Patent Publication Number: US-8978783-B2

Title: Jet arrangement on an expandable downhole tool

Description:
FIELD OF THE DISCLOSURE 
     Embodiments disclosed herein relate generally to underreamers used for enlarging a borehole below a restriction to result in a borehole that is larger than the restriction. Embodiments disclosed herein also relate generally to stabilizers used for controlling the trajectory of a drill bit during the drilling process. More particularly, embodiments disclosed herein relate to delivering drilling fluid having an increased hydraulic energy to remove drill cuttings proximate cutting structures on an expandable tool that may function as an underreamer, or alternatively, may function as a stabilizer in an underreamed portion of borehole. 
     BACKGROUND 
     In the drilling of oil and gas wells, concentric casing strings are installed and cemented in the borehole as drilling progresses to increasing depths. Each new casing string is supported within the previously installed casing string, thereby limiting the annular area available 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. Accordingly, by enlarging the borehole below the previously cased borehole, the bottom of the formation can be reached with comparatively larger diameter casing, thereby providing more 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 is the use of an underreamer, which has basically two operative states—a closed or collapsed 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 partly 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 underreamer enlarges the borehole diameter as the tool is rotated and lowered in the borehole. 
     A “drilling type” underreamer is typically used in conjunction with a conventional pilot drill bit positioned below or downstream of the underreamer. The pilot bit can drill the borehole at the same time as the underreamer enlarges the borehole formed by the bit. Underreamers of this type usually have hinged arms with roller cone cutters attached thereto. Most of the prior art underreamers utilize swing out cutter arms that are pivoted at an end opposite the cutting end of the cutting arms, and the cutter arms are actuated by mechanical or hydraulic forces acting on the arms to extend or retract them. Typical examples of these types of underreamers are found in U.S. Pat. Nos. 3,224,507; 3,425,500 and 4,055,226. In some designs, these pivoted arms tend to break during the drilling operation and must be removed or “fished” out of the borehole before the drilling operation can continue. The traditional underreamer tool typically has rotary cutter pocket recesses formed in the body for storing the retracted arms and roller cone cutters when the tool is in a closed state. The pocket recesses form large cavities in the underreamer body, which requires the removal of the structural metal forming the body, thereby compromising the strength and the hydraulic capacity of the underreamer. Accordingly, these prior art underreamers may not be capable of underreaming harder rock formations, or may have unacceptably slow rates of penetration, and they are not optimized for the high fluid flow rates required. The pocket recesses also tend to fill with debris from the drilling operation, which hinders collapsing of the arms. If the arms do not fully collapse, the drill string may easily hang up in the borehole when an attempt is made to remove the string from the borehole. 
     Conventional underreamers have several disadvantages, including cutting structures that are typically formed of sections of drill bits rather than being specifically designed for the underreaming function. Therefore, the cutting structures of most underreamers do not reliably underream the borehole to the desired diameter. A further disadvantage is that adjusting the expanded diameter of a conventional underreamer requires replacement of the cutting arms with larger or smaller arms, or replacement of other components of the underreamer tool. It may even be necessary to replace the underreamer altogether with one that provides a different expanded diameter. Another disadvantage is that many underreamers are designed to automatically expand when drilling fluid is pumped through the drill string, and no indication is provided at the surface that the underreamer is in the fully-expanded position. In some applications, it may be desirable for the operator to control when the underreamer expands. 
     Accordingly, it would be advantageous to provide an underreamer that is stronger than prior art underreamers, with a hydraulic capacity that is optimized for the high flowrate drilling environment. It would further be advantageous for such an underreamer to include several design features, namely cutting structures designed for the underreaming function, mechanisms for adjustment of the expanded diameter without requiring component changes, and the ability to provide indication at the surface when the underreamer is in the fully-expanded position. Moreover, in the presence of hydraulic pressure in the drill string, it would be advantageous to provide an underreamer that is selectively expandable. 
     Another method for enlarging a borehole below a previously cased borehole section 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. 
     Yet 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 underreamer and pilot bit. The pilot bit is disposed on the lowermost end of the drilling assembly, and the eccentric underreamer 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 underreamer 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 underreamer portions that are eccentric. A number of disadvantages are associated with this design. First, before drilling can continue, cement and float equipment at the bottom of the lowermost casing string must be drilled out. However, the pass-through diameter of the drilling assembly at the eccentric underreamer portion barely fits within the lowermost casing string. Therefore, off-center drilling is required to drill out the cement and float equipment to ensure that the eccentric underreamer portions do not damage the casing. Accordingly, it is desirable to provide an underreamer that collapses while the drilling assembly is in the casing and that expands to underream the previously drilled borehole to the desired diameter below the casing. 
     Further, due to directional tendency problems, these eccentric underreamer portions have difficulty reliably underreaming the borehole to the desired diameter. With respect to a bi-center bit, the eccentric underreamer bit tends to cause the pilot bit to wobble and undesirably deviate off center, thereby pushing the pilot bit away from the preferred trajectory of drilling the well path. A similar problem is experienced with respect to winged reamers, which only underream the borehole to the desired diameter if the pilot bit remains centralized in the borehole during drilling. Accordingly, it is desirable to provide an underreamer that remains concentrically disposed in the borehole while underreaming the previously drilled borehole to the desired diameter. 
     In drilling operations, it is conventional to employ a tool known as a “stabilizer.” In standard boreholes, traditional stabilizers are located in the drilling assembly behind the drill bit for controlling the trajectory of the drill bit as drilling progresses. Traditional stabilizers control drilling in a desired direction, whether the direction is along a straight borehole or a deviated borehole. 
     In a conventional rotary drilling assembly, a drill bit may be mounted onto a lower stabilizer, which is disposed approximately 5 feet above the bit. Typically the lower stabilizer is a fixed blade stabilizer that includes a plurality of concentric blades extending radially outwardly and spaced azimuthally around the circumference of the stabilizer housing. The outer edges of the blades are adapted to contact the wall of the existing cased borehole, thereby defining the maximum stabilizer diameter that will pass through the casing. A plurality of drill collars extends between the lower stabilizer and other stabilizers in the drilling assembly. An upper stabilizer is typically positioned in the drill string approximately 30-60 feet above the lower stabilizer. There could also be additional stabilizers above the upper stabilizer. The upper stabilizer may be either a fixed blade stabilizer or, more recently, an adjustable blade stabilizer that allows the blades to be collapsed into the housing as the drilling assembly passes through the casing and then expanded in the borehole below. One type of adjustable concentric stabilizer is manufactured by Andergauge U.S.A., Inc., Spring, Tex. and is described in U.S. Pat. No. 4,848,490. Another type of adjustable concentric stabilizer is manufactured by Halliburton, Houston, Tex. and is described in U.S. Pat. Nos. 5,318,137; 5,318,138; and 5,332,048. 
     In operation, if only the lower stabilizer was provided, a “fulcrum” type assembly would be present because the lower stabilizer acts as a fulcrum or pivot point for the bit. Namely, as drilling progresses in a deviated borehole, for example, the weight of the drill collars behind the lower stabilizer forces the stabilizer to push against the lower side of the borehole, thereby creating a fulcrum or pivot point for the drill bit. Accordingly, the drill bit tends to be lifted upwardly at an angle, i.e., build angle. Therefore, a second stabilizer is provided to offset the fulcrum effect. Namely, as the drill bit builds angle due to the fulcrum effect created by the lower stabilizer, the upper stabilizer engages the lower side of the borehole, thereby causing the longitudinal axis of the bit to pivot downwardly so as to drop angle. A radial change of the blades of the upper stabilizer can control the pivoting of the bit on the lower stabilizer, thereby providing a two-dimensional, gravity based steerable system to control the build or drop angle of the drilled borehole as desired. 
     When an underreamer or a winged reamer tool is operating behind a conventional bit to underream the borehole, that tool provides the same fulcrum effect to the bit as the lower stabilizer in a standard borehole. Similarly, when underreaming a borehole with a bi-center bit, the eccentric underreamer bit provides the same fulcrum effect as the lower stabilizer in a standard borehole. Accordingly, in a drilling assembly employing an underreamer, winged reamer, or a bi-center bit, a lower stabilizer is not typically provided. However, to offset the fulcrum effect imparted by to the drill bit, it would be advantageous to provide an upper stabilizer capable of controlling the inclination of the drilling assembly in the underreamed section of borehole. 
     In particular, it would be advantageous to provide an upper stabilizer that engages the wall of the underreamed borehole to keep the centerline of the pilot bit centered within the borehole. When utilized with an eccentric underreamer that tends to force the pilot bit off center, the stabilizer blades would preferably engage the opposite side of the expanded borehole to counter that force and keep the pilot bit on center. 
     When an underreamer and/or a stabilizer are operated in a drilling environment and under various drilling conditions, cutting elements may suffer thermal degradation due to frictional abrasive contact with the formation. Additionally, if cuttings generated are not removed at a fast enough rate, an increase in frictional contact on the cutting elements may result, leading to damage or premature failure in the form of heat cracks or carbide wear. It is thus of great importance to have a system that can remove the cuttings at a fast rate and provide sufficient cooling of the cutting elements. 
     SUMMARY OF THE CLAIMED EMBODIMENTS 
     In one aspect, embodiments disclosed herein relate to an expandable downhole tool for use in a drilling assembly positioned within a wellbore. The expandable downhole tool may include: a tubular body including at least one axial recess, a plurality of channels formed into a wall of said at least one axial recess, and an axial flowbore extending therethrough; at least one moveable arm, wherein the at least one moveable arm translates along said plurality of channels between a collapsed position and an expanded position in response to a differential pressure between the axial flowbore and the wellbore; the at least one moveable arm further comprising a borehole-engaging surface; and at least one flow directing element that: decreases a flow area in an annulus formed between the expandable downhole tool and the wellbore; and directs a flow of fluid in the annulus toward the borehole-engaging surface. 
     In another aspect, embodiments disclosed herein relate to an expandable downhole tool for use in a drilling assembly positioned within a wellbore, including: a tubular body including at least one axial recess, a plurality of channels formed into a wall of said at least one axial recess, and an axial flowbore extending therethrough; at least one moveable arm, wherein the at least one moveable arm translates along said plurality of channels between a collapsed position and an expanded position in response to a differential pressure between the axial flowbore and the wellbore; the at least one moveable arm further comprising a borehole-engaging surface and at least one nozzle to direct a fluid across the borehole-engaging surface of the at least one moveable arm. 
     In another aspect, embodiments disclosed herein relate to an expandable downhole tool for use in a drilling assembly positioned within a wellbore, including: a tubular body including at least one axial recess, a plurality of channels formed into a wall of said at least one axial recess, and an axial flowbore extending therethrough; at least one moveable arm, wherein the at least one moveable arm translates along said plurality of channels between a collapsed position and an expanded position in response to a differential pressure between the axial flowbore and the wellbore; at least one nozzle to direct a fluid across a borehole-engaging surface of the at least one moveable arm; the tubular body further including at least one fluid flow path for transporting the fluid from the axial flowbore to the at least one nozzle. 
     In another aspect, embodiments disclosed herein relate to a drilling assembly for underreaming a wellbore to form an enlarged borehole, including: a drill bit to drill the wellbore; and at least one expandable tool as described in the preceding paragraphs. 
     In another aspect, embodiments disclosed herein relate to a method of drilling a wellbore, including: using a drill bit to drill the wellbore; disposing at least one expandable tool as described in the preceding paragraphs above the drill bit; using the at least one expandable tool to form an enlarged borehole or to control directional tendencies of said drilling assembly. 
     Other aspects and advantages will be apparent from the following description and the appended claims. 
    
    
     
       BRIEF DESCRIPTION OF DRAWINGS 
         FIG. 1  is a schematic cross-sectional view of a drilling assembly that employs an expandable downhole tool according to embodiments disclosed herein. 
         FIG. 2  is a schematic cross-sectional view of a drilling assembly that employs an expandable downhole tool according to embodiments disclosed herein. 
         FIG. 3  is a schematic cross-sectional view of a drilling assembly that employs an expandable downhole tool according to embodiments disclosed herein. 
         FIG. 4  is a cross-sectional elevation view of a prior art expandable tool, showing the movable arms in the collapsed position. 
         FIG. 5  is a cross-sectional elevation view of a prior art expandable tool, showing the movable arms in the expanded position. 
         FIGS. 6 and 6A  are cross-sectional elevation views of an expandable tool according to embodiments disclosed herein, showing the movable arms in the collapsed position. 
         FIGS. 7 and 7A  are cross-sectional elevation views of an expandable tool according to embodiments disclosed herein, showing the movable arms in the expanded position. 
         FIGS. 8 and 8A  are cross-sectional elevation views of an expandable tool according to embodiments disclosed herein, showing the movable arms in the collapsed position. 
         FIGS. 9 and 9A  are cross-sectional elevation views of an expandable tool according to embodiments disclosed herein, showing the movable arms in the expanded position. 
         FIGS. 10 and 10A  are cross-sectional elevation views of an expandable tool according to embodiments disclosed herein, showing the movable arms in the expanded position. 
         FIGS. 11 and 11A  illustrate an expandable tool according to embodiments disclosed herein, showing the movable arms in the expanded position. 
         FIGS. 12 and 12A  illustrate an expandable tool according to embodiments disclosed herein. 
         FIG. 13  illustrates an expandable tool according to embodiments disclosed herein. 
     
    
    
     DETAILED DESCRIPTION 
     In one aspect, embodiments herein relate to methods and apparatus for underreaming to enlarge a borehole below a restriction, such as casing. Alternatively, the embodiments herein relate to methods and apparatus for stabilizing a drilling assembly and thereby controlling the directional tendencies of the drilling assembly within an enlarged borehole. In more particular aspects, embodiments disclosed herein relate to delivering drilling fluid having an increased hydraulic energy to remove drill cuttings proximate cutting structures on expandable tools useful for underreaming and stabilizing the drilling assembly. 
     In particular, various embodiments disclosed herein provide a number of different constructions and methods of operation. Each of the various embodiments may be used to enlarge a borehole, or to provide stabilization in a previously enlarged borehole, or in a borehole that is simultaneously being enlarged. The preferred embodiments of the expandable tools disclosed herein may be utilized as an underreamer, or as a stabilizer behind a bi-center bit, or as a stabilizer behind a winged reamer or underreamer following a conventional bit. The embodiments disclosed herein 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. 
     It should be appreciated that the expandable tools described with respect to the Figures that follow may be used in many different drilling assemblies. The following exemplary systems provide only some of the representative assemblies within which the expandable tools described herein may be used, but these should not be considered the only assemblies. In particular, the preferred embodiments of the expandable tool disclosed herein may be used in any assembly requiring an expandable underreamer and/or stabilizer for use in controlling the directional tendencies of a drilling assembly in an expanded borehole. 
       FIGS. 1-3  show various exemplary drilling assemblies within which embodiments of the expandable downhole tools disclosed herein may be utilized. Referring initially to  FIG. 1 , a section of a drilling assembly generally designated as  100  is shown drilling into the bottom of a formation  10  with a conventional drill bit  110  followed by an underreamer  120 . Separated from the underreamer  120  by one or more drill collars  130  is a stabilizer  150  that controls the directional tendencies of the drilling assembly  100  in the underreamed borehole  25 . This section of the drilling assembly  100  is shown at the bottom of formation  10  drilling a borehole  20  with the conventional drill bit  110 , while the underreamer cutting arms  125  are simultaneously opening a larger diameter borehole  25  above. The drilling assembly  100  is operating below any cased portions of the well. 
     As described previously, the underreamer  120  tends to provide a fulcrum or pivot effect to the drill bit  110 , thereby requiring a stabilizer  150  to offset this effect. In the drilling assembly  100 , the expandable tools according to embodiments disclosed herein are provided in the positions of both the underreamer  120  and the stabilizer  150 . In the most preferred embodiments, the stabilizer  150  would also preferably include cutting structures to ensure that the larger borehole  25  is enlarged to the proper diameter. However, any conventional underreamer may alternatively be utilized with embodiments disclosed herein provided in the position of stabilizer  150  in the drilling assembly  100 . Further, embodiments may be utilized in the position of underreamer  120 , and a conventional stabilizer may be utilized in the position of stabilizer  150 . 
     Referring now to  FIG. 2 , where like numerals represent like components, a drilling assembly  200  is shown disposed within formation  10 , below any cased sections of the well. The drilling assembly  200  is drilling a borehole  20  utilizing a conventional drill bit  110  followed by a winged reamer  220 . The winged reamer  220  may be separated from the drill bit  110  by one or more drill collars  130 , but preferably the winged reamer  220  is connected directly above the drill bit  110 . Upstream of the winged reamer  220 , separated by one or more drill collars  130 , is a stabilizer  150  that controls the directional tendencies of the drilling assembly  200  in the underreamed borehole  25 . The drill bit  110  is shown at the bottom of the formation  10  drilling a borehole  20 , while the wing component  225  of the winged reamer  220  is simultaneously opening a larger diameter borehole  25  above. In the preferred assembly  200 , a preferred embodiment of expandable tool would be located in the position of stabilizer  150 . In a most preferred assembly  200 , the stabilizer  150  would also include cutting structures to ensure that the larger borehole  25  is enlarged to the proper diameter. 
     Referring to  FIG. 3 , where like numerals represent like components, again a drilling assembly  300  is shown disposed within formation  10 , below any cased sections of the well. The drilling assembly  300  utilizes a bi-center bit  320  that includes a pilot bit  310  and an eccentric underreamer bit  325 . As the pilot bit  310  drills the borehole  20 , the eccentric underreamer bit  325  opens a larger diameter borehole  25  above. The bi-center bit  320  is separated by one or more drill collars  130  from a stabilizer  150  designed to control the directional tendencies of the bi-center bit  320  in the underreamed borehole  25 . Again, the function of the stabilizer  150  is to offset the fulcrum or pivot effect created by the eccentric underreamer bit  325  to ensure that the pilot bit  310  stays centered as it drills the borehole  20 . In the preferred embodiment of the drilling assembly  300 , one embodiment of the expandable tool disclosed herein would be located in the position of stabilizer  150 . In a most preferred assembly  300 , the stabilizer  150  would also include cutting structures to ensure that the larger borehole  25  is enlarged to the proper diameter. 
     Referring now to  FIGS. 4 and 5 , an expandable tool as disclosed in U.S. Pat. No. 6,732,817 is reproduced, generally designated as  500 , and is shown in a collapsed position in  FIG. 4  and in an expanded position in  FIG. 5 . The expandable tool  500  comprises a generally cylindrical tool body  510  with a flowbore  508  extending therethrough. The tool body  510  includes upper  514  and lower  512  connection portions for connecting the tool  500  into a drilling assembly. In approximately the axial center of the tool body  510 , one or more pocket recesses  516  are formed in the body  510  and spaced apart azimuthally around the circumference of the body  510 . The one or more recesses  516  accommodate the axial movement of several components of the tool  500  that move up or down within the pocket recesses  516 , including one or more moveable, non-pivotable tool arms  520 . Each recess  516  stores one moveable arm  520  in the collapsed position. 
     The recesses  516  further include angled channels  518  that provide a drive mechanism for the moveable tool arms  520  to move axially upwardly and radially outwardly into the expanded position of  FIG. 5 . A biasing spring  540  is preferably included to bias the arms  520  to the collapsed position of  FIG. 4 . The biasing spring  540  is disposed within a spring cavity  545  and covered by a spring retainer  550 . Retainer  550  is locked in position by an upper cap  555 . A stop ring  544  is provided at the lower end of spring  540  to keep the spring  540  in position. 
     Below the moveable arms  520 , a drive ring  570  is provided that includes one or more nozzles  575 . An actuating piston  530  that forms a piston cavity  535 , engages the drive ring  570 . A drive ring block  572  connects the piston  530  to the drive ring  570  via bolt  574 . The piston  530  is adapted to move axially in the pocket recesses  516 . A lower cap  580  provides a lower stop for the axial movement of the piston  530 . An inner mandrel  560  is the innermost component within the tool  500 , and it slidingly engages a lower retainer  590  at  592 . The lower retainer  590  includes ports  595  that allow drilling fluid to flow from the flowbore  508  into the piston chamber  535  to actuate the piston  530 . 
     A threaded connection is provided at  556  between the upper cap  555  and the inner mandrel  560  and at  558  between the upper cap  555  and body  510 . The upper cap  555  sealingly engages the body  510  at  505 , and sealingly engages the inner mandrel  560  at  562  and  564 . A wrench slot  554  is provided between the upper cap  555  and the spring retainer  550 , which provides room for a wrench to be inserted to adjust the position of the spring retainer  550  in the body  510 . Spring retainer  550  connects at  551  via threads to the body  510 . Towards the lower end of the spring retainer  550 , a bore  552  is provided through which a bar can be placed to prevent rotation of the spring retainer  550  during assembly. For safety purposes, a spring cover  542  is bolted at  546  to the stop ring  544 . The spring cover  542  prevents personnel from incurring injury during assembly and testing of the tool  500 . 
     The moveable arms  520  include pads  522 ,  524 , and  526  with structures  700 ,  800  that engage the borehole when the arms  520  are expanded outwardly to the expanded position of the tool  500  shown in  FIG. 5 . Below the arms  520 , the piston  530  sealingly engages the inner mandrel  560  at  566 , and sealingly engages the body  510  at  534 . The lower cap  580  is threadingly connected to the body and to the lower retainer  590  at  582 ,  584 , respectively. A sealing engagement is also provided at  586  between the lower cap  580  and the body  510 . The lower cap  580  provides a stop for the piston  530  to control the collapsed diameter of the tool  500 . 
     Several components are provided for assembly rather than for functional purposes. For example, the drive ring  570  is coupled to the piston  530 , and then the drive ring block  572  is boltingly connected at  574  to prevent the drive ring  570  and the piston  530  from translating axially relative to one another. The drive ring block  572 , therefore, provides a locking connection between the drive ring  570  and the piston  530 . 
       FIG. 5  depicts the tool  500  with the moveable arms  520  in the maximum expanded position, extending radially outwardly from the body  510 . Once the tool  500  is in the borehole, it is only expandable to one position. Therefore, the tool  500  has two operational positions—namely a collapsed position as shown in  FIG. 4  or an expanded position as shown in  FIG. 5 . However, the spring retainer  550 , which is a threaded sleeve, can be adjusted at the surface to limit the full diameter expansion of arms  520 . The spring retainer  550  compresses the biasing spring  540  when the tool  500  is collapsed, and the position of the spring retainer  550  determines the amount of expansion of the arms  520 . The spring retainer  550  is adjusted by a wrench in the wrench slot  554  that rotates the spring retainer  550  axially downwardly or upwardly with respect to the body  510  at threads  551 . The upper cap  555  is also a threaded component that locks the spring retainer  550  once it has been positioned. 
     In the expanded position shown in  FIG. 5 , the arms  520  will either underream the borehole or stabilize the drilling assembly, depending upon how the pads  522 ,  524  and  526  are configured. In the configuration of  FIG. 5 , cutting structures  700  on pads  526  would underream the borehole. Wear buttons  800  on pads  522  and  524  would provide gauge protection as the underreaming progresses. Hydraulic force causes the arms  520  to expand outwardly to the position shown in  FIG. 5  due to the differential pressure of the drilling fluid between the flowbore  508  and the annulus  22 . 
     The drilling fluid flows along path  605 , through ports  595  in the lower retainer  590 , along path  610  into the piston chamber  535 . The differential pressure between the fluid in the flowbore  508  and the fluid in the borehole annulus  22  surrounding tool  500  causes the piston  530  to move axially upwardly from the position shown in  FIG. 4  to the position shown in  FIG. 5 . A small amount of flow can move through the piston chamber  535  and through nozzles  575  to the annulus  22  as the tool  500  starts to expand. As the piston  530  moves axially upwardly in pocket recesses  516 , the piston  530  engages the drive ring  570 , thereby causing the drive ring  570  to move axially upwardly against the moveable arms  520 . The arms  520  will move axially upwardly in pocket recesses  516  and also radially outwardly as the arms  520  travel in channels  518  disposed in the body  510 . In the expanded position, the flow continues along paths  605 ,  610  and out into the annulus  22  through nozzles  575 . Because the nozzles  575  are part of the drive ring  570 , they move axially with the arms  520 . Accordingly, these nozzles  575  are positioned to continuously provide cleaning and cooling to the cutting structures  700  disposed on surface  526  as fluid exits to the annulus  22  along flow path  620 . 
     As described above in  FIGS. 4 and 5 , the expandable tool in U.S. Pat. No. 6,732,817 includes a fluid flow path from the flowbore  508  through ports  595  and piston cavity  535  to the nozzle  575 , where the fluid flow path provides drilling fluid for removal of cuttings generated by the reamer cutting structures. 
     As one skilled in the art would recognize, in some drilling environments and under various drilling conditions, cutting elements may suffer thermal degradation due to frictional abrasive contact with the formation. Additionally, if cuttings generated are not removed at a fast enough rate, an increase in frictional contact on the cutting elements may result, leading to damage or premature failure in the form of heat cracks or carbide wear. It is thus of great importance to have a system that can remove the cuttings at a fast rate and provide sufficient cooling of the cutting elements. 
     It has surprisingly been found that a fluid flow path may be provided through the reamer body to increase the hydraulic energy at the reamer cutting structures. An increase in hydraulic energy at the cutting structures may advantageously improve the rate of removal of cuttings from the cutting structures (improved cuttings evacuation), may decrease cutter element wear, and may prevent damage or premature failure. Improved cuttings evacuation may also provide for improved cutting action and increased rates of reaming and cuttings removal, which may allow for an improvement in the overall rate of penetration. 
     Referring now to  FIGS. 6-7 , one embodiment of an expandable tool  1600  according to embodiments disclosed herein is illustrated, shown in a collapsed position in  FIG. 6  and in an expanded position in  FIG. 7 , where like numerals represent like parts. Lower retainer  590  includes ports  595  that allow drilling fluid to flow from the flowbore  508  into the piston chamber  535  to actuate the piston  530 . The drilling fluid flows along path  605 , through ports  595  in the lower retainer  590 , along path  1610  into the piston chamber  535 . The differential pressure between the fluid in the flowbore  508  and the fluid in the borehole annulus  22  surrounding tool  1600  causes the piston  530  to move axially upwardly from the position shown in  FIG. 6  to the position shown in  FIG. 7 . 
     In the expanded position shown in  FIG. 7 , an amount of fluid can flow from the piston chamber  535  via a fluid flowbore  1620 , provided through the cylindrical tool body  1630 , and through nozzles  575  to the annulus  22  as the tool  1600  starts to expand. As the piston moves axially upwardly in pocket recesses  516 , the piston  530  engages the drive ring  570 , thereby causing the drive ring  570  to move axially upwardly against the moveable arms  520 . The arms  520  will move axially upwardly in pocket recesses  516  and also radially outwardly as the arms  520  travel in channels  518  ( FIG. 6 ) disposed in the body  1630 . In the expanded position, the fluid flow continues along paths  605 ,  1610  and out into the annulus  22  through nozzles  575 . 
     In the embodiment illustrated in  FIGS. 6 and 7 , the nozzles  575  may be located in the drive ring  570 . To provide for fluid communication between flowbore  1620  and nozzle  575 , one end of a flow-carrying piston  1640  may be connected to drive ring  570  or drive ring retainer  572 , with the other end movably disposed in the body  1630 . A through-bore  1642 ,  1644  may be provided in drive ring  570  and drive ring retainer  572 , as needed, to complete the flow path from flowbore  1620  through flow-carrying piston  1640  to nozzle  575 . 
     As the piston  530  engages the drive ring  570 , the drive ring  570  and/or drive ring retainer  572  move axially upwardly, thus also moving the flow-carrying piston  1640  axially upwardly within the flowbore  1620 , effectively extending the flow channel for transporting fluid from the flowbore  1620  to the nozzle  575 . If necessary, the flow-carrying piston  1640  may be appropriately sealed against the body  1630  using sealing elements  1650  to avoid any leakage of fluid from flowbore  1620  to the annulus  22  and bypassing flow-carrying piston  1640  and nozzle  575 . 
     Through use of a flowbore provided in the cylindrical tool body itself, drilling fluid may thus be emitted through the nozzles at a higher velocity and impinged on the cutting elements at a higher hydraulic energy as compared to use of the flow path as described with respect to  FIGS. 4 and 5 . 
     Referring now to  FIGS. 8-9 , another embodiment of an expandable tool  1800  according to embodiments disclosed herein is illustrated, shown in a collapsed position in  FIG. 8  and in an expanded position in  FIG. 9 , where like numerals represent like parts. Lower retainer  590  includes ports  595  that allow drilling fluid to flow from the flowbore  508  into the piston chamber  535  to actuate the piston  530 . The drilling fluid flows along path  605 , through ports  595  in the lower retainer  590 , along path  1810  into the piston chamber  535 . The differential pressure between the fluid in the flowbore  508  and the fluid in the borehole annulus  22  surrounding tool  1800  causes the piston  530  to move axially upwardly from the position shown in  FIG. 8  to the position shown in  FIG. 9 . 
     In the expanded position shown in  FIG. 9 , an amount of fluid can flow from the piston chamber  535  via a fluid flowbore  1820 , provided through the cylindrical tool body  1830  as the tool  1800  starts to expand. As the piston moves axially upwardly in pocket recesses  516 , the piston  530  engages the drive ring  570 , thereby causing the drive ring  570  to move axially upwardly against the moveable arms  520 . The arms  520  will move axially upwardly in pocket recesses  516  and also radially outwardly as the arms  520  travel in channels  518  disposed in the body  1630 . In the expanded position, the fluid flow continues along paths  605 ,  1810  and out into the annulus  22  through nozzles  1875 . 
     In the embodiment illustrated in  FIGS. 8 and 9 , the nozzles  1875  may be located proximate the cutting structures  700  in moveable arms  1700 . To provide for fluid communication between flowbore  1820  and nozzle  1875 , one end of a flow-carrying piston  1840  may be connected to drive ring  570  or drive ring retainer  572 , with the other end movably disposed in the body  1830 . A through-bore  1842 ,  1844  may be provided in drive ring  570  and drive ring retainer  572 , as needed, to complete the flow path from flowbore  1820  through flow-carrying piston  1840  to an upper end of drive ring  570 . A fluid flow path  1860  is also provided through the interior of moveable arm  1700  to nozzles  1875 . In the collapsed position, as illustrated in  FIG. 8 , the flow path in the drive ring  570  (such as bore  1842  or upper end of piston  1840 ) will not be aligned with the flow path  1860  in moveable arm  1700 . 
     As the piston  530  engages the drive ring  570 , the drive ring  570  and/or drive ring retainer  572  move axially upwardly, thus also moving the flow-carrying piston  1840  axially upwardly within the flowbore  1820 , effectively extending the flow channel for transporting fluid through flowbore  1820 . If necessary, the flow-carrying piston  1840  may be appropriately sealed against the body  1830  using sealing elements  1850  to avoid any leakage of fluid from flowbore  1820  to the annulus  22  and bypassing flow-carrying piston  1840  and nozzle  1875 . A face seal  1870  may also be provided on the drive ring  570  to prevent leakage of fluid to the annulus  22  when in the collapsed position or during translation to the expanded position. When the moveable arm  1700  is fully expanded, flow path  1860  is aligned with the flow path provided through the drive ring  570 , thus allowing flow of fluid from flowbore  1820  through flow path  1860  to nozzle  1875 . 
     Through use of a flowbore provided in the cylindrical tool body itself and location of nozzles on moveable arm  1700 , drilling fluid may be emitted through the nozzles at a higher velocity and impinged on the cutting elements  700  at a higher hydraulic energy as compared to use of the flow path described with respect to  FIGS. 4 and 5 . 
       FIGS. 10 and 10A  illustrated an alternative embodiment for impinging drilling fluid on the cutting elements at a higher hydraulic energy, where like numerals represent like parts. In this embodiment, expandable tool  2000  includes at least one moveable arm  520  that includes at least one nozzle  2002 . Nozzle  2002 , located on the arm  520 , may be located and used to direct drilling fluid across cutting structures  700 ,  800  that engage the borehole when the arms  520  are expanded. To deliver the drilling fluid at a higher velocity (i.e., having a lower pressure drop between the inner bore and the nozzle outlet), one or more fluid flow paths  2004  may be provided through the moveable arm  520  to provide fluid communication between the flowbore  508  and nozzles  2002 . 
     In some embodiments, fluid flow paths  2004  may be in direct fluid communication with the fluid in flowbore  508 . In other embodiments, such as shown in  FIGS. 10 and 10A , a flow conduit  2006  may be provided for transporting fluid from the axial flowbore  508  to the at least one fluid flow path  2004 . In some embodiments, flow conduit  2006  may be a flexible flow conduit. 
     In some embodiments, flow of fluids through one or more of flow conduit(s)  2006 , flow path(s)  2004 , and nozzle(s)  2002  may be continuous, whether the arm is expanded or not, due to the differential pressure between flowbore  508  and annulus  22 . 
     In other embodiments, flow of fluids through one or more of flow conduit(s)  2006 , flow path(s)  2004 , and nozzle(s)  2002  may be actuated when the arm is expanded. For example, expandable tool  2000  may include an inner flow control member (not illustrated) having ports therethrough that (a) prevent fluid communication between the axial flowbore  508  and nozzle  2002  when the arm  520  is in a collapsed position, and (b) enable fluid communication between the axial flowbore and nozzle  2002  when the arm  520  is in an expanded or partially expanded position. 
     Referring now to  FIGS. 11-13 , additional alternative embodiments for impinging drilling fluid on the cutting elements at a higher hydraulic energy are illustrated, where like numerals represent like parts. In the embodiment illustrated in  FIGS. 11 and 11A , expandable tool  2100  includes at least one flow directing element  2102 , the purpose of which is to decrease the flow area between the annulus formed between the expandable downhole tool  2100  and the wellbore, and to direct the flow of drilling fluid in the annulus toward the cutting structures  700 ,  800 . In this manner, the reduced flow area necessarily results in an increase in annulus fluid velocity, and as the flow is directed toward or over the cutting structures  700 ,  800 , improvements in cooling of the cutting structure and removal of drill cuttings may be realized. 
     In some embodiments, flow directing elements  2102  may include a raised portion  2104  and a fluid flow path  2106 , for example. The raised portion may provide for the decreased annular flow area, and the fluid flow path  2106  may be used to direct the flow directly on to the cutting elements. 
     As illustrated in  FIGS. 11 and 11A , the arms  520  of expandable tool  2100  include two rows of cutting structures  700 ,  800 , where flow directing elements  2102  are provided to improve flow hydraulics proximate the second row of cutting structures. As illustrated for the expandable tool  2200  in  FIGS. 12 and 12A , one or more flow directing elements  2110  may be provided to similarly improve flow hydraulics proximate the first row of cutting structures.  FIG. 13  illustrates an expandable tool  2300  including both flow directing elements  2102  and  2110  to improve flow hydraulics proximate both the first and second rows of cutting structures. 
     The flow directing elements illustrated in  FIGS. 11-13  may be used alone or in conjunction with the embodiments as illustrated in any one of  FIGS. 4-10 . 
     In operation, an expandable tool ( 1600 ,  1800 ,  2000 ,  2100 ,  2200 ,  2300 ) is lowered through casing in the collapsed position, such as shown in  FIGS. 6 and 8 , respectively. The tool may then be expanded automatically when drilling fluid flows through flowbore  508 . If more than one tool according to embodiments herein is used, as a stabilizer for example, the second embodiment of the tool would be expanded only after selectively actuating the tool. Whether the feature of selective actuation is present or not, the tools expand due to differential pressure between the flowbore  508  and the wellbore annulus  22  acting on the piston  530 . That differential pressure may be in the range of 800 to 1,500 psi. Therefore, differential pressure working across the piston  530  will cause the one or more arms  520  of the tool to move from a collapsed to an expanded position against the force of the biasing spring  540 . 
     Before the drilling assembly is lowered into the borehole, the function of the expandable tools described herein as either an underreamer or as a stabilizer would be determined. Referring again to  FIG. 1 , one example would be to use either embodiment of the tool ( 1600 ,  1800 ,  2000 ,  2100 ,  2200 ,  2300 ) in the position of underreamer  120  and in the position of stabilizer  150 . As another example, referring to  FIGS. 2 and 3 , if a winged reamer  220  or a bi-center bit  320  is used instead of an underreamer  120 , the tool ( 1600 ,  1800 ,  2000 ,  2100 ,  2200 ,  2300 ) would preferably be used in the position of stabilizer  150 . As an underreamer, embodiments of the expandable tools disclosed herein are capable of underreaming a borehole to a desired diameter. As a stabilizer, embodiments of the expandable tools disclosed herein provide directional control for the assembly  100 ,  200 ,  300  within the underreamed borehole  25 . 
     In summary, the various embodiments of the expandable tools disclosed herein may be used as an underreamer to enlarge a borehole below a restriction to a larger diameter. Alternatively, the various embodiments of the expandable tool may be used to stabilize a drilling system in a previously underreamed borehole, or in a borehole that is being underreamed while drilling progresses. Embodiments of the tools disclosed herein may also provide pressure indications at the surface regarding whether the tool is collapsed or expanded. 
     The various embodiments of the expandable tools disclosed herein have a higher hydraulic capacity than prior art underreamers. An increase in hydraulic energy delivered to the cutting structures may advantageously improve the rate of removal of cuttings from the cutting structures (improved cuttings evacuation), may decrease cutter element wear, and may prevent damage or premature failure. Improved cuttings evacuation may also provide for improved cutting action and increased penetration rates. 
     While the disclosure includes a limited number of embodiments, those skilled in the art, having benefit of this disclosure, will appreciate that other embodiments may be devised which do not depart from the scope of the present disclosure. Accordingly, the scope should be limited only by the attached claims.