Patent Publication Number: US-11377909-B2

Title: Extendable cutting tools for use in a wellbore

Description:
BACKGROUND OF THE INVENTION 
     Field of the Invention 
     Embodiments of the present invention generally relate to extendable cutting tools for use in a wellbore. 
     Description of the Related Art 
     A wellbore is formed to access hydrocarbon bearing formations, e.g. crude oil and/or natural gas, by the use of drilling. Drilling is accomplished by utilizing a drill bit that is mounted on the end of a tubular string, such as a drill string. To drill within the wellbore to a predetermined depth, the drill string is often rotated by a top drive or rotary table on a surface platform or rig, and/or by a downhole motor mounted towards the lower end of the drill string. After drilling to a predetermined depth, the drill string and drill bit are removed and a section of casing is lowered into the wellbore. An annulus is thus formed between the string of casing and the formation. The casing string is temporarily hung from the surface of the well. The casing string is cemented into the wellbore by circulating cement into the annulus defined between the outer wall of the casing and the borehole. The combination of cement and casing strengthens the wellbore and facilitates the isolation of certain areas of the formation behind the casing for the production of hydrocarbons. 
     It is common to employ more than one string of casing in a wellbore. In this respect, the well is drilled to a first designated depth with a drill bit on a drill string. The drill string is removed. A first string of casing is then run into the wellbore and set in the drilled out portion of the wellbore, and cement is circulated into the annulus behind the casing string. Next, the well is drilled to a second designated depth, and a second string of casing or liner, is run into the drilled out portion of the wellbore. If the second string is a liner string, the liner is set at a depth such that the upper portion of the second string of casing overlaps the lower portion of the first string of casing. The liner string may then be fixed, or “hung” off of the existing casing by the use of slips which utilize slip members and cones to frictionally affix the new string of liner in the wellbore. The second casing or liner string is then cemented. This process is typically repeated with additional casing or liner strings until the well has been drilled to total depth. In this manner, wells are typically formed with two or more strings of casing/liner of an ever-decreasing diameter. 
     As more casing/liner strings are set in the wellbore, the casing/liner strings become progressively smaller in diameter to fit within the previous casing/liner string. In a drilling operation, the drill bit for drilling to the next predetermined depth must thus become progressively smaller as the diameter of each casing/liner string decreases. Therefore, multiple drill bits of different sizes are ordinarily necessary for drilling operations. As successively smaller diameter casing/liner strings are installed, the flow area for the production of oil and gas is reduced. Therefore, to increase the annulus 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/lined borehole. By enlarging the borehole, a larger annulus is provided for subsequently installing and cementing a larger casing/liner 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/liner, thereby providing more flow area for the production of oil and/or gas. Underreamers also lessen the equivalent circulation density (ECD) while drilling the borehole. 
     In order to accomplish drilling a wellbore larger than the bore of the casing/liner, a drill string with an underreamer and pilot bit may be employed. Underreamers may include a plurality of arms which may move between a retracted position and an extended position. The underreamer may be passed through the casing/liner, behind the pilot bit when the arms are retracted. After passing through the casing, the arms may be extended in order to enlarge the wellbore below the casing. 
     SUMMARY OF THE INVENTION 
     Embodiments of the present invention generally relate to extendable cutting tools for use in a wellbore. In one embodiment, a tool for use in a wellbore includes a tubular body having a bore therethrough, an opening through a wall thereof, and a connector at each longitudinal end thereof; and an arm. The arm is pivotally connected to a first piston and rotationally coupled to the body. The arm is disposed in the opening in a retracted position, and is movable to an extended position where an outer surface of the arm extends outward past an outer surface of the body. The tool further includes the first piston. The first piston is disposed in the body bore, has a bore therethrough, and is operable to move the arm from the retracted position to the extended position in response to fluid pressure in the piston bore exceeding fluid pressure in the opening. The tool further includes a lock operable to retain the first piston in the retracted position; and a second piston operably coupled to the lock. 
     In another embodiment, a tool for use in a wellbore includes a tubular body having a bore therethrough and an opening through a wall thereof; and an arm. The arm is pivotally connected to the body or a first piston, disposed in the opening in a retracted position, and movable to an extended position where an outer surface of the arm extends outward past an outer surface of the body. The first piston is disposed in the body bore, has a bore therethrough, and is operable to move the arm from the retracted position to the extended position in response to fluid pressure in the piston bore exceeding fluid pressure in the opening. The tool further includes a lock operable to retain the piston in the retracted position; and a controller operable to release the lock in response to receiving an instruction signal. 
     In one aspect of the embodiment, the tool further includes a tachometer for measuring an angular speed of the body and in communication with the controller, wherein the controller is operable to receive the instruction signal using the tachometer. In another aspect of the embodiment, the tool further includes an antenna in communication with the controller, wherein the controller is operable to receive the instruction signal using the antenna. In another aspect of the embodiment, the tool further includes a pressure sensor or flow sensor, wherein the controller is operable to receive the instruction signal using the pressure or flow sensor. In another aspect of the embodiment, the tool further includes a mud pulser in communication with the controller, wherein the controller is operable to modulate the mud pulser to send a signal to the surface. In another aspect of the embodiment, the tool further includes a tachometer for measuring an angular speed of the body; and a pressure sensor or flow sensor and in communication with the controller, wherein the controller is operable to receive the instruction signal using either the tachometer or the pressure or flow sensor. 
     In another aspect of the embodiment, the tool further includes a sensor operable to measure a position of the first piston and in communication with the controller. Each of the body and the arm may have a shoulder and the shoulders may be engaged in the extended position. Each shoulder may be radially inclined to create a radially inward component of a normal reaction force between the arm and the body. In another aspect of the embodiment, the controller is operable to re-engage the lock in response to receiving a second instruction signal. The controller may also be operable to re-engage the lock when the arm is an intermediate position between the retracted and extended position. In another aspect of the embodiment, the tool further includes an actuator in communication with the controller, wherein the controller is operable to move the first piston toward the retracted position using the actuator, and the actuator is operable to move the first piston when fluid is being injected through the tool. 
     In another aspect of the embodiment, the tool may be used in a method including running a drilling assembly into the wellbore through a casing string, the drilling assembly comprising a tubular string, the tool, and a drill bit; injecting drilling fluid through the tubular string and rotating the drill bit, wherein the tool remains locked in the retracted position; sending an instruction signal from the surface to the tool, thereby extending the arm; and drilling and reaming the wellbore using the drill bit and the extended tool. The drilling assembly may further include a stabilizer and the instruction signal may also extend an arm of the stabilizer. The method may further include running an actuator through the tubular string to the tool using wireline or slickline; and retracting the arm using the actuator. 
     In another embodiment, a tool for use in a wellbore includes a tubular body having a bore therethrough and an opening through a wall thereof; and an arm. The arm is disposed in the opening in a retracted position, and movable to an extended position where an outer surface of the arm extends outward past an outer surface of the body. The tool further includes a first piston disposed in the body bore, having a bore therethrough, and operable to move the arm from the retracted position to the extended position in response to fluid pressure in the first piston bore exceeding fluid pressure in the opening. The tool further includes a lock operable to retain the first piston in the retracted position; a second piston operable to release the lock in response to fluid pressure; an actuator operable to move the piston and release the lock; and a controller operable to receive an instruction signal and operate the actuator. 
     In another embodiment, a method of drilling a wellbore includes running a drilling assembly into the wellbore through a casing string. The drilling assembly includes a tubular string, upper and lower underreamers, and a drill bit. The method further includes injecting drilling fluid through the tubular string and rotating the drill bit, wherein the underreamers remain locked in the retracted position; sending an instruction signal to the underreamers via modulation of a rotational speed of the drilling assembly, modulation of a drilling fluid injection rate, or modulation of a drilling fluid pressure, thereby extending one of the underreamers; and drilling and reaming the wellbore the drill bit and the extended underreamer; sending an instruction signal to the underreamers via modulation of a rotational speed of the drilling assembly, modulation of a drilling fluid injection rate, or modulation of a drilling fluid pressure, thereby extending the other of the underreamers; and drilling and reaming the wellbore using the drill bit and the extended other underreamer. 
     In another embodiment, a method of drilling a wellbore includes running a drilling assembly into the wellbore through a casing string, the drilling assembly including a tubular string, upper and lower underreamers, and a drill bit; injecting drilling fluid through the tubular string and rotating the drill bit, wherein the underreamers remain locked in the retracted position; sending an instruction signal to one of the underreamers, thereby extending one of the underreamers; drilling and reaming the wellbore the drill bit and the extended underreamer; pumping a closure member to the other of the underreamers or injecting drilling fluid through the drilling assembly at a flow rate greater than or equal to a predetermined flow rate, thereby extending the other of the underreamers; and drilling and reaming the wellbore using the drill bit and the extended other underreamer. 
     In another embodiment, a method of drilling a wellbore includes: running a drilling assembly into the wellbore through a casing string. The drilling assembly includes a tubular string, upper and lower underreamers, and a drill bit. The method further includes extending one of the underreamers; drilling and reaming a first geological formation using the drill bit and the extended underreamer; extending the other underreamer; and drilling and reaming a second geological formation using the drill bit and the extended other underreamer. 
     In another embodiment, a cutter for use in a wellbore, includes: a tubular body having a bore therethrough and an opening through a wall thereof; an arm disposed in the opening in a retracted position and movable to an extended position where an outer surface of the arm extends outward past an outer surface of the body; and a piston. The piston is disposed in the body bore, has a bore therethrough, and is operable to move the arm from the retracted position to the extended position in response to fluid pressure in the piston bore exceeding fluid pressure in the opening. The cutter further includes a controller operable to: receive a position signal from the surface, and move to a set position in response to the signal. 
     In another embodiment, a cutter for use in a wellbore includes a tubular body having a bore therethrough and an opening through a wall thereof; an arm disposed in the opening in a retracted position and movable to an extended position where an outer surface of the arm extends outward past an outer surface of the body; and a mandrel. The mandrel is disposed in the body bore, having a bore therethrough, and operable to move the arm from the retracted position to the extended position. The cutter further includes a controller operable to: receive a position signal from the surface, and move the mandrel to a set position in response to the position signal, thereby at least partially extending the arm. 
     In another embodiment, a method of cutting or milling a tubular cemented to a wellbore includes deploying a cutting assembly into the wellbore, the cutting assembly comprising a workstring and a cutter; sending an instruction signal to the cutter, thereby extending one or more arms of the cutter; and rotating the cutter, thereby milling or cutting the tubular. 
    
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
       So that the manner in which the above recited features of the present invention can be understood in detail, a more particular description of the invention, briefly summarized above, may be had by reference to embodiments, some of which are illustrated in the appended drawings. It is to be noted, however, that the appended drawings illustrate only typical embodiments of this invention and are therefore not to be considered limiting of its scope, for the invention may admit to other equally effective embodiments. 
         FIGS. 1A and 1B  are cross-sections of an underreamer in a retracted and extended position, respectively, according to one embodiment of the present invention.  FIG. 1C  is an isometric view of arms of the underreamer. 
         FIGS. 2A and 2B  are cross-sections of a mechanical control module connected to the underreamer in a retracted and extended position, respectively, according to another embodiment of the present invention. 
         FIG. 3  illustrates an electro-hydraulic control module for use with the underreamer, according to another embodiment of the present invention. 
         FIG. 4  illustrates a telemetry sub for use with the control module, according to another embodiment of the present invention.  FIG. 4A  illustrates an electronics package of the telemetry sub.  FIG. 4B  illustrates an active RFID tag and a passive RFID tag for use with the telemetry sub.  FIG. 4C  illustrates accelerometers of the telemetry sub.  FIG. 4D  illustrates a mud pulser of the telemetry sub. 
         FIGS. 5A and 5B  illustrate a drilling system and method utilizing the underreamer, according to another embodiment of the present invention. 
         FIG. 6A  illustrates an alternative electro-hydraulic control module for use with the underreamer, according to another embodiment of the present invention.  FIG. 6B  illustrates another alternative electro-hydraulic control module for use with the underreamer, according to another embodiment of the present invention.  FIG. 6C  illustrates an alternative electro-mechanical control module for use with the underreamer, according to another embodiment of the present invention. 
         FIG. 7A  illustrates a bottom hole assembly (BHA) including dual underreamers, according to another embodiment of the present invention.  FIGS. 7B and 7C  illustrates an operating sequence for the dual underreamers. 
         FIG. 8  illustrates an alternative dual underreamer BHA, according to another embodiment of the present invention. 
         FIG. 9  illustrates an underreamer arm configured for soft formations, according to another embodiment of the present invention. 
         FIG. 10A  is a cross section of a casing cutter in a retracted position, according to another embodiment of the present invention.  FIG. 10B  is a cross section of the casing cutter in an extended position.  FIG. 10C  is an enlargement of a portion of  FIG. 10A .  FIG. 10D  is a cross section of a portion of an alternative casing cutter. 
         FIG. 10E  is a cross section of a portion of an alternative casing cutter.  FIG. 10F  is a cross section of an alternative casing cutter in an extended position. 
         FIG. 11A  is a cross section of a section mill in a retracted position, according to another embodiment of the present invention.  FIG. 11B  is an enlargement of a portion of  FIG. 11A . 
         FIGS. 12A-12C  are cross-sections of a mechanical control module in a first retracted, extended, and second retracted position, respectively, according to another embodiment of the present invention. 
         FIGS. 13A and 13B  are cross-sections of an underreamer in an extended and second retracted position, respectively, according to another embodiment of the present invention. 
         FIGS. 14A and 14B  are cross-sections of a hydraulic control module in a retracted and extended position, respectively, according to another embodiment of the present invention. 
     
    
    
     DETAILED DESCRIPTION 
       FIGS. 1A and 1B  are cross-sections of an underreamer  100  in a retracted and extended position, respectively, according to one embodiment of the present invention. 
     The underreamer  100  may include a body  5 , an adapter  7 , a piston  10 , one or more seal sleeves  15   u,l , a mandrel  20 , and one or more arms  50   a,b  (see  FIG. 1C  for  50   b ). The body  5  may be tubular and have a longitudinal bore formed therethrough. Each longitudinal end  5   a,b  of the body  5  may be threaded for longitudinal and rotational coupling to other members, such as a control module  200  at  5   a  and the adapter  7  at  5   b . The body  5  may have an opening  5   o  formed through a wall thereof for each arm  50   a,b . The body  5  may also have a chamber formed therein at least partially defined by shoulder  5   s  for receiving a lower end of the piston  10  and the lower seal sleeve  15   l . The body  5  may include an actuation profile  5   p  formed in a surface thereof for each arm  50   a,b  adjacent the opening  5   o . An end of the adapter  7  distal from the body (not shown) may be threaded for longitudinal and rotational coupling to another member of a bottomhole assembly (BHA). 
     The piston  10  may be a tubular, have a longitudinal bore formed therethrough, and may be disposed in the body bore. The piston  10  may have a flow port  10   p  formed through a wall thereof corresponding to each arm  50   a,b . A nozzle  14  may be disposed in each port  10   p  and made from an erosion resistant material, such as a metal, alloy, ceramic, or cermet. The mandrel  20  may be tubular, have a longitudinal bore formed therethrough, and be longitudinally coupled to the lower seal sleeve  15   l  by a threaded connection. The lower seal sleeve  15   l  may be longitudinally coupled to the body  5  by being disposed between the shoulder  5   s  and a top of the adapter  7 . The upper seal sleeve  15   u  may be longitudinally coupled to the body  5  by a threaded connection. 
     Each arm  50   a,b  may be movable between an extended and a retracted position and may initially be disposed in the opening  5   o  in the retracted position. Each arm  50   a,b  may be pivoted to the piston  10  by a fastener  25 . Each arm  50   a,b  may be biased radially inward by a torsion spring (not shown) disposed around the fastener  25 . A surface of the body  5  defining each opening  5   o  may serve as a rotational stop for a respective blade  50   a,b , thereby rotationally coupling the blade  50   a,b  to the body  5  (in both the extended and retracted positions). Each arm  50   a,b  may include an actuation profile  50   p  formed in an inner surface thereof corresponding to the profile  5   p . Movement of each arm  50   a,b  along the actuation profile  5   p  may force the arm radially outward from the retracted position to the extended position. Each actuation profile  5   p ,  50   p  may include a shoulder. The shoulders may be inclined relative to a radial axis of the body  5  in order to secure each arm  50   a,b  to the body in the extended position so that the arms do not chatter or vibrate during reaming. The inclination of the shoulders may create a radial component of the normal reaction force between each arm and the body  5 , thereby holding each arm  50   a,b  radially inward in the extended position. Additionally, the actuation profiles  5   p ,  50   p  may each be circumferentially inclined (not shown) to retain the arms  50   a,b  against a trailing surface of the body defining the opening  5   o  to further ensure against chatter or vibration. 
     The underreamer  100  may be fluid operated by drilling fluid injected through the drill string being at a high pressure and drilling fluid and cuttings, collectively returns, flowing to the surface via the annulus being at a lower pressure. A first surface  10   h  of the piston  10  may be isolated from a second surface  10   l  of the piston  10  by a lower seal  12   l  disposed between an outer surface of the piston  10  and an inner surface of the lower seal sleeve  15   l . The lower seal  12   l  may be a ring or stack of seals, such as chevron seals, and made from a polymer, such as an elastomer. The high pressure may act on the first surface  10   h  of the piston via one or more ports formed through a wall of the mandrel  20  and the low pressure may act on the second surface  10   l  of the piston  10  via fluid communication with the openings  5   o , thereby creating a net actuation force and moving the arms  50   a,b  from the retracted position to the extended position. An upper seal  12   u  may be disposed between the upper seal sleeve  15   u  and an outer surface of the piston  10  to isolate the openings  5   o . The upper seal  12   u  may be a ring or stack of seals, such as chevron seals, and made from a polymer, such as an elastomer. Various other seals, such as o-rings may be disposed throughout the underreamer  100 . 
     In the retracted position, the piston ports  10   p  may be closed by the mandrel  20  and straddled by seals, such as o-rings, to isolate the ports from the piston bore. In the extended position, the flow ports  10   p  may be exposed to the piston bore, thereby discharging a portion of the drilling fluid into the annulus to cool and lubricate the arms  50   a,b  and carry cuttings to the surface. This exposure of the flow ports  10   p  may result in a drop in upstream pressure, thereby providing an indication at the surface that the arms  50   a,b  are extended. 
       FIG. 1C  is an isometric view of the arms  50   a,b . An outer surface of each arm  50   a,b  may form one or more blades  51   a,b  and a stabilizer pad  52  between each of the blades. Cutters  55  may be bonded into respective recesses formed along each blade  51   a,b . The cutters  55  may be made from a super-hard material, such as polycrystalline diamond compact (PDC), natural diamond, or cubic boron nitride. The PDC may be conventional, cellular, or thermally stable (TSP). The cutters  55  may be bonded into the recesses, such as by brazing, welding, soldering, or using an adhesive. Alternatively, the cutters  55  may be pressed or threaded into the recesses. Inserts, such as buttons  56 , may be disposed along each pad  52 . The inserts  56  may be made from a wear-resistant material, such as a ceramic or cermet (e.g., tungsten carbide). The inserts  56  may be brazed, welded, or pressed into recesses formed in the pad  52 . 
     The arms  50   a,b  may be longitudinally aligned and circumferentially spaced around the body  5  and junk slots  5   r  may be formed in an outer surface of the body between the arms. The junk slots  5   r  may extend the length of the openings  5   o  to maximize cooling and cuttings removal (both from the drill bit and the underreamer). The arms  50   a,b  may be concentrically arranged about the body  5  to reduce vibration during reaming. The underreamer  100  may include a third arm (not shown) and each arm may be spaced at one-hundred twenty degree intervals. The arms  50   a,b  may be made from a high strength metal or alloy, such as steel. The blades  51   a,b  may each be arcuate, such as parabolic, semi-elliptical, semi-oval, or semi-super-elliptical. The arcuate blade shape may include a straight or substantially straight gage portion  51   g  and curved leading  51   l  and trailing  51   t  ends, thereby allowing for more cutters  55  to be disposed at the gage portion thereof and providing a curved actuation surface against a previously installed casing shoe when retrieving the underreamer  100  from the wellbore should the actuator spring be unable to retract the blades. Cutters  55  may be disposed on both a leading and trailing surface of each blade for back-reaming capability. The cutters in the leading and trailing ends of each blade may be super-flush with the blade. The gage portion may be raised and the gage-cutters flattened and flush with the blade, thereby ensuring a concentric and full-gage hole. 
     Alternatively, the cutters  55  may be omitted and the underreamer  100  may be used as a stabilizer instead. 
       FIGS. 2A and 2B  are cross-sections of a mechanical control module  200  connected to the underreamer  100  in a retracted and extended position, respectively, according to another embodiment of the present invention. The control module  200  may include a body  205 , a control mandrel  210 , a piston housing  215 , a piston  220 , a keeper  225 , a lock mandrel  230 , and a biasing member  235 . The body  205  may be tubular and have a longitudinal bore formed therethrough. Each longitudinal end  205   a,b  of the body  205  may be threaded for longitudinal and rotational coupling to other members, such as the underreamer  100  at  205   b  and a drill string at  205   a.    
     The biasing member may be a spring  235  and may be disposed between a shoulder  210   s  of the control mandrel  210  and a shoulder of the lock mandrel  230 . The spring  235  may bias a longitudinal end of the control mandrel or a control module adapter  212  into abutment with the underreamer piston end  10   t , thereby also biasing the underreamer piston  210  toward the retracted position. The control module adapter  212  may be longitudinally coupled to the control mandrel  210 , such as by a threaded connection, and may allow the control module  200  to be used with differently configured underreamers by changing the adapter  212 . The control mandrel  210  may be longitudinally coupled to the lock mandrel  230  by a latch or lock, such as a plurality of dogs  227 . Alternatively, the latch or lock may be a collet. The dogs  227  may be held in place by engagement with a lip  225   l  of the keeper  225  and engagement with a lip  210   l  of the control mandrel  210 . The lock mandrel  230  may be longitudinally coupled to the piston housing  215  by a threaded connection and may abut a body shoulder  205   s  and the piston housing  215 . 
     The piston housing  215  may be longitudinally coupled to the body  205  by a threaded connection. The piston  220  may be longitudinally coupled to the keeper  225  by one or more fasteners, such as set screws  224 , and by engagement of a piston end  220   b  with a keeper shoulder  225   s . The set screws  224  may each be disposed through a respective slot formed through a wall of the piston  220  so that the piston may move longitudinally relative to the keeper  225 , the movement limited by a length of the slot. The keeper  225  may be longitudinally movable relative to the body  205 , the movement limited by engagement of the keeper shoulder  225   s  with a piston housing shoulder  215   s  and engagement of a keeper longitudinal end with a lock mandrel shoulder  230   s . The piston  220  may be longitudinally coupled to the piston housing  215  by one or more frangible fasteners, such as shear screws  222 . The piston  220  may have a seat  220   s  formed therein for receiving a closure element, such as a ball  290 , plug, or dart. A nozzle  214  may be disposed in a bore of the piston  220  and made from an erosion resistant material, such as a metal, alloy, ceramic, or cermet. 
     When deploying the underreamer  100  and control module  200  in the wellbore, a drilling operation (e.g., drilling through a casing shoe) may be performed without operation of the underreamer  100 . Even though force is exerted on the underreamer piston  10  by drilling fluid, the shear screws  222  may prevent the underreamer piston  10  from extending the arms  50   a,b . When it is desired to operate the underreamer  100 , the ball  290  is pumped or dropped from the surface and lands in the ball seat  220   s . Drilling fluid continues to be injected or is injected through the drill string. Due to the obstructed piston bore, fluid pressure acting on the ball  290  and piston  220  increases until the shear screws  222  are fractured, thereby allowing the piston to move longitudinally relative to the body  205 . The piston end  220   b  may then engage the keeper shoulder  225   s  and push the keeper  225  longitudinally relative to the body  205 , thereby disengaging the keeper lip  225   l  from the dogs  227 . The control mandrel lip  210   l  may be inclined and force exerted on the control mandrel  210  by the underreamer piston  10  may push the dogs  227  radially outward into a radial gap defined between the lock mandrel  230  and the keeper  225 , thereby freeing the control mandrel and allowing the underreamer piston  10  to extend the arms  50   a,b . Movement of the piston  220  may also expose a piston housing bore and place bypass ports  220   p  formed through a wall of the piston  220  in fluid communication therewith. 
     Alternatively, the control mandrel  210  may be released by increasing an injection rate of the drilling fluid to or past a predetermined flow rate instead of using the ball  290 . The casing shoe may be drilled through without operation of the underreamer  100  by maintaining the injection rate below or substantially below the predetermined flow rate. When the injection rate of the drilling fluid is increased to or past the predetermined rate, the drilling fluid is choked through the nozzle  214 , thereby exerting a longitudinal force on the piston  220  downward or toward the underreamer  100 . Simultaneously, the underreamer piston  10  exerts longitudinal force via the control mandrel  210  onto dogs  227  upward or toward the body connector  205   a , thereby pushing the dogs  227  radially against the keeper  225  and exerting a longitudinal friction force on the keeper  225  upward or toward the body connector  205   a . If the piston  220  and keeper  225  were a single integral piece, the friction force would counteract the piston force created by differential pressure across the nozzle  214 . By allowing the initial longitudinal movement between piston  220  and keeper  225 , the piston  220  may fracture the screws  222  first without having to overcome the friction force as well and then engage the keeper  225  and overcome the isolated friction force. 
     Alternatively, if the flow rate operation option is not needed, the nozzle  214  may be omitted and the keeper  225  and piston  220  may be formed as an integral piece, thereby also omitting the fastener  224 . 
       FIG. 3  illustrates an electro-hydraulic control module  300  for use with the underreamer  100 , according to another embodiment of the present invention. The control module  300  may be used instead of the control module  200 . The control module  300  may include an outer tubular body  341 . The lower end of the body  341  may include a threaded coupling, such as pin  342 , connectable to the threaded end  5   a  of the underreamer  100 . The upper end of the body  341  may include a threaded coupling, such as box  343 , connected to a threaded coupling, such as lower pin  346 , of the retainer  345 . The retainer  345  may have threaded couplings, such as pins  346  and  347 , formed at its ends. The upper pin  347  may connect to a threaded coupling, such as box  408   b , of a telemetry sub  400 . 
     The tubular body  341  may house an interior tubular body  350 . The inner body  350  may be concentrically supported within the tubular body  341  at its ends by support rings  351 . The support rings  351  may be ported to allow drilling fluid flow to pass into an annulus  352  formed between the two bodies  341 ,  350 . The lower end of tubular body  350  may slidingly support a positioning piston  355 , the lower end of which may extend out of the body  350  and may engage piston end  10   t.    
     The interior of the piston  355  may be hollow in order to receive a longitudinal position sensor  360 . The position sensor  360  may include two telescoping members  361  and  362 . The lower member  362  may be connected to the piston  355  and be further adapted to travel within the first member  361 . The amount of such travel may be electronically measured. The position sensor  360  may be a linear potentiometer. The upper member  361  may be attached to a bulkhead  365  which may be fixed within the tubular body  350 . 
     The bulkhead  365  may have a solenoid operated valve  366  and passage extending therethrough. The bulkhead  365  may further include a pressure switch  367  and passage. A conduit tube (not shown) may be attached at its lower end to the bulkhead  365  and at its upper end to and through a second bulkhead  369  to provide electrical communication for the position sensor  360 , the solenoid valve  366 , and the pressure switch  367 , to a battery pack  370  located above the second bulkhead  369 . The batteries may be high temperature lithium batteries. A compensating piston  371  may be slidingly positioned within the body  350  between the two bulkheads  365 , 369 . A spring  372  may be located between the piston  371  and the second bulkhead  369 , and the chamber containing the spring may be vented to allow the entry of drilling fluid. 
     A tube  301  may be disposed in the connector sub  345  and may house an electronics package  325 . The electronics package  325  may include a controller, such as microprocessor, power regulator, and transceiver. Electrical connections  377  may be provided to interconnect the power regulator to the battery pack  370 . A data connector  378  may be provided for data communication between the microprocessor  325  and the telemetry sub  400 . The data connector may include a short-hop electromagnetic telemetry antenna  378 . 
     Hydraulic fluid (not shown), such as oil, may be disposed in a lower chamber defined by the positioning piston  355 , the bulkhead  365 , and the body  350  and an upper chamber defined by the compensating piston  371 , the bulkhead  365 , and the body  350 . The spring  372  may bias the compensating piston  371  to push hydraulic oil from the upper reservoir, through the bulkhead passage and valve, thereby extending the positioning piston into engagement with the underreamer piston  10  and biasing the underreamer piston toward the retracted position. Alternatively, the underreamer  100  may include its own return spring and the spring  372  may be used maintain engagement of the positioning piston  355  with the underreamer piston  10 . The solenoid valve  366  may be a check valve operable between a closed position where the valve functions as a check valve oriented to prevent flow from the lower chamber to the upper chamber and allow reverse flow therethrough, thereby fluidly locking the underreamer  100  in the retracted position and an open position where the valve allows flow through the passage (in either direction). Alternatively, a solenoid operate shutoff valve may be used instead of the check valve. To allow extension of the underreamer  100 , the valve  366  may be opened when drilling fluid is flowing. The underreamer piston  10  may then actuate and push the positioning piston  355  toward the lower bulkhead  365 . 
     The position sensor  360  may measure the position of the piston  355 . The controller  325  may monitor the sensor  360  to verify that the piston  355  has been actuated. The differential pressure switch  367  in the lower bulkhead  365  may verify that the underreamer piston  10  has made contact with the positioning piston  355 . The force exerted on the piston  355  by the underreamer piston  310  may cause a pressure increase on that side of the bulkhead. Additionally, the underreamer  100  may be modified to be variable (see section mill  1100 ) and the controller  325  may close the valve  366  before the underreamer arms  50   a,b  are fully extended, thereby allowing the underreamer  100  to have one or more intermediate positions. Additionally, the controller may lock and unlock the underreamer  100  repeatedly. 
     In operation, the control module  300  may receive an instruction signal from the surface (discussed below). The instruction signal may direct the control module  300  to allow full or partial extension of the arms  50   a,b . The controller  325  may open the solenoid valve  366 . If drilling fluid is being circulated through the BHA, the underreamer piston  10  may then extend the arms  50   a,b . During extension, the controller  325  may monitor the arms using the pressure sensor  367  and the position sensor  361 . Once the arms have reached the instructed position, the controller  325  may close the valve  366 , thereby preventing further extension of the arms. The controller  325  may then report a successful extension of the arms or an error if the arms are obstructed from the instructed extension. Once the underreamer operation has concluded, the control module  300  may receive a second instruction signal to retract the arms. If the valve  366  is the check valve, the controller may open the valve or may not have to take action as the check valve may allow for hydraulic fluid to flow from the upper chamber to the lower chamber regardless of whether the valve is open or closed. The controller may simply monitor the position sensor and report successful retraction of the arms. If the valve  366  is a shutoff valve, the instruction signal may include a time at which the rig pumps are shut off or the controller  325  may wait for indication from the telemetry sub that the rig pumps are shut off. The controller may then open the valve to allow the retraction of the arms. Since the control module may not force retraction of the arms  50   a,b  the control module may be considered a passive control module. Advantageously, the passive control module may use less energy to operate than an active control module (discussed below). 
     As shown, components of the control module  300  are disposed in a bore of the body  341  and connector  345 . Alternatively, components of the control module may be disposed in a wall of the body  341 , similar to the telemetry sub  400 . The center configured control module  300  may allow for: stronger outer collar connections, a single size usable for different size underreamers or other downhole tools, and easier change-out on the rig floor. The annular alternative arranged control module may provide a central bore therethrough so that tools, such as a ball, may be run-through or dropped through the drill string. 
     Additionally, as illustrated in FIG. 7 of the &#39;198 provisional, a latch, such as a collet, may be formed in an outer surface of the position piston  355 . A corresponding profile may be formed in an inner surface of the interior body  350 . The latch may engage the profile when the position piston is in the retracted position. The latch may transfer at least a substantial portion of the underreamer piston  10  force to the interior body  350  when drilling fluid is injected through the underreamer  100 , thereby substantially reducing the amount of pressure required in the lower hydraulic chamber to restrain the underreamer piston. 
       FIG. 4  illustrates a telemetry sub  400  for use with the control module  300 , according to another embodiment of the present invention. The telemetry sub  400  may include an upper adapter  401 , one or more auxiliary sensors  402   a,b , an uplink housing  403 , a sensor housing  404 , a pressure sensor  405 , a downlink mandrel  406 , a downlink housing  407 , a lower adapter  408 , one or more data/power couplings  409   a,b , an electronics package  425 , an antenna  426 , a battery  431 , accelerometers  455 , and a mud pulser  475 . The housings  403 ,  404 ,  407  may each be modular so that any of the housings  403 ,  404 ,  407  may be omitted and the rest of the housings may be used together without modification thereof. Alternatively, any of the sensors or electronics of the telemetry sub  400  may be incorporated into the control module  300  and the telemetry sub  400  may be omitted. 
     The adapters  401 , 408  may each be tubular and have a threaded coupling  401   p ,  408   b  formed at a longitudinal end thereof for connection with the control module  300  and the drill string. Each housing may be longitudinally and rotationally coupled together by one or more fasteners, such as screws (not shown), and sealed by one or more seals, such as o-rings (not shown). 
     The sensor housing  404  may include the pressure sensor  405  and a tachometer  455 . The pressure sensor  405  may be in fluid communication with a bore of the sensor housing via a first port and in fluid communication with the annulus via a second port. Additionally, the pressure sensor  405  may also measure temperature of the drilling fluid and/or returns. The sensors  405 , 455  may be in data communication with the electronics package  425  by engagement of contacts disposed at a top of the mandrel  406  with corresponding contacts disposed at a bottom of the sensor housing  406 . The sensors  405 , 455  may also receive electricity via the contacts. The sensor housing  404  may also relay data between the mud pulser  475 , the auxiliary sensors  402   a,b , and the electronics package  425  via leads and radial contacts  409   a,b.    
     The auxiliary sensors  402   a,b  may be magnetometers which may be used with the accelerometers for determining directional information, such as azimuth, inclination, and/or tool face/bent sub angle. 
     The antenna  426  may include an inner liner, a coil, and an outer sleeve disposed along an inner surface of the downlink mandrel  406 . The liner may be made from a non-magnetic and non-conductive material, such as a polymer or composite, have a bore formed longitudinally therethrough, and have a helical groove formed in an outer surface thereof. The coil may be wound in the helical groove and made from an electrically conductive material, such as a metal or alloy. The outer sleeve may be made from the non-magnetic and non-conductive material and may be insulate the coil from the downlink mandrel  406 . The antenna  426  may be longitudinally and rotationally coupled to the downlink mandrel  406  and sealed from a bore of the telemetry sub  400 . 
       FIG. 4A  illustrates the electronics package  425 .  FIG. 4B  illustrates an active RFID tag  450   a  and a passive RFID tag  450   p . The electronics package  425  may communicate with a passive RFID tag  450   p  or an active RFID tag  450   a . Either of the RFID tags  450   a,p  may be individually encased and dropped or pumped through the drill string. The electronics package  425  may be in electrical communication with the antenna  426  and receive electricity from the battery  431 . Alternatively, the data sub  400  may include a separate transmitting antenna and a separate receiving antenna. The electronics package  425  may include an amplifier  427 , a filter and detector  428 , a transceiver  429 , a microprocessor  430 , an RF switch  434 , a pressure switch  433 , and an RF field generator  432 . 
     The pressure switch  433  may remain open at the surface to prevent the electronics package  425  from becoming an ignition source. Once the data sub  400  is deployed to a sufficient depth in the wellbore, the pressure switch  433  may close. The microprocessor  430  may also detect deployment in the wellbore using pressure sensor  405 . The microprocessor  430  may delay activation of the transmitter for a predetermined period of time to conserve the battery  431 . 
     When it is desired to operate the underreamer  100 , one of the tags  450   a,p  may be pumped or dropped from the surface to the antenna  426 . If a passive tag  450   p  is deployed, the microprocessor  430  may begin transmitting a signal and listening for a response. Once the tag  450   p  is deployed into proximity of the antenna  426 , the passive tag  450   p  may receive the signal, convert the signal to electricity, and transmit a response signal. The antenna  426  may receive the response signal and the electronics package  425  may amplify, filter, demodulate, and analyze the signal. If the signal matches a predetermined instruction signal, then the microprocessor  430  may communicate the signal to the underreamer control module  300  using the antenna  426  and the transmitter circuit. The instruction signal carried by the tag  450   a,p  may include an address of a tool (if the BHA includes multiple underreamers and/or stabilizers, discussed below) and a set position (if the underreamer/stabilizer is adjustable). 
     If an active tag  450   a  is used, then the tag  450   a  may include its own battery, pressure switch, and timer so that the tag  450   a  may perform the function of the components  432 - 434 . Further, either of the tags  450   a,p  may include a memory unit (not shown) so that the microprocessor  430  may send a signal to the tag and the tag may record the signal. The signal may then be read at the surface. The signal may be confirmation that a previous action was carried out or a measurement by one of the sensors. The data written to the RFID tag may include a date/time stamp, a set position (the command), a measured position (of control module position piston), and a tool address. The written RFID tag may be circulated to the surface via the annulus. 
     Alternatively, the control module  300  may be hard-wired to the telemetry sub  400  and a single controller, such as a microprocessor, disposed in either sub may control both subs. The control module  300  may be hard-wired by replacing the data connector  378  with contact rings disposed at or near the pin  347  and adding corresponding contact rings to/near the box  408   b  of the telemetry sub  400 . Alternatively, inductive couplings may be used instead of the contact rings. Alternatively, a wet or dry pin and socket connection may be used instead of the contact rings. 
       FIG. 4C  is a schematic cross-sectional view of the sensor sub  404 . The tachometer  455  may include two diametrically opposed single axis accelerometers  455   a,b . The accelerometers  455   a,b  may be piezoelectric, magnetostrictive, servo-controlled, reverse pendular, or microelectromechanical (MEMS). The accelerometers  455   a,b  may be radially X oriented to measure the centrifugal acceleration A c  due to rotation of the telemetry sub  400  for determining the angular speed. The second accelerometer may be used to account for gravity G if the telemetry sub is used in a deviated or horizontal wellbore. Detailed formulas for calculation of the angular speed are discussed and illustrated in U.S. Pat. App. Pub. No. 2007/0107937, which is herein incorporated by reference in its entirety. Alternatively, as discussed in the &#39;937 publication, the accelerometers may be tangentially Y oriented, dual axis, and/or asymmetrically arranged (not diametric and/or each accelerometer at a different radial location). Further, as discussed in the &#39;937 publication, the accelerometers may be used to calculate borehole inclination and gravity tool face. Further, the sensor sub may include a longitudinal Z accelerometer. Alternatively, magnetometers may be used instead of accelerometers to determine the angular speed. 
     Instead of using one of the RFID tags  450   a,p  to activate the underreamer  100 , an instruction signal may be sent to the controller  430  by modulating angular speed of the drill string according to a predetermined protocol. An exemplary signal is illustrated in FIG. 10 of the &#39;937 publication. The modulated angular speed may be detected by the tachometer  455 . The controller  430  may then demodulate the signal and relay the signal to the control module controller  325 , thereby operating the underreamer  100 . The protocol may represent data by varying the angular speed on to off, a lower speed to a higher speed and/or a higher speed to a lower speed, or monotonically increasing from a lower speed to a higher speed and/or a higher speed to a lower speed. 
       FIG. 4D  illustrates the mud pulser  475 . The mud pulser  475  may include a valve, such as a poppet  476 , an actuator  477 , a turbine  478 , a generator  479 , and a seat  480 . The poppet  476  may be longitudinally movable by the actuator  477  relative to the seat  480  between an open position (shown) and a choked position (dashed) for selectively restricting flow through the pulser  475 , thereby creating pressure pulses in drilling fluid pumped through the mud pulser. The mud pulses may be detected at the surface, thereby communicating data from the microprocessor to the surface. The turbine  478  may harness fluid energy from the drilling fluid pumped therethrough and rotate the generator  479 , thereby producing electricity to power the mud pulser. The mud pulser may be used to send confirmation of receipt of commands and report successful execution of commands or errors to the surface. The confirmation may be sent during circulation of drilling fluid. Alternatively, a negative or sinusoidal mud pulser may be used instead of the positive mud pulser  475 . The microprocessor may also use the turbine  478  and/or pressure sensor as a flow switch and/or flow meter. 
     Instead of using one of the RFID tags  450   a,p  or angular speed modulation to activate the underreamer  100 , a signal may be sent to the controller by modulating a flow rate of the rig drilling fluid pump according to a predetermined protocol. Alternatively, a mud pulser (not shown) may be installed in the rig pump outlet and operated by the surface controller to send pressure pulses from the surface to the telemetry sub controller according to a predetermined protocol. The telemetry sub controller may use the turbine and/or pressure sensor as a flow switch and/or flow meter to detect the sequencing of the rig pumps/pressure pulses. The flow rate protocol may represent data by varying the flow rate on to off, a lower speed to a higher speed and/or a higher speed to a lower speed, or monotonically increasing from a lower speed to a higher speed and/or a higher speed to a lower speed. Alternatively, an orifice flow switch or meter may be used to receive pressure pulses/flow rate signals communicated through the drilling fluid from the surface instead of the turbine and/or pressure sensor. Alternatively, the sensor sub may detect the pressure pulses/flow rate signals using the pressure sensor and accelerometers to monitor for BHA vibration caused by the pressure pulse/flow rate signal. 
     Alternatively, an electromagnetic (EM) gap sub (not shown) may be used instead of the mud pulser, thereby allowing data to be transmitted to the surface using EM waves. Alternatively, an RFID tag launcher (not shown) may be used instead of the mud pulser. The tag launcher may include one or more RFID tags. The microprocessor  430  may then encode the tags with data and the launcher may release the tags to the surface. Alternatively, an acoustic transmitter may be used instead of the mud pulser. Alternatively, and as discussed above, instead of the mud pulser, RFID tags may be periodically pumped through the telemetry sub and the microprocessor may send the data to the tag. The tag may then return to the surface via an annulus formed between the workstring and the wellbore. The data from the tag may then be retrieved at the surface. Alternatively, and as discussed above, instruction signals may be sent to the electronics package using mud pulses, EM waves, or acoustic signals. 
     For deeper wells, the drill string may further include a signal repeater (not shown) to prevent attenuation of the transmitted mud pulse. The repeater may detect the mud pulse transmitted from the mud pulser  475  and include its own mud pulser for repeating the signal. As many repeaters may be disposed along the workstring as necessary to transmit the data to the surface, e.g., one repeater every five thousand feet. Each repeater may also be a telemetry sub and add its own measured data to the retransmitted data signal. If the mud pulser is being used, the repeater may wait until the data sub is finished transmitting before retransmitting the signal. The repeaters may be used for any of the mud pulser alternatives, discussed above. Repeating the transmission may increase bandwidth for the particular data transmission. 
     Alternatively, multiple telemetry subs may be deployed in a workstring or drill string. An RFID tag including a memory unit may be dropped/pumped through the telemetry subs and record the data from the telemetry subs until the tag reaches a bottom of the data subs. The tag may then transmit the data from the upper subs to the bottom sub and then the bottom sub may transmit all of the data to the surface. 
     Alternatively, the mud pulser may instead be located in a measurement while drilling (MWD) and/or logging while drilling (LWD) tool assembled in the drill string downstream of the underreamer. The MWD/LWD module may be located in the BHA to receive written RFID tags from several upstream tools. The mud pulse module or MWD/LWD module may then pulse a signal to the surface indicating time to shut down pumps to allow passive activation. Alternatively, the mud pulse module or MWD/LWD module may send a mud-pulse to annulus pressure measurement module (PWD subs) along the drill string. The PWD module may then upon command, or periodically, write RFID tags and eject the tags into the annulus for telemetry to surface or into the bore for telemetry to the MWD/LWD module. 
     Alternatively, the control module may send and receive instructions via wired drill/casing string. 
       FIGS. 5A and 5B  illustrate a drilling system  500  and method utilizing the underreamer  100 , according to another embodiment of the present invention. 
     The drilling system  500  may include a drilling derrick  510 . The drilling system  500  may further include drawworks  524  for supporting a top drive  542 . The top drive  542  may in turn support and rotate a drilling assembly  500 . Alternatively, a Kelly and rotary table (not shown) may be used to rotate the drilling assembly instead of the top drive. The drilling assembly  500  may include a drill string  502  and a bottomhole assembly (BHA)  550 . The drill string  502  may include joints of threaded drill pipe connected together or coiled tubing. The BHA  550  may include the telemetry sub  400 , the control module  300 , the underreamer  100 , and a drill bit  505 . A rig pump  518  may pump drilling fluid, such as mud  514   f , out of a pit  520 , passing the mud through a stand pipe and Kelly hose to a top drive  542 . The mud  514   f  may continue into the drill string, through a bore of the drill string, through a bore of the BHA, and exit the drill bit  505 . The mud  514   f  may lubricate the bit and carry cuttings from the bit. The drilling fluid and cuttings, collectively returns  514   r , flow upward along an annulus  517  formed between the drill string and the wall of the wellbore  516   a /casing  519 , through a solids treatment system (not shown) where the cuttings are separated. The treated drilling fluid may then be discharged to the mud pit for recirculation. 
     The drilling system may further include a launcher  520 , surface controller  525 , and a pressure sensor  528 . The pressure sensor  528  may detect mud pulses sent from the telemetry sub  400 . The surface controller  525  may be in data communication with the rig pump  518 , launcher  520 , pressure sensor  528 , and top drive  542 . The rig pump  518  and/or top drive  542  may include a variable speed drive so that the surface controller  525  may modulate  545  a flow rate of the rig pump  518  and/or an angular speed (RPM) of the top drive  542 . The modulation  545  may be a square wave, trapezoidal wave, or sinusoidal wave. Alternatively, the controller  545  may modulate the rig pump and/or top drive by simply switching them on and off. 
     A first section of a wellbore  516   a  has been drilled. A casing string  519  has been installed in the wellbore  516   a  and cemented  511  in place. A casing shoe  519   s  remains in the wellbore. The drilling assembly  500  may then be deployed into the wellbore  516   a  until the drill bit  505  is proximate the casing shoe  519   s . The drill bit  505  may then be rotated by the top drive and mud injected through the drill string by the rig pump. Weight may be exerted on the drill bit, thereby causing the drill bit to drill through the casing shoe. The underreamer  100  may be restrained in the retracted position by the control module  200 / 300 . Once the casing shoe  519   s  has been drilled through and the underreamer  100  is in a pilot section  516   p  of the wellbore, the underreamer  100  may be extended. If the control module  200  is used, then the surface controller  525  may instruct the launcher  520  to deploy the ball  290 . If the control module  300  is used, then the surface controller  525  may instruct the launcher  520  to deploy one of the RFID tags  450   a,p ; modulate angular speed of the top drive  545 ; or flow rate of the rig pump  518 , thereby conveying an instruction signal to extend the underreamer  100 . Alternatively, the ball  290 /RFID tags  450   a,p  may be manually launched. The telemetry sub  400  may receive the instruction signal; relay the instruction signal to the control module  300  allow the arms  50   a,b  to extend; and send a confirmation signal to the surface via mud pulse. The pressure sensor  528  may receive the mud pulse and communicate the mud pulse to the surface controller. The underreamer  100  may then ream the pilot section  516   p  into a reamed section  516   r , thereby facilitating installation of a larger diameter casing/liner upon completion of the reamed section. 
     Alternatively, instead of drilling through the casing shoe, a sidetrack may be drilled or the casing shoe may have been drilled during a previous trip. 
     Once drilling and reaming are complete, it may be desirable to perform a cleaning operation to clear the wellbore  516   r  of cuttings in preparation for cementing a second string of casing. A second instruction signal may be sent to the telemetry sub  400  commanding retraction of the arms. The rig pump may be shut down, thereby allowing the control module  300  to retract the arms and lock the arms in the retracted position. Once the arms are retracted, the rig pump may resume circulation of drilling fluid and the telemetry sub may confirm retraction of the arms via mud pulse. Once the confirmation is received at the surface, the cleaning operation may commence. The cleaning operation may involve rotation of the drill string at a high angular velocity that may otherwise damage the arms if they are extended. The drilling assembly may be removed from the wellbore during the cleaning operation. Additionally, the control module  300  may be commanded to retract and lock the arms for other wellbore operations, such as underreaming only a selected portion of the wellbore. Alternatively, the drill string may remain in the wellbore during the cleaning operation and then the arms may be re-extended by sending another instruction signal and the wellbore may be back-reamed while removing the drill string from the wellbore. The arms may then be retracted again when reaching the casing shoe. Alternatively, the cleaning operation may be omitted. Alternatively or additionally, the cleaning operation may be occasionally or periodically performed during the drilling and reaming operation. 
     Alternatively, the drill bit may be rotated at a high speed by a mud motor (not shown) of the BHA and the underreamer  100  may be rotated at a lower speed by the top drive. Since the bit speed may equal the motor speed plus the top drive speed, the mud motor speed may be equal or substantially equal to the top drive speed. 
     For directional drilling operations, the telemetry sub  400  may be used as an MWD sub for measuring and transmitting orientation data to the surface. Alternatively, the BHA may include a separate MWD sub. The surface may need to send instruction signals to the separate MWD sub in addition to the instruction signals to the telemetry sub. If modulation of the rig pump is the chosen communication media for both MWD and underreamer instruction signals, then the protocol may include an address field or the signals may be multiplexed (e.g., frequency division). Alternatively, modulation of the rig pump may be used to send MWD instructions and top drive modulation may be used to send underreamer instructions. If dynamic steering is employed as discussed in the &#39;100 patent and the underreamer instruction signal is sent by top drive modulation, then the underreamer signal may be multiplexed with the dynamic steering signal. Alternatively, the RFID tag protocol may include an address field distinguishing the instructions. 
     Alternatively, the underreamer may be used in a drilling with casing/liner operation. The drilling assembly may include the casing/liner string instead of the drill string. The BHA may be operated by rotation of the casing/liner string from the surface of the wellbore or a motor as part of the BHA. After the casing/liner is drilled and set into the wellbore, the BHA may be retrieved from the wellbore. To facilitate retrieval of the BHA, the BHA may be fastened to the casing/liner string employing a latch, such as is disclosed in U.S. Pat. No. 7,360,594, which is herein incorporated by reference in its entirety. Alternatively, the BHA may be drillable. Once the BHA is retrieved, the casing/liner string may then be cemented into the wellbore. 
     Alternatively, the underreamer may be used in an expandable casing/liner operation. The casing/liner may be expanded after it is run-into the wellbore. 
     Additionally, a single or multiple underreamers may be used without the pilot bit to ream a casing or liner into a pre-drilled wellbore. 
       FIG. 6A  illustrates a portion of an alternative electro-hydraulic control module  600  for use with the underreamer  100 , according to another embodiment of the present invention. The rest of the control module  600  may be similar to the control module  300 . The control module  600  may be used instead of the control module  300 . 
     The control module  600  may include an inner body and bulkhead  615 . For ease of depiction, the bulkhead and inner body are shown as an integral piece  615 . To facilitate manufacture and assembly, the inner body and bulkhead may be made as separate pieces as shown in  FIG. 3 . The control module  600  may further include upper  602   u  and lower  602   l  hydraulic chambers having hydraulic fluid disposed therein and isolated by seals  603   a,b . The control module  600  may further include an actuator so that the control module  600  may actively move the underreamer piston  10  while the rig pump  518  is injecting drilling fluid through the control module  600  and the underreamer  100 . The actuator may be a hydraulic pump  601  in communication with the upper  602   u  and lower  602   l  hydraulic chambers via a hydraulic passage and operable to pump the hydraulic fluid from the upper chamber  602   u  to the lower chamber  602   l  while being opposed by the underreamer piston  10 . Alternatively, the pump may be a hydraulic amplifier on a lead or ball screw being turned by the electric motor. Additionally, as with the control module  300 , the control module  600  may further include a second passage (not shown) with a pressure sensor for detecting engagement of the underreamer piston with the position sensor. 
     The electric motor  604  may drive the hydraulic pump  601 . The electric motor  604  may be reversible to cause the hydraulic pump  601  to pump fluid from the lower chamber  602   l  to the upper chamber  602   u . The active control module  600  may receive an instruction signal from the surface (as discussed above via the telemetry sub  400 ) and operate the underreamer  100  without having to wait for shut down of the rig pump  518 . Alternatively, the underreamer piston force may be reduced by decreasing flow rate of the drilling fluid or shutting off the rig pump before or during sending of the instruction signal. 
     The control module  600  may further include a solenoid valve, such as a check valve  616  or shutoff valve, operable to prevent flow from the lower chamber to the upper chamber in the closed position. Similar to the control module  300 , the position piston  605  may prevent the underreamer piston  10  from extending the arms  50   a,b  while drilling fluid  514   f  is pumped through the control module  600  and the underreamer  100  due to the closed check valve  616 . The control module  600  may further include a position sensor, such as a Hall sensor  611  and magnet  612 , which may be monitored by the controller  325  to allow extension of the arms to one or more intermediate positions and/or to confirm full extension of the arms. Alternatively, the position sensor may be a linear voltage differential transformer (LVDT). The control module  600  may further include a compensating piston  621  to equalize pressure between drilling fluid (via port  606 ) and the upper chamber  602   u . The control module may further include a biasing member, such as a spring  622 , to bias flow of hydraulic fluid from the upper  602   u  to the lower  602   l  chamber. 
     In operation, when the controller  325  receives a signal instructing extension of the arms  50   a,b , the controller  325  may open the solenoid check valve  616  so oil may flow through the hydraulic passage from the lower chamber to the upper chamber. Depending on whether the rig pump is operating, the controller  325  may then supply electricity to the motor  604 , thereby driving the pump  601 . If the rig pump is operating, the underreamer piston  10  may force hydraulic fluid through the pump  601 , thereby obviating the need to operate the motor and the pump. The hydraulic pump  601  may then transfer oil from the lower reservoir to the upper reservoir to retract the position piston  605 . If the rig pump is shut down, the underreamer piston may not follow the position piston until the rig pump is operated. Once the controller  325  detects that the position piston  605  is in the instructed position via the position sensor  611 ,  612 , the controller may shut off the motor and pump and close the solenoid check valve. 
     In operation, when the controller  325  may receive a signal instructing retraction of the arms  50   a,b , the controller  325  may open the solenoid check valve  616  so oil may flow through the hydraulic passage from the upper chamber to the lower chamber or operation of the pump may open the valve. The controller  325  may then supply electricity to the motor  604 , thereby driving the pump  601 . The hydraulic pump  601  may then transfer oil from the upper reservoir to the lower reservoir to extend the position piston  605 . Once the controller  325  detects that the position piston  605  is in the instructed position via the position sensor  611 ,  612 , the controller may shut off the motor and pump and close the solenoid check valve. If the controller  325  does not detect that the position piston has moved to the instructed position after a predetermined period of time, the controller  325  may shut off the motor and close the valve and send an error message to the surface (via the telemetry sub). Alternatively, the controller  325  may periodically retry to move the position piston or wait for shut-down of the rig pump and then re-try. 
       FIG. 6B  illustrates a portion of an alternative electro-hydraulic control module  630  for use with the underreamer  100 , according to another embodiment of the present invention. The rest of the control module  630  may be similar to the control module  300 . The control module  630  may be used instead of the control module  300 . 
     The control module  630  may include an inner body and bulkhead  645 . For ease of depiction, the bulkhead and inner body are shown as an integral piece  645 . To facilitate manufacture and assembly, the inner body and bulkhead may be made as separate pieces as shown in  FIG. 3 . The control module  630  may further include upper  602   u  and lower  602   l  hydraulic chambers having hydraulic fluid disposed therein and isolated by seals  603   a,b . The control module  630  may further include an actuator, such as a solenoid operated shutoff valve  647 , in communication with the upper  602   u  and lower  602  hydraulic chambers via a first hydraulic passage. A check valve  646  may be disposed in a second hydraulic passage in communication with the hydraulic chambers  602   u,l . The check valve  646  may be oriented to allow fluid flow from the lower chamber  602   l  to the upper chamber  602   u  and prevent fluid flow from the upper chamber to the lower chamber. The shutoff valve  647  may normally be in a closed position until operated by the controller  325 . Additionally, as with the control module  300 , the control module  600  may further include a third passage (not shown) with a pressure sensor for detecting engagement of the underreamer piston with the position sensor. 
     Similar to the control module  300 , the position piston  605  may prevent the underreamer piston  10  from extending the arms  50   a,b  while drilling fluid  514   f  is pumped through the control module  630  and the underreamer  100  due to the closed check valve  616 . The control module  630  may further include a position sensor, such as a Hall sensor  611  and magnet  612 , which may be monitored by the controller  325  to allow extension of the arms to one or more intermediate positions and/or to confirm full extension of the arms. Alternatively, the position sensor may be a linear voltage differential transformer (LVDT). The control module  630  may further include a compensating piston  621  to equalize pressure between drilling fluid (via port  606 ) and the upper chamber  602   u . The control module may further include a biasing member, such as a spring  622 , to bias flow of hydraulic fluid from the upper  602   u  to the lower  602   l  chamber and bias the arms  50   a,b  toward the retracted position. Alternatively, the motor  604  and pump  601  may be installed in the first passage instead of or in addition to the shutoff valve  647 . 
     In operation, when the controller  325  receives a signal instructing extension of the arms  50   a,b , the controller  325  may open the shutoff valve  647  so oil may flow through the first hydraulic passage from the lower chamber to the upper chamber and hold the shutoff valve open while the underreamer is in use to ensure firm engagement of the blades  50   a,b  with the body  5 . The holding and opening currents may be different. The controller  325  may occasionally reapply the opening current to ensure that shock or vibration has not caused closure of the shutoff valve  647 . Alternatively, as discussed below, if the control module  630  is deployed with an adjustable underreamer or adjustable stabilizer, the controller may close the shutoff valve  647  once the controller detects that the piston  605  is in the instructed position. 
     In operation, when the controller  325  receives a signal instructing retraction of the arms  50   a,b , the controller  325  may open the shutoff valve  647  so oil may flow through the hydraulic passage from the upper chamber to the lower chamber (once the rig pump is shut off). The controller may then close the shutoff valve after a predetermined period of time or upon detection of movement of the piston  605  to the retracted position. If the arms  50   a,b  are not fully retracted when the shutoff valve is closed, the check valve  646  may allow the spring  622  to complete retraction of the arms. 
       FIG. 6C  illustrates an alternative electro-mechanical control module  650  for use with the underreamer  100 , according to another embodiment of the present invention. 
     [moo] The control module  650  may include a body  655 , the control mandrel  210 , an actuator housing  665 , a keeper  675 , the lock mandrel  230 , an electronics package  625 , the biasing member  235 , a battery  670 , and a linear actuator  680 . The body  655  may be tubular and have a longitudinal bore formed therethrough. Each longitudinal end  655   a,b  of the body  655  may be threaded for longitudinal and rotational coupling to other members, such as the underreamer  100  at  655   b  and the telemetry sub  400  at  655   a . The electronics package  625  may include a controller, such as a microprocessor, a power regulator, and a modem. A data connector, such as an inductive coupling  678 , may be disposed at or near upper end  655   a  for interfacing with an inductive coupling disposed at or near a lower end of the telemetry sub  400 , thereby providing data communication between the controller  430  and the controller  625 . Alternatively, the data connector may be hard-wire or short-hop antenna. The controller  625  may be in electrical communication with the inductive coupling  678 , position sensor  660 , and power coupling  677  via leads. The power coupling  677  may be in electrical communication with the linear actuator  680  via leads. The linear actuator  680  may be a linear motor or a rotary motor and a lead screw or a ball screw. The linear actuator  680  may also include a position sensor for monitoring the position of the keeper  675  and may communicate with the controller  625  via the power coupling  677  or a separate data coupling (not shown). 
     In operation, the control module  650  may operate similar to the control module  200  except that instead of dropping the ball  290  to operate the piston  220 , the controller  625  may operate the linear actuator  680  to move the keeper  675 , thereby releasing the dogs  227 . The controller  625  may receive the instruction signal from the telemetry sub  400  via the inductive coupling  678 . The controller  625  may also monitor a position of the control mandrel shoulder  210   s  using position sensor  660  in order to report successful deployment of the arms  50   a,b . After completion of the drilling/reaming operation, the controller  625  may receive a signal instructing retraction of the arms  50   a,b  from the telemetry sub  400 . The controller  625  may wait for detection of movement of the control mandrel to the retracted position by the spring  235 . The controller  625  may then reverse the linear actuator  680 , thereby re-locking the dogs  227  against the control mandrel. The controller  625  may then report successful retraction and re-locking of the arms to the surface or an error message if either retraction or re-locking is not successful 
     Alternatively, the dogs  227  may be replaced by a collet fingers (not shown) formed on an end of the lock mandrel  230  and a corresponding profile may be formed in the end of the control mandrel  210 . The keeper  675  may then engage the collet fingers and prevent the fingers from expanding until moved by the linear actuator  680 . Alternatively, locking pins may be used instead of the dogs and an electromagnet may be used instead of the linear actuator. 
     Alternatively, instead of replacing the piston  220  with the linear actuator, the actuator may instead be arranged to move the piston  220  without obstructing the ball seat  220   s  so that the piston may be moved using either the actuator or the ball  290 , thereby providing redundancy. 
     Alternatively, instead of modifying the mechanical control module  200 , an electromechanical adapter (not shown) may be connected to the mechanical control module  200  by a threaded connection. The adapter may include the electronics package and an actuator for engaging the ball seat and breaking the shear screws  222 . The actuator may include a plunger which may engage or abut the ball seat. Alternatively the adapter may break or remove the shear screw. 
     Alternatively, the actuator  680 , electronics package  680 , and battery  670  may be omitted and the keeper  675  may be modified to have a latch profile (not shown) formed in an inner surface thereof and a detent disposed in an outer surface thereof. The actuator housing  665  may be modified to have detent profiles formed on an inner surface thereof corresponding to positions where the keeper is engaged with the dogs  227  and disengaged from the dogs  227 , respectively. An actuator having a latch may then be deployed from the surface using wireline to engage the latch profile. The keeper  675  may then be moved from one of the engaged and disengaged positions to the other position using the actuator. The latch may then be released by sending a signal to the actuator via the wireline. The wireline and actuator may be retrieved to the surface and re-deployed when it is desired to move the keeper  675 . Alternatively, the actuator may be deployed using slickline by including a battery and a controller. Additionally if the arms  50   a,b  are jammed in the extended position, the actuator may engage the control mandrel  210  and weight of the actuator may be set on the control mandrel to push the blades toward the retracted position. 
       FIG. 7A  illustrates an alternate BHA  700  including dual underreamers  100   u,l , according to another embodiment of the present invention.  FIGS. 7B and 7C  illustrates an operating sequence for the dual underreamers  100   u,l . The BHA  700  may be used instead of the BHA  550 . The BHA  700  may include an upper control module  300   u , an upper underreamer  100   u , one or more stabilizers  705 , a lower control module  300   l , a lower underreamer  300   l , and the telemetry sub  400 , and a drill bit (not shown, see  505 ). Alternatively, the control module  600  or control module  650  may replace the control modules  300   u,l.    
     In operation, the BHA  700  is deployed into the wellbore and, if necessary, the casing shoe is drilled with both underreamers  100   u,l  locked in the retracted position. Once the shoe is drilled through and the BHA is in the pilot section clear of the casing, an instruction signal may be sent to the telemetry sub  400  commanding extension of the upper underreamer  100   u . The telemetry sub  400  may then relay the signal to the upper control module  300   u . The upper control module  300   u  may then release the upper underreamer as discussed above. The wellbore may then be drilled and reamed until the upper underreamer becomes dull. An instruction signal may then be sent to the telemetry sub  400  commanding retraction of the upper underreamer  100   u  and extension of the lower underreamer without tripping the drill string from the wellbore. The wellbore may then be drilled and reamed until the section is finished. As discussed above, the wellbore may then be cleaned and/or back reamed and the drilling assembly removed from the wellbore. 
     Additionally, a third underreamer and control module may be added if necessary. The third underreamer may be placed adjacent the bit. The third underreamer may be activated at total depth (TD) to eliminate the rat hole. Additionally, the BHA may include four or more underreamers and control modules. 
     Alternatively, the operating sequence may be reversed. Alternatively, both underreamers may be opened together. When the lower underreamer becomes dull, the lower underreamer may be closed and drilling may continue with only the upper underreamer. Alternatively the lower underreamer arms may have a smaller outer diameter in the extended position and the upper underreamer may have a greater diameter in the extended position and both underreamers may be opened together, thereby creating a two-stage reamer. The two-stage reaming may lessen the wear on both underreamers. 
     Alternatively, the mechanical control module  200  may be used instead of the upper electro-hydraulic control module  300   u . Both underreamers may be locked in the retracted position upon deployment through the casing and drill-through of the casing shoe. The ball  290  may then be launched and the upper underreamer extended. Once the upper underreamer arms become dull, an instruction signal may be sent to the telemetry sub and relayed to the lower control module, thereby extending the lower underreamer arms. Drilling and reaming may then re-commence. The drill string may be raised before extension of the lower underreamer so that the lower underreamer is in the section reamed by the upper underreamer, thereby maintaining hole size. The upper underreamer nozzles may include a screen, such as a sand screen, for preventing the RFID tag from being discharged therethrough. The upper underreamer may be left in the extended position and used as a stabilizer. Alternatively, the operating sequence may be reversed. Extending the lower underreamer arms first may negate the need for a screen since the upper nozzles would be closed by the mandrel  20 . Further, reversing the order negates the need for lifting the drill string before re-commencing drilling. Further, reversing the order and activating the lower underreamer first reduces or eliminates the risk that the lower electro-hydraulic control module will become damaged during drilling prior to the desired actuation of the lower underreamer. 
     Alternatively, the mechanical control module  200  may be used instead of the lower electro-hydraulic control module  300   l  and the electro-mechanical control module  650  may be used instead of the upper electro-hydraulic control module  300   u . Both underreamers may be locked in the retracted position upon deployment through the casing and drill-through of the casing shoe. An instruction signal may be sent to the telemetry sub and relayed to the upper control module, thereby extending the upper underreamer arms. Drilling and reaming may then commence. Once the upper underreamer becomes dull, the ball may then be launched and the lower underreamer arms extended. The upper underreamer may be left in the extended position and used as a stabilizer or it may be retracted. 
     Alternatively, each of the control modules  300   u,l  may be replaced by the mechanical control module  200  and the telemetry sub  400  may be omitted. The wellbore may then be drilled with the upper underreamer first. The upper control module may be modified with a hinged expandable or frangible ball seat set at a pressure greater than the shear screws  222 . When the upper underreamer becomes dull, then the pressure may be increased to fracture the hinged ball seat, thereby dropping the ball to the lower control module ball seat. The lower control module may then be activated. The upper control module may remain extended and serve as a stabilizer. Alternatively, the upper control module may have a larger ball seat than the lower control module. The lower control module may be activated first with a smaller ball which may pass through the larger upper seat. A larger ball may then be dropped to activate the upper control module. 
     Alternatively, the cutters  55  may be omitted from the upper underreamer  100   u  and the upper underreamer  100   u  may be extended simultaneously with or shortly after the lower underreamer  100   l  and used as a stabilizer. Alternatively, a third underreamer without cutters and a third control module may be added to the BHA  700  above the upper control module  300   u  and used as a stabilizer. Alternatively, the section mill  1100  without cutters may replace the upper underreamer and control module and be extended and used as an adjustable stabilizer or added to the BHA  700  above the upper control module  300   u . In the adjustable stabilizer alternatives, the instruction signal may include an extension setting for the adjustable stabilizer. The adjustable stabilizer arms may be extended to a diameter substantially equal to the extended lower underreamer arms. 
     Alternatively, the adjustable stabilizer may be used to steer the drill bit in a directional drilling operation. In a directional drilling operation, the lower underreamer  100   l  may act as a fulcrum or pivot point for the bit due to the weight of the drill collars behind the lower underreamer  100   l  forcing the lower underreamer  100   l  to push against the lower side of the borehole. Accordingly, the drill bit tends to be lifted upwardly at an angle, e.g. build angle. Selective extension of the adjustable stabilizer may control this effect. Namely, as the drill bit builds angle due to the fulcrum effect created by the lower underreamer  100   l , the adjustable 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 adjustable stabilizer arms may control the pivoting of the bit on the lower underreamer  100   l , thereby providing a two-dimensional, gravity based steerable system to control the build or drop angle of the drilled borehole as desired. 
       FIG. 8  illustrates an alternative dual underreamer BHA  800 , according to another embodiment of the present invention. The BHA  800  may include an upper control module  300   u , an upper underreamer  100   u , one or more stabilizers  705 , a lower control module  300   l , a lower underreamer  300   l , and the telemetry sub  400 , and a drill bit (not shown, see  505 ). Alternatively, the control module  600  or control module  650  may replace the control modules  300   u,l . The upper underreamer  100   u  and control module  300   u  may be flipped upside down so that the control modules and the telemetry sub may be placed adjacent one another. This arrangement may facilitate hard-wiring or inductive couplings to be used to transfer data between the control modules and the telemetry sub. 
     Alternatively, this arrangement may facilitate integration of the control module and telemetry sub electronics and even structural integration so that one sub having one battery and one controller may perform the function of the control modules and the telemetry sub. 
       FIG. 9  illustrates an underreamer arm  950   a  configured for soft formations, according to another embodiment of the present invention. Instead of super-hard cutters, the arm  955  may have teeth formed on one or more blades thereof, such as by casting, milling, or machining. Alternatively, cutters made from a hard or superhard material may be disposed along each of the blades, as discussed above. The cutters may be substantially larger than the cutters  55  and spaced substantially further apart than the cutters  55 . Alternatively, the teeth may be hard-faced. The arms  50   a,b  of either of the underreamers  100   u,l  may be replaced by the arm  950   a  so that one of the underreamers is configured to ream a hard formation, such as limestone, and the other is configured to ream a soft formation, such as shale. The soft-arm underreamer may then be extended for reaming the soft formation while the hard-arm underreamer is retracted and the hard-arm underreamer may be extended for reaming a hard formation while the soft-arm underreamer is retracted. Alternatively, one of the upper underreamer and lower underreamer may have arms configured to forward ream and the other of the upper and lower underreamer may have arms configured to back ream and the forward arm underreamer may be extended while forward reaming while the back ream underreamer is retracted and vice versa. Alternatively, the BHA may include an underreamer and a casing cutter or section mill (discussed below). 
     Alternatively, the arms of a first of the underreamers  100   u,l  may be configured to ream a first geological formation and the arms of a second of the underreamers  100   u,l  may be configured to ream a second geological formation. In operation, the arms of the first underreamer may be extended and the first formation drilled and reamed until the second formation is encountered. The arms of the second underreamer may then be extended and the arms of the first underreamer may be optionally retracted. The second formation may then be drilled and reamed. Optionally, the arms of the first underreamer may then be extended if a new geological formation is encountered. 
       FIG. 10A  is a cross section of a casing cutter  1000  in a retracted position, according to another embodiment of the present invention.  FIG. 10B  is a cross section of the casing cutter  1000  in an extended position.  FIG. 10C  is an enlargement of a portion of  FIG. 10A . The casing cutter  1000  may include a housing  1005 , a plurality of arms  1015 , a piston  1010 , a seal  1012 , a piston spring  1020 , a follower  1022 , a follower spring  1027 , and a control module  1030 . The control module  1030  may include an electronics package  1025 , a solenoid valve  1031 , a stop spring  1032 , a flow passage  1033 , a position sensor  1034 , chambers  1035   a,b , and a sleeve  1036 , a battery  1170 , and an antenna  1178 . The electronics package  1025  may include a controller, such as microprocessor, power regulator, and transceiver. 
     The housing  1005  may be tubular and may have a threaded coupling formed at a longitudinal end thereof for connection to a workstring (not shown) deployed in a wellbore for an abandonment operation. The workstring may be drill pipe or coiled tubing. To facilitate manufacture and assembly, the housing  1005  may include a plurality of longitudinal sections, each section longitudinally and rotationally coupled, such as by threaded connections, and sealed (above the piston  1010 ), such as by o-rings. Each arm  1015  may be pivoted  1018  to the housing for rotation relative to the housing between a retracted position and an extended position. A coating  1017  of hard material, such as tungsten carbide ceramic or cermet, may be bonded to an outer surface and a bottom of each arm  1016 . The hard material  1017  may be coated as grit. An upper surface of each arm  1015  may form a cam  1019   a  and an inner surface of each arm may form a taper  1019   b . The housing  1005  may have an opening  1005   o  formed therethrough for each arm  1015 . Each arm  1015  may extend through a respective opening  1005   o  in the extended position. 
     The piston  1010  may be tubular, disposed in a bore of the housing  1005 , and include a main shoulder  1010   a . The piston spring  1020  may be disposed between the main shoulder  1010   a  and a shoulder formed in an inner surface of the housing, thereby longitudinally biasing the piston  1010  away from the arms  1015 . A nozzle  1011  may be longitudinally coupled to the piston  1010 , such as by a threaded connection, and made from an erosion resistant material, such as a metal, alloy, or cermet. To extend the arms  1015 , drilling fluid may be pumped through the workstring to the housing bore. The drilling fluid may then continue through the nozzle  1011 . Flow restriction through the nozzle  1011  may cause pressure loss so that a greater pressure is exerted on a top of the piston  1010  than on the main shoulder  1010   a , thereby longitudinally moving the piston downward toward the arms and against the piston spring  1020 . As the piston  1010  moves downward, a bottom of the piston  1010  may engage the cam surface  1019   a  of each arm  1015 , thereby rotating the arms  1015  about the pivot  1018  to the extended position. 
     The housing  1005  may have a stem  1005   s  extending between the arms  1015 . The follower  1022  may extend into a bore of the stem  1005   s . The follower spring  1027  may be disposed between a bottom of the follower and a shoulder of the stem  1005   s . The follower  1022  may include a profiled top mating with each arm taper  1019   b  so that longitudinal movement of the follower toward the arms  1015  radially moves the arms toward the retracted position and vice versa. The follower spring  1027  may longitudinally bias the follower  1022  toward the arms  1015 , thereby also biasing the arms toward the retracted position. When flow through the housing  1005  is halted, the piston spring  1020  may move the piston  1010  upward away from the arms  1015  and the follower spring  1027  may push the follower  1022  along the taper  1019   b , thereby retracting the arms. 
     The chambers  1035   a,b  may be filled with a hydraulic fluid, such as oil. The first chamber  1035   a  may be formed radially between an inner surface of the housing  1005  and an outer surface of the sleeve  1036  and longitudinally between a bottom of a first shoulder  1036   a  of the sleeve and a top of one of the housing sections. The second chamber  1035   b  may be formed radially between an inner surface of the housing  1005  and an outer surface of the sleeve  1036  and longitudinally between a top of the first shoulder  1036   a  and a shoulder of the housing. The position sensor  1034  may measure a position of the first shoulder  1036   a  and communicate the position to the controller  1025 . The solenoid operated valve  1031  may be a check valve operable between a closed position where the valve functions as a check valve oriented to prevent flow from the first chamber to the second chamber (downward flow) and allow reverse flow therethrough, thereby fluidly stopping downward movement of the sleeve  1036 . The sleeve  1036  may further include a second shoulder  1036   b  and the piston may include a stop shoulder  1010   b . Engagement of the stop shoulder  1010   b  with the second shoulder  1036   b  may also stop downward movement of the piston, thereby limiting extension of the arms  1015 . 
     In operation, when it is desired to activate the cutter  1000 , an instruction signal may be sent to the telemetry sub  400  and relayed to the controller  1025  via the antenna  1078 , thereby conveying an arm setting command. Drilling fluid may then be circulated through the workstring from the surface to extend the arms  1015 . The microprocessor  1025  may monitor the position of the sleeve  1036  until the sleeve reaches a position corresponding to the set position of the arms  1015 . The microprocessor  1025  may then supply electricity from the battery  1070  to the solenoid valve  1031 , thereby closing the solenoid valve and halting downward movement of the sleeve  1036  and extension of the arms  1015 . The workstring may then be rotated, cutting through a wall of a casing string to be removed from the wellbore. Once the casing string has been cut, the casing cutter  1000  may be redeployed in the same trip to cut a second casing string having a different diameter by sending a second instruction signal. 
     Additionally, the control module may lock the arms in the retracted position to prevent premature actuation of the arms. Alternatively, the first arm setting may be preprogrammed at the surface. 
       FIG. 10D  is a cross section of a portion of an alternative casing cutter  1000   a  including an alternative control module  1030   a  in a retracted position. Instead of the solenoid valve, the alternative control module may include a pump  1031   a  in communication with each of the chambers  1035   a, b  via passages  1033   a, b . The sleeve may be moved to the set position by supplying electricity to the pump and then shutting the pump off when the sleeve is in the set position as detected by the position sensor  1034 . 
       FIG. 10E  is a cross section of a portion of an alternative casing cutter  1000   b  including an alternative control module  1030   b . The control module  1030   b  may further include a body  1041 , a nozzle  1042 , a flange  1043 , and a sleeve  1046 . The body  1041  may include a nose formed at a bottom thereof for seating against the nozzle  1011 . The nozzle  1042  may be longitudinally coupled to the body  1041  via a threaded cap  1044 . The flange  1043  may be biased toward a shoulder formed in an outer surface of the body  1041  a spring  1048 . The spring  1048  may be disposed between the body  1041  and one or more threaded nuts  1047  engaging a threaded outer surface of the body. The flange  1043  may be longitudinally coupled to the sleeve  1046  by abutment with a shoulder  1046   b  of the sleeve and abutment with a fastener, such as a snap ring. The flange  1043  may have one or ports formed therethrough. The body  1041  may be longitudinally movable downward toward the nozzle  1011  relative to the flange  1043  by a predetermined amount adjustable at the surface by the nuts  1047 . 
     During normal operation in the extended position, the body nose may be maintained against the nozzle  1011 . Drilling fluid may be pumped through both nozzles  1042 ,  1011 , thereby extending the arms. As the piston  1010  moves downward toward the arms  1015 , fluid pressure exerted on the body  1041  by restriction through the nozzle  1042  may push the body  1041  longitudinally toward the piston  1010 , thereby maintaining engagement of the body nose and the nozzle  1011 . If the arms  1015  extend past a desired cutting diameter, the nuts  1047  may abut the stop  1049 , thereby preventing the body nose from following the nozzle  1011 . Separation of the blade nose from the nozzle  1011  may allow fluid flow to bypass the nozzle  1042  via the flange ports, thereby creating a pressure differential detectable at the surface. To initialize or change the setting of the sleeve  1046 , an instruction signal may be sent to the telemetry sub  400  and relayed to the controller  1025 . The controller  1025  may move the sleeve  1046  to the setting using the pump  1031   a , thereby also moving the body  1041 . 
       FIG. 10F  is a cross section of an alternative casing cutter  1000   c  in an extended position. The casing cutter  1000   c  may include a housing  1055 , a plurality of arms  1075 , a follower  1022 , a follower spring  1027 , and a control module  1030   c . The housing  1055  may be tubular and may have a threaded coupling formed at a longitudinal end thereof for connection to a workstring (not shown) deployed in a wellbore for an abandonment operation. The workstring may be drill pipe or coiled tubing. To facilitate manufacture and assembly, the housing  1055  may include a plurality of longitudinal sections, each section longitudinally and rotationally coupled, such as by threaded connections, and sealed (above the arms  1075 ), such as by O-rings. Although shown schematically, the arms  1075  may be similar to the arms  1015  and may be returned to the retracted position by the follower  1022  and the follower spring  1027 . 
     The control module  1030   c  may include the electronics package  1025 , a cam  1060 , a shaft  1065 , a battery  1070 , an electric motor  1071 , a position sensor  1072 , and an antenna  1078 . The shaft  1065  may be longitudinally and rotationally coupled to the motor  1071 . The shaft  1065  may include a threaded outer surface. The cam  1060  may be disposed along the shaft  1065  and include a threaded inner surface (not shown). The cam  1060  may be moved longitudinally along the shaft by rotation of the shaft  1065  by the motor  1071 . As discussed above, the controller  1025  may measure the longitudinal position of the cam  1065  and the position of the arms  1075  using the position sensor  1072 . The motor  1070  may further include a lock to hold the arms in the set position. Although shown schematically, as the cam  1060  moves downward, a bottom of the cam may engage a cam surface of each arm  1075 , thereby rotating the arms about the pivot to the extended position. The control module  1030   c  may further include a load cell (not shown) operable to measure a cutting force exerted on the arms  1075  and the controller  1025  may be programmed to control the blade position to maintain a constant predetermined cutting force. The control module  1030   c  may communicate with the telemetry sub  400  to send a signal to the surface when the cut is finished or if the cutting forces exceed a predetermined maximum. 
     In operation, when it is desired to activate the cutter  1000   c , an instruction signal may be sent to the telemetry sub  400  and relayed to the controller  1025  via the antenna  1078 , thereby conveying an arm setting command. The controller  1025  may supply electricity to the motor  1071  and monitor the position of the arms  1075  until the set position is reached. The microprocessor  1025  may shut off the motor (which may also set the lock). Drilling fluid may then be circulated through the workstring from the surface and the workstring may then be rotated, thereby cutting through a wall of a casing string to be removed from the wellbore. Once the casing string has been cut, a second instruction signal may be sent commanding retraction of the arms. Alternatively, the arms may automatically retract when the cut is finished. The controller  1025  may supply reversed polarity electricity to the motor  1070 , thereby unsetting the lock and moving the cam away from the arms so that the follower  1022  may retract the arms. The casing cutter  1000   c  may be redeployed in the same trip to cut a second casing string having a different diameter by sending another instruction signal including a second arm setting. 
       FIG. 11A  is a cross section of a section mill  1100  in a retracted position, according to another embodiment of the present invention.  FIG. 11B  is an enlargement of a portion of  FIG. 11A . The section mill  1100  may include a housing  1105 , a piston  1110 , a plurality of arms  1115 , a piston spring  1120 , and a control module  1130 . The control module  1130  may include an electronics package  1125 , an electric pump  1131 , flow passages  1133   a, b , chambers  1135   a, b , a second piston shoulder  1110   b , a position sensor  1134 , a battery  1170 , and an antenna  1178 . The electronics package  1125  may include a controller, such as microprocessor, power regulator, and transceiver. 
     The housing  1105  may be tubular and may have a threaded couplings formed at longitudinal ends thereof for connection to a workstring (not shown) deployed in a wellbore for a milling operation. The workstring may be drill pipe or coiled tubing. To facilitate manufacture and assembly, each of the housing  1105  and the piston  1110  may include a plurality of longitudinal sections, each section longitudinally and rotationally coupled, such as by threaded connections. Each arm  1115  may be pivoted  1115   p  to the housing  1105  for rotation relative to the housing between a retracted position and an extended position. Each arm  1115  may include a coating (not shown) of hard material, such as tungsten carbide ceramic or cermet, bonded to an outer surface and a bottom thereof. The hard material may be coated as grit. An inner surface of each arm may be cammed  1115   c . The housing may have an opening  1105   o  formed therethrough for each arm  1115 . Each arm  1115  may extend through a respective opening  1105   o  in the extended position. 
     The piston  1110  may be tubular, disposed in a bore of the housing  1105 , and include one or more shoulders  1110   a,b . The piston spring  1120  may be disposed between the first shoulder  1110   a  and a shoulder formed by a top of one of the housing sections, thereby longitudinally biasing the piston  1110  away from the arms  1115 . The piston  1110  may have a nozzle  1110   n . To extend the arms, drilling fluid may be pumped through the workstring to the housing bore. The drilling fluid may then continue through the nozzle  1110   n . Flow restriction through the nozzle may cause pressure loss so that a greater pressure is exerted on the nozzle  1110   n  than on a cammed surface  1110   c  of the piston  1110   c , thereby longitudinally moving the piston downward toward the arms and against the piston spring. As the piston  1110  moves downward, the cammed surface  1110   c  engages the cam surface  1115   c  of each arm  1115 , thereby rotating the arms about the pivot  1115   p  to the extended position. 
     The chambers  1135   a, b  may be filled with a hydraulic fluid, such as oil. The first chamber  1135   a  may be formed radially between an inner surface of the housing  1105  and an outer surface of the piston  1110  and longitudinally between a bottom of the shoulder  1110   b  and a top of one of the housing sections. The second chamber  1135   b  may be formed radially between an inner surface of the housing and an outer surface of the sleeve and longitudinally between a top of the shoulder  1110   b  and a shoulder of the housing. The pump  1131  may be in fluid communication with each of the chambers  1135   a, b  via a respective passage  1133   a, b.    
     In operation, when it is desired to activate the mill  1100 , an instruction signal may be sent to the telemetry sub  400  and relayed to the controller  1125  via the antenna  1178 , thereby conveying an extension command. The controller  1125  may supply electricity to the pump  1131 , thereby pumping fluid from the chamber  1135   b  to the chamber  1135   a  and allowing the piston  1110  to move longitudinally downward and extending the arms  1115 . As with the casing cutter, the signal may include a position setting command so that the controller may actuate the piston to the instructed set position which may be fully extended, partially extended, or substantially extended depending on the diameter of the casing/liner section to be milled. As discussed above, the controller may monitor the position of the piston shoulder  1110   b  using the position sensor  1134 . Drilling fluid may then be circulated and the workstring may then be rotated and raised/lowered until a desired section of casing or liner has been removed. Once the casing/liner has been milled, the mill may be retracted by sending another instruction signal, thereby conveying retraction command. The controller may then reverse operation of the pump. Alternatively, the control module may include a motor instead of a pump in which case the piston may be a mandrel. 
       FIGS. 12A-12C  are cross-sections of a mechanical control module  1200  in a first retracted, extended, and second retracted position, respectively, according to another embodiment of the present invention. The control module  1200  may include a body  1205 , a control mandrel  1210 , a piston housing  1215 , an extension piston  1220 , a lock mandrel  1230 , one or more biasing members  1235   a,b , and a retraction piston  1250 . The body  1205  may be tubular and have a longitudinal bore formed therethrough. Each longitudinal end  1205   a,b  of the body  205  may be threaded for longitudinal and rotational coupling to other members, such as the underreamer  100  at  1205   b  and a drill string at  1205   a.    
     The biasing members may each be springs  1235   a,b . A return spring  1235   a  may be disposed between a shoulder  1210   s  of the control mandrel  1210  and a shoulder of the lock mandrel  1230 . The return spring  1235   a  may bias a longitudinal end of the control mandrel or a control module adapter  1212  into abutment with the underreamer piston end  10   t , thereby also biasing the underreamer piston  210  toward the retracted position. The control module adapter  1212  may be longitudinally coupled to the control mandrel  1210 , such as by a threaded connection, and may allow the control module  1200  to be used with differently configured underreamers by changing the adapter  1212 . The control mandrel  1210  may be longitudinally coupled to the lock mandrel  1230  by a latch or lock, such as a plurality of dogs  1227 . Alternatively, the latch or lock may be a collet. The dogs  1227  may be held in place by engagement with a lip  1220   l  of the extension piston  1220  and engagement with a lip of the control mandrel  1210 . The lock mandrel  1230  may be longitudinally coupled to the piston housing  1215  by a threaded connection and may abut a body shoulder and the piston housing  1215 . 
     The piston housing  1215  may be longitudinally coupled to the body  1205  by a threaded connection. The extension piston  1220  may include recesses for receiving a slotted end  1250   e  of the retraction piston  1250 . The extension piston  1220  may be longitudinally movable relative to the body  1205 , the movement limited by engagement of a shoulder  1220   b  with an upper end of the lock mandrel  1230 . The extension piston  1220  may be longitudinally coupled to the piston housing  1215  by one or more frangible fasteners, such as shear pin  1222   a . The extension piston  1220  may have a seat  220   s  formed therein for receiving a dissolvable closure element, such as a ball  1290   a , plug, or dart. 
     A piston spring  1235   b  may be disposed between a shoulder formed in the piston housing  1215  and a shoulder  1250   b  formed in the retraction piston  1250 . The retraction piston  1250  may be longitudinally coupled to the piston housing by one or more frangible fasteners, such as shear pin  1222   b . The retraction piston  1250  may be longitudinally movable relative to the body  1205 , the movement limited by engagement of the slotted end  1250   e  with the lip  1220   l . The extension piston  1250  may have a seat  1250   s  formed therein for receiving a closure element, such as a ball  1290   b , plug, or dart. The seat  1250   s  may have a larger diameter than the seat  1220   s , thereby allowing passage of the dissolvable ball  1290   a  therethrough. The ball  1290   b  may be dissolvable or non-dissolvable. 
     When deploying the underreamer  100  and control module  1200  in the wellbore, a drilling operation (e.g., drilling through a casing shoe) may be performed without operation of the underreamer  100 . Even though force is exerted on the underreamer piston  10  by drilling fluid, the shear screws  1222   a  may prevent the underreamer piston  10  from extending the arms  50   a,b . When it is desired to operate the underreamer  100 , the ball  1290   a  is pumped or dropped from the surface and lands in the ball seat  1220   s . Drilling fluid continues to be injected or is injected through the drill string. Due to the obstructed piston bore, fluid pressure acting on the ball  1290   a  and piston  1220  increases until the shear pin  1222   a  is fractured, thereby allowing the extension piston  1220  to move longitudinally relative to the body  1205  and disengaging the lip  1220   l  from the dogs  1227 . The control mandrel lip may be inclined and force exerted on the control mandrel  1210  by the underreamer piston  10  may push the dogs  1227  radially outward into a radial gap defined between the lock mandrel  230  and the extension piston  1220 , thereby freeing the control mandrel and allowing the underreamer piston  10  to extend the arms  50   a,b . Movement of the extension piston  1220  may also open bypass ports  1220   p  formed through a wall of the extension piston  1220 . The ball  1290   a  may then gradually dissolve as drilling continues. 
     When or if it is desired to re-lock the arms  50   a,b  in the retracted position, the second ball  1290   b  is pumped or dropped from the surface and lands in the ball seat  1250   s . Drilling fluid continues to be injected or is injected through the drill string. Due to the obstructed piston bore, fluid pressure acting on the ball  1290   b  and piston  1250  increases until the shear pin  1222   b  is fractured, If the ball  1290   b  was dropped, the retraction piston  1250  may move longitudinally relative to the body  1205  and engage the end  1250   e  with the dogs  1227 , push the dogs  1227  into engagement with the control mandrel lip, and continue until engaging the extension piston lip  1220   l . If the ball  1290   b  was pumped, the retraction piston  1250  may move longitudinally relative to the body  1205  and engage the end  1250   e  with the dogs  1227  and stop due to interference with an outer surface of the control mandrel  1210 . Injection of drilling fluid may then be halted allowing the return spring  1235   a  to push the control mandrel  1210  and underreamer piston  10  to the retracted position. The piston spring  1235   b  may then push the retraction piston  1250  to engage the dogs  1227  with the control mandrel lip. Movement of the retraction piston  1250  by the piston spring  1235   b  may continue until the end  1250   e  engages the extension piston lip  1220   l . Movement of the retraction piston  1250  may also open bypass ports  1250   p  formed through a wall thereof. 
     Alternatively, instead of a dissolvable ball  1290   a , the extension piston  1220  may be modified so that the ball seat  1220   s  is radially movable between a contracted position and an extended position. The modified ball seat  1220   s  may receive the (non-dissolvable) ball in the contracted position and move to the extended position as the extension piston  1220  moves longitudinally. To allow radial movement, the ball seat may be split into fingers biased toward the extended position. In the extended position, the ball seat may allow passage of the ball therethrough. The ball may then be caught by a receptacle (not shown) located in the underreamer adapter. Alternatively, instead of a dissolvable ball  1290   a , the ball  1290   a  may be deformable. The ball  1290   a  may be received by the seat  1220   s  until a predetermined deformation pressure is applied. The pressure necessary to shear the pins  1222   b  may be less or substantially less than the deformation pressure. Once the deformation pressure exerted on the deformable ball is exceeded, the ball may elastically or plastically deform and pass through the seat  1220   s  and be received by the receptacle, discussed above. 
       FIGS. 13A and 13B  are cross-sections of an underreamer  1300  in an extended and second retracted position, respectively, according to another embodiment of the present invention. The underreamer  1300  may include a body  5 , an adapter  1307 , an extension piston  10 , a retraction piston  1310 , one or more seal sleeves  15   u ,  1315 , a mandrel  1320 , a retraction piston and one or more arms  50   a,b  (see  FIG. 1C  for  50   b ). Relative to the underreamer  100 , reference numerals for unchanged parts have been kept and the discussion thereof is not repeated. 
     An end  1307   a  of the adapter  1307  distal from the body may be threaded for longitudinal and rotational coupling to another member of a bottomhole assembly (BHA). The mandrel  1320  may be tubular, have a longitudinal bore formed therethrough, and be longitudinally coupled to the lower seal sleeve  1315  by a threaded connection. The lower seal sleeve  1315  may be longitudinally coupled to the body  5  by being disposed between the shoulder  5   s  and a top of the adapter  1307 . The lower seal sleeve  1315  may have one or more longitudinal ports  1315   p  formed through a cap thereof. The ports  1315   p  may provide fluid communication between the piston surface  10   h  and a control chamber  1311  formed between the adapter  1307  and the retraction piston  1310 . The retraction piston  1310  may include one or more upper ports  1310   u  and one or more lower ports  1310   l  formed through a wall thereof. The upper ports  1310   u  may provide fluid communication between a bore of the retraction piston and the control chamber  1311 . 
     The retraction piston  1310  may be received by a seat  1307   s  formed in the adapter  1307 . A bypass  1307   b  may be formed through the seat  1307   s  and a check valve  1317  may be disposed in the bypass and oriented to allow fluid flow from a bore of the adapter to the control chamber but to prevent flow of fluid from the control chamber to the adapter bore. The retraction piston may be longitudinally coupled to the mandrel  1320  by one or more frangible fasteners, such as shear pins  1322 . The lower ports  1310   l  may be closed. The retraction piston  1310  may have a seat  1310   s  formed therein receiving a closure element, such as a ball  1390 , plug, or dart. The ball  1390  may be dissolvable or non-dissolvable. The retraction piston  1310  may have a shoulder  1310   s  engageable with a shoulder  1307   a  formed in the adapter  1307 . 
     The underreamer  1300  may be deployed with the control module  200  in a similar fashion as the underreamer  100  with the exception that the underreamer  1300  may be re-locked in the retracted position. The ball  290  may be removed as discussed above for removing the ball  1290   a  (e.g., by deforming, dissolving, or modifying the ball seat to be extendable). When or if it is desired to re-lock the arms  50   a,b  in the retracted position, the ball  1390  is pumped or dropped from the surface and lands in the ball seat  1310   s . Drilling fluid continues to be injected or is injected through the drill string. Due to the obstructed piston bore, fluid pressure acting on the ball  1390  and retraction piston  1310  increases until the shear pins  1322  are fractured. The retraction piston  1310  may move longitudinally relative to the body  1305  until the shoulder  1310   s  engages the shoulder  1307   a , thereby opening lower ports  1310   l  and closing upper ports  1310   u . Closing of the upper ports  1310   u  may isolate the control chamber  1311  except for the check valve  1317  allowing retraction of the extension piston  10  via bypass  1307   b . The lower ports  1310  provide fluid communication between around the closed ball seat. The ball  1390  may or may not gradually dissolve to reopen the seat  1310   s . Injection of drilling fluid may then be halted, thereby allowing the control module spring to retract the arms  50   a,b . Once the arms are retracted, isolation of the piston surface  10   h  prevents further extension of the arms  50   a,b  when drilling fluid is injected through the underreamer  1300 . 
     Alternatively, a similar effect may be achieved by adding a circulation sub (not shown) to a BHA including the underreamer  100  and the control module  200 . The circulation sub may include a body having a bore therethrough and one or more ports formed through a wall thereof. A piston may be disposed in the body and seal the port in a closed position. The piston may have a seat for receiving a closure member, such as a ball. The piston may be longitudinally coupled to the body by one or more frangible fasteners, such as shear pins. The piston may be longitudinally movable relative to the body to an open position where the ports are in fluid communication with the body bore. In operation, after the underreaming operation is complete, the ball may be pumped or dropped down to the seat. The circulation seat may be larger than the control module seat to allow passage of the ball  290 . The circulation ball may land in the circulation seat and pressure may increase or be increased to fracture the shear pins and move the piston to the open position. The ball and piston may seal or at least substantially obstruct the body bore below the ports, thereby preventing fluid pressure from operating the underreamer piston and allowing the cleaning operation, discussed above to be performed without extending the underreamer arms. 
       FIGS. 14A and 14B  are cross-sections of a hydraulic control module  1400  in a retracted and extended position, respectively, according to another embodiment of the present invention. The control module  1400  may include a body  1405 , an adapter  1407 , a control mandrel  1410 , a piston  1415 , a piston mandrel  1420 , a valve mandrel  1425 , a valve head  1430   i , a valve seat  1430   o , and a biasing member  1435 . The body  1405  may be tubular and have a longitudinal bore formed therethrough. Each longitudinal end  1405   a,b  of the body  1405  may be threaded for longitudinal and rotational coupling to other members, such as the underreamer  100  at  1405   b  and the adapter at  1405   a . The adapter  1407  may be tubular and have a longitudinal bore formed therethrough. Each longitudinal end  1407   a  of the adapter  1407  may be threaded for longitudinal and rotational coupling to other members, such as the drill string at  1407   a.    
     The biasing member may be a spring, such as a Belleville spring  1435 , and may be disposed between a bottom of the adapter  1407  and a top of the piston  1415 . The spring  1435  may bias a longitudinal end of the control mandrel  1410  or a control module adapter (not shown) into abutment with the underreamer piston end, thereby also biasing the underreamer piston toward the retracted position. Advantageously, a preload of the Belleville spring  1435  may be easily adjusted for various underreamer configurations. The control mandrel  1410  may be longitudinally coupled to the piston  1415 , such as with a threaded connection. The piston mandrel  1420  may be longitudinally coupled to the piston  1415 , such as with a threaded connection. A vent (not shown) may be formed through a wall of the body  1405  and provide fluid communication between a spring chamber formed radially between the spring mandrel and the body and an exterior of the control module  1400 . 
     The valve head  1430   i  and seat  1430   o  may each be rings made from an erosion resistant material, such as a metal, alloy, ceramic, or cermet. The valve head  1430   i  may be longitudinally coupled to the valve mandrel  1425 , such as by being disposed between a shoulder formed in the valve mandrel  1425  and a fastener (not easily seen due to scale). The valve mandrel  1425  may be longitudinally coupled to the piston  1415 , such as with a threaded connection. The valve seat  1430   o  may be longitudinally coupled to the body  1405 , such as by being disposed between a shoulder  1405   s  formed in the body  14205  and a fastener (not easily seen due to scale). One or more seals, such as o-rings  1412 , may be disposed between the piston  1415  and the body  1405  and may isolate the spring chamber from a piston chamber formed radially between the piston  1415 /valve mandrel and the body  1405 . Various other seals, such as o-rings may be disposed throughout the control module  1400 . 
     The valve  1430   i,o  may be operable between an open and closed position. In the closed position, the valve  1430   i,o  may at least substantially isolate the piston chamber from a valve chamber formed radially between the control mandrel  1410  and the body  1405 . One or more ports  1410   p  formed through a wall of the control mandrel  1410  may provide fluid communication between the valve chamber and a bore of the control mandrel. A predetermined radial clearance (not easily seen due to scale) may be formed between the valve head  1430   i  and seat  1430   o  to at least restrict, substantially restrict, or severely restrict fluid flow between the valve chamber and the piston chamber. The predetermined radial clearance may be less than or equal to 0.005 inch, 0.004 inch, 0.003 inch, or 0.002 inch. Alternatively, the valve head and seat may each be tapered so that the head contacts the seat in the closed position, thereby forming a seal. 
     When deploying the underreamer  100  and control module  1400  in the wellbore, a drilling operation (e.g., drilling through a casing shoe) may be performed without extension of the underreamer  100 . Even though force is exerted on the underreamer piston  10  by drilling fluid, the spring  1435  preload may prevent the underreamer piston  10  from extending the arms  50   a,b  at least for a predetermined duration of time sufficient to drill through the casing shoe. When it is desired to operate the underreamer  100 , an injection rate of the drilling fluid is substantially increased from the normal drilling flow rate. Fluid pressure acting on the underreamer piston  10  (and an end of the valve mandrel and an end of the valve head) increases until the spring preload is overcome, thereby moving the piston  1415  and mandrels  1420 ,  1425  longitudinally relative to the body, opening the valve  1430   i,o , and compressing the spring  1435 . With the valve open, drilling fluid pressure may act on the control module piston  1415  and the underreamer piston  10  so that the drilling fluid rate may be reduced to normal while retaining the valve in the open position and the underreamer in the extended position. Further, injection of the drilling fluid may be halted and the valve may be re-closed to allow a further operation to be performed while injecting drilling fluid with the underreamer retracted, such as a cleanout operation, discussed above. 
     Alternatively, any of the control modules  200 ,  300 ,  600 ,  630 ,  650 ,  1030 ,  1030   a - c ,  1130 ,  1200 ,  1400  may be used with any of the underreamer  100 , casing cutter  1000 , or section mill  1100 . Alternatively, the section mill may be used in an underreaming operation or vice versa. Alternatively, any of the sensors or electronics of the telemetry sub  400  may be incorporated into any of the control modules  300 ,  600 ,  630 ,  650 ,  1030 ,  1030   a - c ,  1130  and the telemetry sub  400  may be omitted. 
     Additionally, as with the underreamer, two section mills may be connected. The primary section mill may be extended to mill a section of casing/liner. Once the arms of the primary mill become worn, the backup mill may be extended by sending an instruction signal, thereby commanding retraction of the primary mill and extension of the backup mill. The milling operation may then continue without having to remove the primary mill to the surface for repair. Alternatively, two casing cutters  1000  may be deployed in a similar fashion. Alternatively, also as with the underreamer, a stabilizer or adjustable stabilizer may be used with the casing cutter or section mill or with two casing cutters or section mills. 
     In another alternative (not shown), any of the electric control modules  300 ,  600 ,  630 ,  650 ,  1030 ,  1030   a - c ,  1130  may include an override connection in the event that the telemetry sub  400  and/or controllers of the control modules fail. An actuator may then be deployed from the surface to the control module through the drill string using wireline or slickline. The actuator may include a mating coupling. The actuator may further include a battery and controller if deployed using slickline. The override connection may be a contact or hard-wire connection, such as a wet-connection, or a wireless connection, such as an inductive coupling. The override connection may be in direct communication with the control module actuator, e.g., the solenoid valve, so that transfer of electricity via the override connection will operate the control module actuator. 
     In another alternative (not shown), any of the electric control modules  300 ,  600 ,  630 ,  650 ,  1030 ,  1030   a - c ,  1130  may be deployed without the electronics package and without the telemetry sub and include the override connection, discussed above. The wireline or slickline actuator may then be deployed each time it is desired to operate the control module. 
     Additionally, the telemetry sub  400  or any of the sensors or electronics thereof may be used with the motor actuator, the jar actuator, the vibrating jar actuator, the overshot actuator, or the disconnect actuator disclosed and illustrated in the &#39;077 application. 
     While the foregoing is directed to embodiments of the present invention, other and further embodiments of the invention may be devised without departing from the basic scope thereof, and the scope thereof is determined by the claims that follow.