposed in the flow bore  114  of the upper  110  section and extends into the flow bore  152  of the tool piston  150 ,  550 . The bullet activation mechanism  600  comprises a sliding sleeve  650  biased upwardly by an axial spring  640  disposed in an oil-filled spring chamber  642 . The sliding sleeve  650  comprises a plunger portion  655  with an internal tapered surface  654 , a cylindrical body portion  656 , and a flow bore  652  extending through both portions  655 ,  656 . The sliding sleeve  650  extends into an internal recess  115  in the tool piston  150 ,  550 , the recess  115  including a shoulder  117  to limit the downward movement of the sliding sleeve  650 . The sliding sleeve  650  sealingly engages the upper section  110  at  604 ,  606  and sealingly engages the tool piston  150 ,  550  at  608 . Ports  644  extend through the wall  112  of the upper section  110 , providing fluid communication between the upper section flowbore  114  and a flat upper surface  605  of the tool piston  150 ,  550 . A bullet  610  is the activation device and comprises a lower tapered surface  614 , an upper flat surface  616 , and a bore  612  extending therethrough. 
     FIG. 12  depicts the bullet activation system  600  with the sliding sleeve  650  and the piston  150 ,  550  in their uppermost positions, corresponding to the retracted position of the tool  100 ,  500 . When the operator wants to activate the tool  100 ,  500  and expand moveable arms  160 ,  300 , the bullet  610  is dropped into the wellbore from the surface. In  FIG. 12 , the bullet  610  has almost reached the sliding sleeve  650 , which blocks the fluid ports  644  so that drilling fluid flows downwardly from the surface through the bullet bore  612 , through the sliding sleeve bore  652 , and through the piston flowbore  152  as depicted by the flow arrows. Thus, the piston  150 ,  550  has not moved downwardly to drive the arms  160  of the tool  100  radially outwardly from the retracted position. 
     FIG. 13  depicts the bullet  610  just as the lower tapered bullet surface  614  seats on the upper internal tapered surface  654  within the plunger portion  655  of the sliding sleeve  650 . In  FIG. 13 , the sliding sleeve  650  still blocks the fluid ports  644  so that the drilling fluid flows through the bullet bore  612 , through the sliding sleeve bore  652 , and downwardly through the piston flowbore  152  as depicted by the flow arrows. Thus, the piston  150 ,  550  has not moved downwardly to drive the arms  160  of the tool  100  radially outwardly from the retracted position. 
     FIG. 14  depicts the bullet activation mechanism  600  after the bullet  610  has moved the sliding sleeve  650  downwardly due to pressure build up behind the bullet  610  from drilling fluid being pumped from the surface. Thus, the pressure of the drilling fluid on the flat upper surface  616  of the bullet  610 , which is now seated on the sliding sleeve  650 , causes the bullet  610  and sliding sleeve  650  to move downwardly against the axial spring  640 . The sliding sleeve  650  will stop moving downwardly when the lower end of the sleeve body  656  engages the shoulder  117  within the recess  115  in the tool piston  150 ,  550 . By moving downwardly, the sliding sleeve  650  opens the ports  644  so that a small amount of flow can move around the bullet  610  and into the ports  644  as depicted by the flow arrows in  FIG. 14 . The remaining fluid continues along the flow path through the bullet flowbore  612 , through the sliding sleeve flowbore  652 , and downwardly into the tool piston flowbore  152 . 
   As depicted in  FIG. 15 , the pressure of the drilling fluid flowing through the ports  644  and acting against the upper surface  605  of the tool piston  150 ,  550  will cause the piston  150 ,  550  to move downwardly, thereby forming a gap  205  between the upper section  110  and the piston  150 ,  550 . The downward movement of the piston  150 ,  550  expands the arms  160 ,  300  of the tool  100 ,  500  as previously described. In summary, when the bullet  610  is not seated on the sliding sleeve  650 , the fluid will flow directly through the tool  100 ,  500  so that the arms  160  will not expand. However, when the bullet  610  is dropped into the borehole  50  and seats with the sliding sleeve  650 , pressure on the upper surface  616  of the bullet  610  will force the bullet  610  and sliding sleeve  650  down, thereby opening lateral ports  644  through the upper section wall  112  to allow fluid pressure to engage the upper surface  605  of the piston  150 ,  550 . This fluid pressure causes the piston  150 ,  550  to move downwardly and extend the arms  160  to the expanded position. Thus, the bullet activation mechanism  600  eliminates the need for shear pins  107  because the piston  150 ,  550  will not actuate until the bullet  610  is dropped into the borehole  50  and seats on the sliding sleeve  650 . 
   In another embodiment, the bullet  610  has no bore  612  therethrough such that when the bullet  610  seats on the sliding sleeve  650 , all flow is blocked through the tool until the bullet  610  and sliding sleeve  650  move downwardly to open ports  644 , and then flow through the ports  644  causes the piston  150 ,  550  to move downwardly away from the upper section  110 . In yet another embodiment, there are no ports  644  through the upper section  110 , and the sliding sleeve  650  either engages or connects to the tool piston  150 ,  550 . In this embodiment, when the bullet  610  seats on the sliding sleeve  650 , the sliding sleeve  650  will move downwardly, thereby causing downward movement of the tool piston  150 ,  550 . 
     FIGS. 16-18  depict enlarged cross-sectional side views of one embodiment of an exemplary centrifugal activation mechanism  700 , which allows for selective expansion of the tool  100 ,  500  without using shear pins  107 . In particular,  FIGS. 16-18  depict a series of activation steps for the centrifugal activation mechanism  700 , which is disposed in the flow bore  114  of the upper  110  section and extends into the flow bore  152  of the tool piston  150 ,  550 . The centrifugal activation mechanism  700  comprises a sliding sleeve  750  biased upwardly by an axial spring  740  disposed in an oil-filled spring chamber  742 . The sliding sleeve  750  comprises a plunger portion  755  with a flat upper surface  715  and a side-notch  754  disposed therein, a cylindrical body portion  756 , and a flowbore  752  extending through both portions  755 ,  756 . The sliding sleeve  750  extends into an internal recess  115  in the tool piston  150 ,  550 , the recess  115  including a shoulder  117  to limit the downward movement of the sliding sleeve  750 . The sliding sleeve  750  sealingly engages the upper section  110  at  704 ,  706  and sealingly engages the tool piston  150 ,  550  at  708 . Ports  644  extend through the wall  112  of the upper section  110 , providing fluid communication between the upper section flowbore  114  and a flat upper surface  605  of the tool piston  150 ,  550 . The centrifugal activation mechanism  700  further comprises a latching assembly  710  disposed in an oil-filled cavity  116  within the wall  112  of the upper section  110 . The latching assembly  710  comprises an outer plate  720 , a heavy T-shaped member  730 , and a radial spring  745 . The T-shaped member  730  can move radially and is disposed on linear bearings  726 ,  728  surrounding guideposts  722 ,  724  extending from the plate  720 . 
     FIG. 16  depicts the centrifugal activation mechanism  700  with the sliding sleeve  750  in the uppermost, locked position and the piston  150 ,  550  in its uppermost position, corresponding to the retracted position of the tool  100 ,  500 . The T-shaped member  730  is biased radially inwardly with respect to the plate  720  by the radial spring  745 , and a locking portion  734  of the T-shaped member  730  engages the side-notch  754  of the sliding sleeve  750 . In this position, the sliding sleeve  750  blocks ports  644  that extend through the wall  112  of the upper section  110  between the upper section flowbore  114  and a flat upper surface  605  of the piston  150 ,  550 . 
   In operation, the centrifugal activation mechanism  700  will only unlock the latching assembly  710  and allow the piston  150 ,  550  to move downwardly to extend the tool arms  160 ,  300  if the drill string (not shown) that connects to the upper section  110  is rotated from the surface before starting the surface pump. In normal drilling practices, the surface pump is started before the drill string is rotated. Thus, if the surface pumps are turned on first, the centrifugal activation mechanism  700  will remain locked as depicted in  FIG. 16 , and the expandable tool  100 ,  500  will remain locked in the retracted position. 
   To unlock the latching assembly  710  as depicted in  FIG. 17 , the drill string must be rotated before turning on the surface pump. By spinning the drill string at an adequate speed, the centrifugal force acting on the T-shaped member  730  will cause it to slide radially outwardly against the radial spring  745  and along the guideposts  722 ,  724  aided by the linear bearings  726 ,  728 . It is expected that  120 - 125  revolutions per minute (RPM) of the drill string will be sufficient to cause the T-shaped member  730  to move radially outwardly and disengage from the sliding sleeve  750 . Once the locking portion  734  of the T-shaped member  730  has disengaged from the side-notch  754  of the sliding sleeve  750 , then the surface pump can be turned on while continuing to rotate the drill string. Then the sliding sleeve  750  is free to move axially downwardly against the axial spring  740  in response to the drilling fluid pressure acting on the upper surface  715  of the sliding sleeve  750 . The sliding sleeve  750  will stop moving downwardly when the lower end of the sleeve body  756  engages the shoulder  117  within the recess  115  in the tool piston  150 ,  550 . The downward movement of the sliding sleeve  750  to the position shown in  FIG. 17  open the fluid ports  644  to allow flow therethrough. 
     FIG. 18  depicts the latching assembly  710  in the unlocked position, with the sliding sleeve  750  moved downwardly to compress the axial spring  740 . Fluid is flowing through the ports  644  in the wall  112  of the upper section  110  to engage the upper surface  605  of the piston  150 ,  550 , thereby causing it to move downwardly away from the upper section  110 , creating a gap  205 . The downward movement of the piston  150 ,  550  causes the tool arms  160 ,  300  to extend. Thus, the centrifugal activation mechanism  700  eliminates the need for shear pins  107  because the piston  150 ,  550  will not actuate until the latching assembly  710  is disengaged from the sliding sleeve  750  by rotating the drill string before operating the surface pumps. 
   While preferred embodiments of the concentric expandable tool have been shown and described, modifications thereof can be made by one skilled in the art without departing from the spirit or teaching of this invention. The embodiments described herein are exemplary only and are not limiting. Many variations and modifications of the system and apparatus are possible and are within the scope of the invention. Accordingly, the scope of protection is not limited to the embodiments described herein, but is only limited by the claims which follow, the scope of which shall include all equivalents of the subject matter of the claims.