Patent Publication Number: US-9428962-B2

Title: Selective deployment of underreamers and stabilizers

Description:
CROSS-REFERENCE TO RELATED APPLICATIONS 
     This application claims the benefit of a related U.S. Provisional Patent Application having Ser. No. 61/713,317 filed Oct. 12, 2012, titled “Selective Deployment of Underreamers and Stabilizers,” to Mahajan et al., the disclosure of which is incorporated by reference herein in its entirety. 
    
    
     BACKGROUND 
     Embodiments described herein generally relate to downhole tools. More particularly, such embodiments relate to underreamers and stabilizers for enlarging the diameter of a wellbore. 
     In the drilling of oil and gas wells, concentric casing strings are installed and cemented in the wellbore as drilling progresses to increasing depths. Each new casing string is supported within the previously installed casing string, thereby limiting the annular area available outside the uppermost casing strings for the cementing operation. Further, as successively smaller diameter casing strings are suspended, the flow area for the production of oil and gas inside the casing strings decreases as the distance from the surface increases. Therefore, to increase the annular space for the cementing operation, and to increase the production flow area, it is often desirable to enlarge the diameter of the wellbore below the lower end portion of the previous casing string. 
     Underreamers are used for enlarging the diameter of the wellbore below the lower end portion of the previous casing string and stabilizers are used for controlling the trajectory of the underreamer during the drilling process. An underreamer generally has two states—an inactive or collapsed state where the cutters of the underreamer are stationary and the underreamer maintains a diameter small enough to pass through the existing casing strings, and an active or expanded state where one or more arms having the cutters on the end portions thereof extend radially outward from the underreamer. In the active state, the cutters are adapted to enlarge the diameter of the wellbore. As the underreamer is lowered into deeper and harder formations, however, additional underreamers may need to be deployed. 
     What is needed, therefore, are improved systems and methods for running multiple underreamers and/or stabilizers downhole. 
     SUMMARY 
     This summary is provided to introduce a selection of concepts that are further described below in the detailed description. This summary is not intended to identify key or essential features of the claimed subject matter, nor is it intended to be used as an aid in limiting the scope of the claimed subject matter. 
     A downhole tool for increasing a cross-sectional area of a wellbore is disclosed. The downhole tool may include a first drilling assembly which includes a first reaming tool, a first ball seat, and a first piston. The first reaming tool selectively increases the cross-sectional area of the wellbore. The first ball seat may receive a first ball. At least one of the first ball seat and the first ball may deform to allow the first ball to pass through the first ball seat when a predetermined pressure is applied thereto. The first piston may be coupled to the first ball seat. The first ball seat and the first piston may stroke when the first ball is received within the first ball seat, thereby actuating the first reaming tool between an active state and an inactive state. A second drilling assembly may be axially offset from the first drilling assembly along the downhole tool. The second drilling assembly includes a second reaming tool, a second ball seat, and a second piston. The second reaming tool selectively increases the cross-sectional area of the wellbore. The second ball seat may receive a second ball. At least one of the second ball seat and the second ball may deform to allow the second ball to pass through the second ball seat when a predetermined pressure is applied thereto. The second piston may be coupled to the second ball seat. The second ball seat and the second piston may stroke when the second ball is received within the second ball seat, thereby actuating the second reaming tool between an active state and an inactive state. 
     In another embodiment, the downhole tool may include a first drilling assembly which includes a first reaming tool, a first ball seat, and a first piston. The first reaming tool selectively increases the cross-sectional area of the wellbore. The first ball seat may receive a ball. At least one of the first ball seat and the ball may deform to allow the ball to pass through the first ball seat when a predetermined pressure is applied thereto. The first piston may be coupled to the first ball seat. The first ball seat and the first piston may stroke when the ball is received within the first ball seat. A first indexing mechanism may be coupled to the first piston. The first indexing mechanism may actuate the first reaming tool between an active state and an inactive state after each stroke of the first piston. A second drilling assembly may be axially offset from the first drilling assembly along the downhole tool. The second drilling assembly includes a second reaming tool, a second ball seat, and a second piston. The second reaming tool selectively increases the cross-sectional area of the wellbore. The second ball seat may receive the ball. At least one of the second ball seat and the ball may deform to allow the ball to pass through the second ball seat when a predetermined pressure is applied thereto. The second piston may be coupled to the second ball seat. The second ball seat and the second piston may stroke when the ball is received within the second ball seat. A second indexing mechanism may be coupled to the second piston. The second indexing mechanism may actuate the second reaming tool between an active state and an inactive state after two strokes of the second piston. 
     A method for increasing a cross-sectional area of a wellbore is also disclosed. The method includes running a downhole tool into the wellbore. The downhole tool includes first and second drilling assemblies coupled thereto and axially offset from one another. A first ball may be received within a first ball seat of the first drilling assembly. At least one of the first ball seat and the first ball may deform when a predetermined pressure is reached to allow the first ball to pass through the first ball seat. The first ball seat and a first piston coupled thereto move in response to the first ball being received in the first ball seat, thereby actuating a first reaming tool of the first drilling assembly between an active state and an inactive state. The first reaming tool may increase a cross-sectional area of the wellbore in the active state. A second ball may be received within a second ball seat of the second drilling assembly. At least one of the second ball seat and the second ball may deform when the predetermined pressure is reached to allow the second ball to pass through the second ball seat. The second ball seat and a second piston coupled thereto move in response to the second ball being received in the second ball seat, thereby actuating a second reaming tool of the second drilling assembly between the active state and the inactive state. The second reaming tool may increase the cross-sectional area of the wellbore in the active state. 
    
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
       So that the recited features may be understood in detail, a more particular description, briefly summarized above, may be had by reference to one or more embodiments, some of which are illustrated in the appended drawings. It is to be noted, however, that the appended drawings illustrate only exemplary embodiments and are therefore not to be considered limiting of scope, for the invention may admit to other equally effective embodiments. 
         FIG. 1  depicts a cross-sectional view of an illustrative downhole tool including a plurality of drilling assemblies coupled thereto in tandem, according to one or more embodiments disclosed. 
         FIG. 2-1  depicts a cross-sectional view of a portion of a drilling assembly depicted in  FIG. 1 , according to one or more embodiments disclosed. 
         FIG. 2-2  depicts a cross-sectional view of an illustrative piston assembly in the drilling assembly depicted in  FIG. 2-1 , according to one or more embodiments disclosed. 
         FIG. 3  depicts a cross-sectional view of another illustrative downhole tool including a plurality of drilling assemblies coupled thereto in tandem, according to one or more embodiments disclosed. 
         FIG. 4  depicts a cross-sectional view of yet another illustrative downhole tool including a plurality of drilling assemblies coupled thereto in tandem, according to one or more embodiments disclosed. 
         FIGS. 5 and 6  depict cross-sectional views of illustrative indexing mechanisms for the drilling assemblies depicted in  FIG. 4 , according to one or more embodiments disclosed. 
         FIG. 7  depicts a perspective view of a portion of a cam-piston in  FIG. 4  having the indexing mechanism of  FIG. 6  coupled thereto, according to one or more embodiments disclosed. 
         FIG. 8  depicts a cross-sectional view of another illustrative downhole tool including a plurality of drilling assemblies coupled thereto in tandem, according to one or more embodiments disclosed. 
         FIG. 9  depicts a cross-sectional view of yet another illustrative downhole tool including a plurality of drilling assemblies coupled thereto in tandem, according to one or more embodiments disclosed. 
     
    
    
     DETAILED DESCRIPTION 
       FIG. 1  depicts a cross-sectional view of an illustrative downhole tool  100  including a plurality of drilling assemblies  110 ,  120 ,  130  coupled thereto in tandem, and  FIG. 2-1  depicts a cross-sectional view of a portion of the drilling assembly  110 , according to one or more embodiments. While drilling assemblies  120  and  130  are not shown in greater detail, those skilled in the art will readily understand that such drilling assemblies and their operation are similar to drilling assembly  110 . The drilling assemblies  110 ,  120 ,  130  are positioned in series along the tool  100 . More particularly, the drilling assemblies  110 ,  120 ,  130  are positioned axially-offset from one another along the length of the tool  100 . Although three drilling assemblies  110 ,  120 ,  130  are shown, it may be appreciated that the number of drilling assemblies  110 ,  120 ,  130  on the tool  100  may range from a low of 1, 2, 3 or 4 to a high of 6, 8, 10 or more. Illustrative drilling assemblies  110 ,  120 ,  130  are shown and described in U.S. Pat. No. 6,732,817. 
     The drilling assemblies  110 ,  120 ,  130  each include one or more reaming tools  112 ,  122 ,  132 , one or more stabilizers (not shown), or a combination thereof. For purposes of simplicity, the foregoing description will refer to reaming tools  112 ,  122 ,  132 ; however, it may be appreciated that any of  112 ,  122 ,  132  may also refer to a stabilizer or a reaming tool/stabilizer combination. It may also be appreciated to those skilled in the art that the drilling assemblies of the various embodiments of  FIGS. 3-4 and 8-9  may also include one or more reaming tools, one or more stabilizers (not shown), or a combination thereof. 
     Each drilling assembly  110 ,  120 ,  130  includes a piston assembly  116 ,  126 ,  136  adapted to actuate the corresponding reaming tool  112 ,  122 ,  132 .  FIG. 2-2  depicts a cross-sectional view of an illustrative piston assembly  116  in the drilling assembly  110 , according to one or more embodiments. The piston assembly  116  includes a mandrel  150  having a cam-piston  117  disposed therein. The cam-piston  117  is adapted to move or slide axially within the mandrel  150 . A ball seat  114  may be coupled to or integral with a distal end portion of the cam-piston  117 . The ball seat  114  is adapted to receive a ball  115  dropped into the wellbore from the surface. The ball  115  forms a fluid tight seat against the ball seat  114  allowing pressure to build up within the bore of the piston assembly  116 . As the pressure builds, the cam-piston  117  moves in a first axial direction within the mandrel  150  until a shoulder  154  extending radially outward from the cam-piston  117  contacts a shoulder  156  extending radially inward from the mandrel  150  preventing further movement. As the cam-piston  117  moves in the first axial direction, another shoulder  152  extending radially outward therefrom may compress or collapse a spring  158  against a stationary (relative to the cam-piston  117 ) spacer  153 . 
     The ball seat  114  and/or the ball  115  may be deformable. For example, the ball seat  114  may be deformable and the ball  115  may be non-deformable. As used herein, the term “deformable” refers to the ability of an element to change shape temporarily and then return to its original shape. When the pressure within the bore reaches a predetermined level, the ball seat  114  and/or the ball  115  may deform to allow the ball  115  to pass through the ball seat  114 . Once the ball  115  passes through the ball seat  114 , the ball  115  may become retained within a ball catcher  118  disposed downstream from the ball seat  114  (see  FIGS. 1 and 2-1 ). Illustrative ball catchers  118  are shown and described in U.S. Patent Publication No. 2007/027412. Further, once the ball  115  passes through the ball seat  114 , the spring  158  may stretch or expand, thereby pushing the shoulder  152  and the cam-piston  117  in the second axial direction. 
     Each time the cam-piston  117  moves axially within the mandrel  150 , a cartridge  160  disposed between the cam-piston  117  and the mandrel  150  may pivot or rotate at least partially around the circumference of the cam-piston  117 . The cartridge  160  may have a pin or protrusion  161  extending radially-inward therefrom that is arranged and designed to move through a slot or groove (not shown but see, e.g.,  502  of  FIG. 5 ) in an indexing mechanism (not shown but see, e.g.,  500  of  FIG. 5 ) disposed on the cam-piston  117  (see generally  FIGS. 5-7 , which illustrate the similar arrangement of cam-piston  427 , slot or groove  602  and indexing mechanism  600 ). As the cam-piston  117  moves axially, the protrusion  161  slides through the groove  502  in the indexing mechanism  500  and causes the cartridge  160  to rotate between the cam-piston  117  and the mandrel  150 , as similarly described in more detail below with respect to  FIGS. 5-7 . The interaction of the protrusion  161  of the cartridge  160  and the indexing mechanism  500  of the cam-piston  117  determines the axial resting position of the cam-piston  117  after each stroke. 
     The axial resting position of the cam-piston  117  relative to the mandrel  150  determines whether one or more ports  162  formed radially through the mandrel  150  are aligned with one or more ports  164  formed radially through the cam-piston  117 . When the ports  162 ,  164  are aligned, pressurized fluid may flow therethrough actuating the reaming tool  112  into an “active” position, and when the ports  162 ,  164  are axially offset (as shown), the reaming tool  112  is actuated into an “inactive” position. In at least one embodiment, after a single stroke of the cam-piston  117 , the ports  162 ,  164  may be aligned and the reaming tool  112  may actuate into the active state. However, in another embodiment, it may take two (or more) strokes of the cam-piston  117  for the ports  162 ,  164  to align such that the reaming tool  112  actuates into the active state. 
     In the inactive state, one or more cutters on the reaming tool  112  may be stationary and folded into the body of the reaming tool  112  allowing the reaming tool  112  to maintain a diameter small enough to pass through the existing casing strings. In the active state, the reaming tool  112  may be in an expanded state where one or more arms with the cutters on the end portions thereof extend radially outward. Further, in the active state, the cutters of the reaming tool  112  may be adapted to cut into the formation and enlarge the diameter of the wellbore. 
     Referring now to  FIGS. 1, 2-1, and 2-2 , the ball seats  114 ,  124 ,  134  in the drilling assemblies  110 ,  120 ,  130  have an aperture defined or formed axially therethrough. At least a portion of an inner surface of the ball seat, i.e., the surface defining the aperture, may be frustoconical. Balls  115 ,  125 ,  135  having different diameters are dropped into the wellbore from the surface and travel into the tool  100 . In at least one embodiment, the aperture in the ball seat  114  may have a diameter less than a diameter of the “large” ball  115  but greater than the diameter of the “medium” ball  125  and “small” ball  135 . As such, the medium and small balls  125 ,  135  flow through the ball seat  114  while the large ball  115  becomes lodged in the ball seat  114  and obstructs flow therethrough until a predetermined pressure forces the ball seat  114  (or ball  115 ) to deform to allow the ball  115  to pass therethrough. Similarly, the aperture in the ball seat  124  may have a diameter less than a diameter of the medium ball  125  but greater than the diameter of the small ball  135 . As such, the small ball  135  flows through the ball seat  124  while the medium ball  125  becomes lodged in the ball seat  124  and obstructs flow therethrough until a predetermined pressure forces the ball seat  124  (or ball  125 ) to deform to allow the ball  125  to pass therethrough. Illustrative ball seats  114 ,  124 ,  134  and balls  115 ,  125 ,  135  are shown and described in U.S. Pat. No. 7,416,029. 
     In operation, the first drilling assembly  110  is actuated by dropping a large ball  115  down the drill string from the surface, and the large ball  115  becomes lodged in the ball seat  114 . Pressure is then applied to the drill string from the surface via pump drilling fluid. As the pressure builds, the cam-piston  117  in the piston assembly  116  moves in the first axial direction until the pressure reaches a predetermined amount where the ball seat  114  (or the large ball  115 ) deforms and allows the large ball  115  to pass therethrough and become retained within the ball catcher  118 . Once the large ball  115  passes through the ball seat  114 , the cam-piston  117  moves in the second axial direction due to the expansion of the spring  158 , thereby actuating the reaming tool  112  between the inactive state and the active state or vice versa. The first drilling assembly  110  may be actuated between the active and inactive states by dropping subsequent large balls  115  into the tool  100 . 
     The second drilling assembly  120  is actuated by dropping a medium ball  125  down the drill string from the surface, and the medium ball  125  becomes lodged in the ball seat  124 . As the medium ball  125  is smaller than the large ball  115 , it may pass through the ball seat  114  and the ball catcher  118  without being retained therein. Pressure is then applied to the drill string from the surface via pump drilling fluid. As the pressure builds, the cam-piston  127  of the piston assembly  126  moves in the first axial direction until the pressure reaches a predetermined amount where the ball seat  124  (or the medium ball  125 ) deforms and allows the medium ball  125  to pass therethrough and become retained within the ball catcher  128 . Once the medium ball passes through the ball seat  124 , cam-piston  127  moves in the second axial direction due to the expansion of the spring, thereby actuating the reaming tool  122  between the inactive state and the active state or vice versa. The second drilling assembly  120  may be actuated between the active and inactive states by dropping subsequent medium balls  125  into the tool  100 . 
     The third drilling assembly  130  is actuated by dropping a small ball  135  down the drill string from the surface, and the small ball  135  may become lodged in the ball seat  134 . As the small ball  135  is smaller than the large and medium balls  115 ,  125 , it may pass through the ball seats  114 ,  124  and the ball catchers  118 ,  128  without becoming retained therein. Pressure is then applied to the drill string from the surface via pump drilling fluid. As the pressure builds, the cam-piston  137  of the piston assembly  136  moves in the first axial direction until the pressure reaches a predetermined amount where the ball seat  134  (or the small ball  135 ) deforms and allows the small ball  135  to pass therethrough and become retained within the ball catcher  138 . Once the small ball  135  passes through the ball seat  134 , the cam-piston  137  moves in the second axial direction due to the expansion of the spring, thereby actuating the reaming tool  132  between the inactive state and the active state or vice versa. The third drilling assembly  130  may be actuated between the active and inactive states by dropping subsequent small balls  135  into the tool  100 . The varying sizes of the ball seats  114 ,  124 ,  134  and the balls  115 ,  125 ,  135  may allow the reaming tools, e.g.,  112 , to be selectively actuated between the inactive and active states independent of the other reaming tools, e.g.,  122 ,  132 . 
     The drilling assemblies  110 ,  120 ,  130  may each have the same cross-sectional length (e.g., diameter) when in the active state. As such, each of the drilling assemblies  110 ,  120 ,  130  may be arranged and designed to increase the diameter of the wellbore to a single predetermined diameter. In another embodiment, one or more of the drilling assemblies (e.g., drilling assembly  110 ) may have a different cross-sectional length (e.g., diameter) than one or more of the other drilling assemblies (e.g., drilling assemblies  120 ,  130 ) when in the active state. As such, the drilling assembly  110  may be arranged and designed to increase the diameter of the wellbore to a first diameter, and the drilling assemblies  120 ,  130  may be arranged and designed to increase the diameter of the wellbore to a second, different diameter. 
       FIG. 3  depicts a cross-sectional view of another illustrative downhole tool  300  including a plurality of drilling assemblies  310 ,  320 ,  330  coupled thereto in tandem, according to one or more embodiments. Although three drilling assemblies  310 ,  320 ,  330  are shown, it may be appreciated that more or fewer may be used. The drilling assemblies  310 ,  320 ,  330  may be generally similar to the drilling assemblies  110 ,  120 ,  130  depicted in  FIG. 1 , and like components will not be described again in detail. The ball seats  314 ,  324 ,  334  in the drilling assemblies  310 ,  320 ,  330 , however, may each define an aperture with substantially the same cross-sectional area, e.g., diameter. Accordingly, a single ball  315  may actuate multiple drilling assemblies  310 ,  320 ,  330  in sequence. 
     In operation, a ball  315  is dropped down the drill string from the surface, and the ball  315  becomes lodged in the ball seat  314  of the first drilling assembly  310 . Pressure may then be applied to the drill string from the surface via pump drilling fluid. As the pressure builds, the cam-piston  317  moves in the first axial direction until the pressure reaches a predetermined amount where the ball seat  314  (or ball  315 ) deforms and allows the ball  315  to pass therethrough. The cam-piston  317  then moves via spring action in the second axial direction, thereby actuating the first reaming tool  312  between the inactive state and the active state or vice versa. 
     The ball  315  may then flow through the tool  300  and become lodged in the ball seat  324  of the second drilling assembly  320 . Pressure may again be applied to the drill string from the surface via pump drilling fluid. As the pressure builds, the cam-piston  327  moves in the first axial direction until the pressure reaches a predetermined amount where the ball seat  324  (or ball  315 ) deforms and allows the ball  315  to pass therethrough. The cam-piston  327  then moves via spring action in the second axial direction, thereby actuating the second reaming tool  322  between the inactive state and the active state or vice versa. 
     The ball  315  may then flow through the tool  300  and become lodged in the ball seat  334  of the third drilling assembly  330 . Pressure may again be applied to the drill string from the surface via pump drilling fluid. As the pressure builds, the cam-piston  337  moves in the first axial direction until the pressure reaches a predetermined amount where the ball seat  334  (or ball  315 ) deforms and allows the ball  315  to pass therethrough. The cam-piston  337  then moves via spring action in the second axial direction, thereby actuating the third reaming tool  332  between the inactive state and the active state or vice versa. When the ball  315  passes through the last drilling assembly, e.g.,  330 , the ball  315  may become retained within the ball catcher  338 . Thus, each drilling assembly  310 ,  320 ,  330  may be actuated in sequence by a single ball  315 . 
       FIG. 4  depicts a cross sectional view of yet another illustrative downhole tool  400  including a plurality of drilling assemblies  410 ,  420  coupled thereto in tandem,  FIGS. 5 and 6  depict illustrative indexing mechanisms  500 ,  600  for the drilling assemblies  410 ,  420 , and  FIG. 7  depicts a perspective view of a portion of the cam-piston  427  having the indexing mechanism  600  coupled thereto, according to one or more embodiments. 
     The drilling assemblies  410 ,  420  may be generally similar to the drilling assemblies  310 ,  320  depicted in  FIG. 3 , and like components will not be described again in detail. For example, the ball seats  414 ,  424  in the drilling assemblies  410 ,  420  may each define an aperture with substantially the same cross-sectional area, e.g., diameter, such that a single ball  415  may actuate the drilling assemblies  410 ,  420  in sequence. The drilling assemblies  410 ,  420 , however, may include different indexing mechanisms  500 ,  600  adapted to actuate the reaming tools  412 ,  422  between the inactive state and the active state or vice versa. 
     The indexing mechanisms  500 ,  600  are coupled to and adapted to move with the cam-pistons  417 ,  427 . Although shown as flat in  FIGS. 5 and 6 , the indexing mechanisms  500 ,  600  may be cylindrical or annular and have a grooved path  502 ,  602  formed circumferentially within the inner and/or outer surface thereof (see  FIG. 7 ). The grooved paths  502 ,  602  may include “long” grooves  504 ,  604  and “short” grooves  506 ,  606 . The grooves  504 ,  506 ,  604 ,  606  may be circumferentially offset from one another. For example, the grooves  504 ,  506  may be circumferentially offset from one another by 90°, and the grooves  604 ,  606  may be circumferentially offset from one another by 45°, as shown; however, other distances are also contemplated herein. 
     The cartridge  160  disposed between the cam-piston  417 ,  427  and the mandrel  150  (see, e.g.,  FIG. 2-2 , which illustrates a similar arrangement with cam-piston  117 ), may have a protrusion  161  extending radially-inward therefrom that is adapted to travel through the grooved path  502 ,  602  of the indexing mechanism  500 ,  600 . For example, each time the cam-pistons  417 ,  427  stroke back and forth, sloped surfaces  508 ,  608  in the indexing mechanisms  500 ,  600  may cause the protrusion  161 , and thus the cartridge  160 , to at least partially rotate about a longitudinal axis therethrough. 
     In at least one embodiment, when the protrusion  161  of the cartridge  160  comes to rest in a long groove  504 ,  604  of the indexing mechanism  500 ,  600  after a stroke of the cam-piston  417 ,  427 , the reaming tool  412 ,  422  is in the inactive state due to the misalignment of the ports  162 ,  164 , and when the protrusion  161  of the cartridge  160  comes to rest in a short groove  506 ,  606  of the indexing mechanism  500 ,  600  after a stroke of the cam-piston  417 ,  427 , the reaming tool  412 ,  422  is in the active state due to the alignment of the ports  162 ,  164  (see, e.g.,  FIG. 2-2 , which illustrates a similar arrangement with cam-piston  117 ). 
     Accordingly, the first indexing mechanism  500  may require two strokes of the cam-piston  417  to actuate the first reaming tool  412  into the active state while the second indexing mechanism  600  may require one stroke of the cam-piston  427  to actuate the second reaming tool  422  into the active state. In the exemplary embodiment shown in  FIG. 5 , the first reaming tool  412  may start in the inactive state (0°) and remain in the inactive state after the first stroke (45°). The first reaming tool  412  may then actuate into the active state after the second stroke (90°) and remain in the active state after the third stroke (135°). The first reaming tool  412  may then actuate into the inactive state after the fourth stroke (180°) and remain in the inactive state after the fifth stroke (225°). The first reaming tool  412  may then actuate into the active state after the sixth stroke (270°) and remain in the active state after the seventh stroke (315°), thereby completing the cycle. In contrast, the second indexing mechanism  600  may start in the inactive state and actuate into the active state after the first stroke (45°). The second indexing mechanism  600  may then actuate between the active state and the inactive state after each subsequent stroke, as shown. 
     Thus, in operation, a first ball  415 - 1  may be dropped down the drill string from the surface. The first ball  415 - 1  may cause the first and second cam-pistons  417 ,  427  to stroke a first time. After the first stroke, the first reaming tool  412  remains in the inactive state while the second reaming tool  422  actuates into the active state. A second ball  415 - 2  may then be dropped down the drill string from the surface. The second ball  415 - 2  may cause the first and second cam-pistons  417 ,  427  to stroke a second time. After the second stroke, the first reaming tool  412  actuates into the active state, and the second reaming tool  422  actuates into the inactive state. A third ball  415 - 3  may then be dropped down the drill string from the surface. The third ball  415 - 3  may cause the first and second cam-pistons  417 ,  427  to stroke a third time. After the third stroke, the first reaming tool  412  remains in the active state, and the second reaming tool  422  actuates into the active state. A fourth ball  415 - 4  may then be dropped down the drill string from the surface. The fourth ball  415 - 4  may cause the first and second cam-pistons  417 ,  427  to stroke a fourth time. After the fourth stroke, the first and second reaming tools  412 ,  422  both actuate into the inactive state, thereby completing the cycle. 
     Thus, the indexing mechanisms  500 ,  600  allow the reaming tools  412 ,  422  to be selectively actuated based upon the number of balls  415  dropped into the tool  400 . It may be appreciated that the indexing mechanisms  500 ,  600  are only exemplary, and other designs are also contemplated herein. It may also be appreciated that this concept may be applied to more than two drilling assemblies  410 ,  420  coupled to the tool  400 . For example, this concept may be applied to a tool having 2, 3, 4, 5, 6, 7, 8, 9, 10, or more drilling assemblies coupled to the tool  400 . 
       FIG. 8  depicts a cross-sectional view of another illustrative downhole tool  800  including a plurality of drilling assemblies  810 ,  820  coupled thereto in tandem, according to one or more embodiments. The drilling assemblies  810 ,  820  may be generally similar to the drilling assemblies  110 ,  120  depicted in  FIG. 1 , and like components will not be described again in detail. For example, the ball seat  814  may have a larger cross-sectional area e.g., diameter, than the ball seat  824 . As such, a “small” ball  825  may pass through the first ball seat  814  without actuating the first reaming tool  812 . The small ball  825  may, however, actuate the second reaming tool  822 . A “large” ball  815  may actuate the first reaming tool  812  and subsequently actuate the second reaming tool  822 . It may be appreciated that a greater pressure may be required to cause the large ball  815  to pass through the ball seat  824  than is required for the small ball  825 . 
     Thus, in operation, both reaming tools  812 ,  822  may begin in the inactive state. A first, small ball  825 - 1  may be dropped down the drill string from the surface. The first ball  825 - 1  passes through the first reaming tool  812  and actuates the second reaming tool  822  into the active state. A second, large ball  815 - 1  may then be dropped down the drill string from the surface. The second ball  815 - 1  actuates the first reaming tool  812  into the active state and subsequently actuates the second reaming tool  822  into the inactive state. A third, small ball  825 - 2  may then be dropped down the drill string from the surface. The third ball  825 - 2  passes through the first reaming tool  812  and actuates the second reaming tool  822  into the active state. A fourth, large ball  815 - 2  may then be dropped down the drill string from the surface. The fourth ball  815 - 2  actuates the first and second reaming tools  812 ,  822  into the inactive state, thereby completing the cycle. It may be appreciated that this sequence is provided for illustrative purposes, and the large and small balls  815 - 1 ,  815 - 2 ,  825 - 1 ,  825 - 2  may be dropped in any number and any order to selectively actuate the reaming tools  812 ,  822 . 
       FIG. 9  depicts a cross-sectional view of yet another illustrative downhole tool  900  including a plurality of drilling assemblies  910 ,  920 ,  930  coupled thereto in tandem, according to one or more embodiments. Each drilling assembly  910 ,  920 ,  930  may include a flow control device  940 ,  950 ,  960 . Illustrative flow control devices  940 ,  950 ,  960  are shown and described in U.S. Pat. No. 6,289,999. 
     The flow control devices  940 ,  950 ,  960  are adapted to selectively actuate a valve  942 ,  952 ,  962  disposed within the drilling assembly  910 ,  920 ,  930  between an open position and a closed position. When in the open position, fluid may flow through a central flow passage  902  that extends through the tool  900  and each of the drilling assemblies  910 ,  920 ,  930 . When in the closed position, the valve  942 ,  952 ,  962  blocks flow through the central flow passage  902 , and the fluid may be directed through a bypass passage  944 ,  954 ,  964 . The reaming tools  912 ,  922 ,  932  are adapted to actuate into the active state when fluid flows therethrough via the central flow passage  902 , and into the inactive state when the fluid flows through the bypass passages  944 ,  954 ,  964 , or vice versa. 
     In operation, the first reaming tool  912  may be actuated into the active state by opening the first valve  942  with the first flow control device  940  so that fluid may flow through the first reaming tool  912  via the central flow passage  902 . The first reaming tool  912  is then actuated into the inactive state by closing the first valve  942  with the first flow control device  940  so that the fluid instead flows through the first bypass passage  944 . Similarly, the second reaming tool  922  may be actuated into the active state by opening the second valve  952  with the second flow control device  950  so that fluid may flow through the second reaming tool  922  via the central flow passage  902 . The second reaming tool  922  is then actuated into the inactive state by closing the second valve  952  with the second flow control device  950  so that the fluid instead flows through the second bypass passage  954 . The third reaming tool  932  may be actuated into the active state by opening the third valve  962  with the third flow control device  960  so that fluid may flow through the third reaming tool  932  via the central flow passage  902 . The third reaming tool  932  is then actuated into the inactive state by closing the third valve  962  with the third flow control device  960  so that the fluid instead flows through the third bypass passage  964 . 
     In at least one embodiment, each drilling assembly  910 ,  920 ,  930  may include a control unit (not shown) and a valve  942 ,  952 ,  962 . The control units and/or the valves  942 ,  952 ,  962  are adapted to receive signals from the surface. The signals may include an RPM sequence, a flow and/or pressure pulse, a radio signal, communication from a bottom hole assembly (BHA) component, and the like. In at least one embodiment, the signals may be transmitted via wired pipe. Upon receiving the signals, the control units may be adapted to alter the position of the valves  942 ,  952 ,  962 , and the valves  942 ,  952 ,  962  may actuate the reaming tools  912 ,  922 ,  932 . Thus, the signals may selectively actuate the reaming tools  912 ,  922 ,  932  independent of one another. 
     In another embodiment, the first reaming tool  912  may be actuated by one or more balls (not shown), as described with reference to  FIG. 1  above. Thus, a ball may become lodged in the ball seat. Pressure may then be applied to the drill string from the surface via pump drilling fluid. As the pressure builds, the ball seat and the piston may move or stroke in the first axial direction until the pressure reaches a predetermined amount where the ball seat deforms and allows the ball to pass therethrough and become retained within the ball catcher. The ball seat and the piston may then move or stroke in the second axial direction via spring action, thereby actuating the reaming tool  912  between the inactive state and the active state. 
     The second reaming tool  922  may be actuated by one or more signals as described above. For example, the second reaming tool  922  may be actuated with a flow and/or pressure pulse signal. The third reaming tool  932  may be electromechanically actuated with a control unit. Thus, the reaming tools  912 ,  922 ,  932  may each be selectively actuated by different mechanisms. 
     As used herein, the terms “inner” and “outer,” “up” and “dowry,” “upper” and “lower;” “upward” and “downward;” “above” and “below,” “inward” and “outward;” and other like terms as used herein refer to relative positions to one another and are not intended to denote a particular direction or spatial orientation. The terms “large,” “medium,” “small,” “long,” “short,” and the like are used herein to refer to relative sizes to one another. The terms “couple,” “coupled,” “connect,” “connection,” “connected,” “in connection with,” and “connecting” refer to “in direct connection with” or “in connection with via another element or member.” 
     Although only a few example embodiments have been described in detail above, those skilled in the art will readily appreciate that many modifications are possible in the example embodiments without materially departing from “Selective Deployment of Underreamers and Stabilizers,” Accordingly, all such modifications are intended to be included within the scope of this disclosure. In the claims, means-plus-function clauses are intended to cover the structures described herein as performing the recited function and not only structural equivalents, but also equivalent structures. Thus, although a nail and a screw may not be structural equivalents in that a nail employs a cylindrical surface to secure wooden parts together, whereas a screw employs a helical surface, in the environment of fastening wooden parts, a nail and a screw may be equivalent structures. It is the express intention of the applicant not to invoke 35 U.S.C. §112, paragraph 6 for any limitations of any of the claims herein, except for those in which the claim expressly uses the words ‘means for’ together with an associated function.