Abstract:
In one embodiment, a method of forming a wellbore includes running a liner drilling assembly into the wellbore, the liner drilling assembly having a liner, a conveying member, one or more connection members, and a drilling member. The method includes temporarily suspending the liner at a location below the rig floor; releasing the conveying member and the drilling member from the liner; re-connecting the conveying member to the liner; releasing the liner from its location of temporary suspension; and advancing the liner drilling assembly.

Description:
CROSS-REFERENCE TO RELATED APPLICATION 
     This application claims benefit of U.S. Provisional Patent Application No. 60/747,929, filed on May 22, 2006, which application is incorporated herein by reference in its entirety. 
    
    
     BACKGROUND OF THE INVENTION 
     1. Field of the Invention 
     The present invention relates apparatus and methods for drilling and completing a wellbore. Particularly, the present invention relates to apparatus and methods for forming a wellbore, lining a wellbore, and circulating fluids in the wellbore. The present invention also relates to apparatus and methods for cementing a wellbore. 
     2. Description of the Related Art 
     In the drilling of oil and gas wells, a wellbore is formed using a drill bit that is urged downwardly at a lower end of a drill string. After drilling a predetermined depth, the drill string and bit are removed, and the wellbore is lined with a string of casing. An annular area is thus defined between the outside of the casing and the earth formation. This annular area is filled with cement to permanently set the casing in the wellbore and to facilitate the isolation of production zones and fluids at different depths within the wellbore. 
     It is common to employ more than one string of casing in a wellbore. In this respect, a first string of casing is set in the wellbore when the well is drilled to a first designated depth. The well is then drilled to a second designated depth and thereafter lined with a string of casing with a smaller diameter than the first string of casing. This process is repeated until the desired well depth is obtained, each additional string of casing resulting in a smaller diameter than the one above it. The reduction in the diameter reduces the cross-sectional area in which circulating fluid may travel. Also, the smaller casing at the bottom of the hole may limit the hydrocarbon production rate. Thus, oil companies are trying to maximize the diameter of casing at the desired depth in order to maximize hydrocarbon production. To this end, the clearance between subsequent casing strings having been trending smaller because larger subsequent casings are used to maximize production. 
     Drilling with casing or liner is a method of forming a borehole with a drill bit attached to the same string of tubulars that will line the borehole. In other words, rather than run a drill bit on smaller diameter drill string, the bit is run at the end of larger diameter tubing or casing or liner that will remain in the wellbore and be cemented therein. The advantages of drilling with casing are obvious. Because the same string of tubulars transports the bit and lines the borehole, no separate trip out of or into the wellbore is necessary between the forming of the borehole and the lining of the borehole. Drilling with casing or liner is especially useful in certain situations where an operator wants to drill and line a borehole as quickly as possible to minimize the time the borehole remains unlined and subject to collapse or the effects of pressure anomalies, and mechanical instability. 
     In the drilling of offshore wells or deep wells, the length of casing or liner may be shorter than the water depth. Also, in some instances, the wellbore may be formed in stages, such as installing casing and thereafter hanging a liner from the casing. In both cases, the length of casing may not extend back to surface. 
     There is a need, therefore, for running a length of drill casing or liner into the hole to form the wellbore. 
     SUMMARY OF THE INVENTION 
     In one embodiment, a drilling apparatus includes a liner as a portion of the drill string. The axial and torsional loads are carried by the drill pipe and then transferred to the drilling liner by the use of a liner drilling tool. The forces are then transmitted along the liner to a latch. The loads are then transferred from the liner to the latch and attached BHA. The drilling apparatus may include an inner string that connects the liner drilling tool at the liner top to the BHA. This way, when the liner drilling tool and latch are disconnected from the liner, the drill pipe can pull the inner string and BHA from the liner and bore hole. In one embodiment, releasing and pulling the liner drilling tool also releases and pulls the BHA out of hole with the inner string. The inner string can also act as a conduit for fluid flow from the drillpipe to the BHA below. It should be noted that the fluid flow could be split between the inner string and the liner ID, or diverted so the entire flow is in the annulus between the inner string and the liner ID. 
     In another embodiment, a method of forming a wellbore includes running a liner into the wellbore; suspending the liner at a location below the rig floor; running a drilling bottom hole assembly through the liner on a drill string; attaching the drill string to the liner; releasing the liner from its location of suspension; and advancing the liner through the wellbore on the drill string. 
     The present invention relates methods and apparatus for lining a wellbore. In one embodiment, a method of forming a wellbore includes running liner drilling assembly into the wellbore, the liner drilling assembly including a liner, a conveying member, one or more connection members, and a drilling member. The method includes temporarily suspending the liner at a location below the rig floor; releasing the conveying member and the drilling member from the liner; re-connecting the conveying member to the liner; releasing the liner from its location of temporary suspension; and advancing the liner drilling assembly. 
     In another embodiment, an apparatus for forming a wellbore includes a liner coupled to a drilling member; a conveying member releasably connected to the liner, the conveying member adapted to supply torque to the liner; a first releasable and re-settable connection members for coupling the conveying member to the liner; and a second connection member for coupling the liner to the drilling member. 
    
    
     
       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. 
         FIG. 1  shows an embodiment of the liner drilling system according to aspects of the present invention. 
         FIG. 2  shows an embodiment of the liner drilling system with the liner top suspended from a blow-out prevent ram. 
         FIG. 3  shows another embodiment of a liner drilling assembly. 
         FIGS. 4-8  shows the liner drilling assembly of  FIG. 3  in operation. 
         FIG. 9  shows another embodiment of a liner drilling assembly. 
     
    
    
     DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENT 
     In one embodiment, a drilling apparatus includes a liner as a portion of the drill string. The axial and torsional loads are carried by the drill pipe and then transferred to the drilling liner by the use of a liner drilling tool. The forces are then transmitted along the liner to a latch. The loads are then transferred from the liner to the latch and attached BHA. The drilling apparatus may include an inner string that connects the liner drilling tool at the liner top to the BHA. This way, when the liner drilling tool and latch are disconnected from the liner, the drill pipe can pull the inner string and BHA from the liner and bore hole. In one embodiment, releasing and pulling the liner drilling tool also releases and pulls the BHA out of hole with the inner string. The inner string can also act as a conduit for fluid flow from the drill pipe to the BHA below. It should be noted that the fluid flow could be split between the inner string and the liner ID, or the fluid flow can be fully diverted to the annulus area between the inner string OD and the liner ID. In one embodiment, the fluid returning to the surface may flow through the annular area between the wellbore and the outer diameter of the liner and/or the annular area between the inner diameter of the liner and the outer diameter of the inner string. 
       FIG. 1  shows an embodiment of a drilling with liner assembly of the present invention. As shown, the drilling liner assembly  100  extends below a previously installed casing  10 . The drilling liner assembly  100  is run in on drill pipe  110  from the rig floor  22 . A liner drilling tool  116  is used to connect the drill pipe  110  to the liner  120 . The liner drilling tool  116  may be a component of the liner top assembly  115 , which may also include a liner hanger  117  and a polished bore receptacle (“PBR”). In one embodiment, the liner drilling tool  116  functions as a running tool for connecting the drill pipe  110  to the liner  120 . The running tool may include a latch and/or gripping members that may releasably attach and detach from the liner  120 . The running/drilling tool is adapted to transmit axial and torsional forces from the drill pipe  110  to the liner  120 . The running tool may be released from the liner  120  so that the BHA may be retrieved. Preferably, the running tool has torque capability that equals or exceeds the drill pipe capability and is adapted to endure typical bore hole drilling dynamics. Exemplary running tools are disclosed in U.S. Pat. Nos. 5,613,567, 5,531,273, and 6,032,734, which patents are incorporated herein by reference in their entirety. The liner top equipment (liner hanger and PBR) may also include large radial clearance for cuttings bypass and reduced equivalent circulating density (“ECD”) and setting of liner hanger does not reduce the annular clearance area significantly. In one embodiment, setting of the liner hanger and release of drilling tool may be independent of the differential pressure between the inside of the tool and the outside of the liner to prevent premature activation. In another embodiment, the liner top assembly is not equipped with a packer. In yet another embodiment, the liner top assembly utilizes an expandable liner hanger. 
     An inner string  130  extends from the liner running/drilling tool  116  to a drilling latch  140  below. The inner string  130  may be used to convey fluid from the drill pipe  110  and/or to retrieve the BHA. Also, it should be noted that fluid may be conveyed outside of the inner string, inside of the inner string, or the flow split between both. The drilling latch  140  is adapted to releasably connect to the liner  120 . An exemplary drilling latch is disclosed in U.S. Patent Application Publication No. 2004-0216892, filed on Mar. 5, 2004 by Giroux et al. having Ser. No. 10/795,214, entitled Drilling With Casing Latch, which application is herein incorporated by reference in its entirety. The drilling latch  140  is adapted to transfer axial and torsional forces from the liner  120  to the bottom hole assembly (“BHA”). The drilling latch  140  may be hydraulically, mechanically, or remotely actuated. Suitable actuating mechanism includes mud pulse technology, wire line, and fiber optics. 
     As shown in  FIG. 1 , the bottom hole assembly includes one or more stabilizers  155 , a motor  160 , an under-reamer  165 , MWD/LWD  170 , rotary steerable systems  175 , and a drill bit  180 . It must be noted that the BHA may include other components, in addition to or in place of the above items, such as other geophysical measurement sensors, stabilizers such as eccentric or adjustable stabilizers, steerable systems such as bent motor housing, other drill bits such as expandable bit or bits having nozzles or jetting orifices for directional drilling, or any other suitable component as is known to a person of ordinary skill in the art. Further, the components of the BHA may be arranged in any suitable order as is known to a person of ordinary skill in the art. For example, the under-reamer may be place below the motor and MWD/LWD tool. 
     In operation, the liner drilling tool  116  and the drilling latch  140  are actuated to engage the liner  120 . The liner drilling assembly  100  is then run-in to the hole using drill pipe  110 . The liner drilling assembly  100  is directionally steered to drill the hole. In this respect, the hole may be drilled and lined in the same trip. The directional steering is performed using the rotary steerable system  175 . The axial and torsional forces are transferred from the drilling pipe  110  to the liner  120  through the liner running tool  116  and are then transferred from the liner  120  to the BHA through the drilling latch  140 . In this respect, the inner string  130  experiences little, if any, torque that is transmitted. The inner diameter of the hole may be enlarged using the under-reamer  165 . The liner drilling assembly  100  is advanced until total depth is reached. One advantage of the liner drilling assembly is that the liner protects the drilled hole during drilling. After reaching total depth, the liner hanger  117  is set to connect the liner  120  to the previously set casing. Then, the liner running tool  116  and the drilling latch  140  are released to detach from the liner  120  and are removed from the wellbore, thereby removing the BHA. In one embodiment, setting of the liner hanger  117  triggers the release of the liner running tool  116 . After the BHA is retrieved, a cement operation may be performed. 
     In one embodiment, a cement retainer valve is tripped in and installed in the liner to enable cementing from the liner bottom. Thereafter, a conventional cementing operation may be performed. In the situation where cement cannot be circulated, a bottom squeeze may be performed. Thereafter, a second squeeze may be performed at the liner top and the liner top packer may be set in another trip into the hole. 
     In some circumstances, the BHA may become inoperable before total depth is reached and the BHA must be repaired or replaced. In one embodiment, the liner  120  is left in the hole and the liner drilling tool  116  and the drilling latch  140  are released. Then, the BHA is pulled out of the hole. After the BHA is repaired or replaced, the BHA is run-in to the hole and the liner drilling tool  116  and the drilling latch  140  are actuated to re-engage the liner  120 . Thereafter, the drilling operation may continue by applying rotational and axial forces to the BHA. One or more BHAs may be replaced by repeating this process. It must be noted that in this embodiment, a possibility exists that the liner may become stuck during the time it takes to trip the new BHA into the hole. 
     In another embodiment, the liner drilling assembly  100  may be retrieved to a safe location in the wellbore. For example, the liner drilling assembly may be retrieved back to surface. The liner string  120  may then be hung on the rig floor slips. Then, the BHA may be replaced and the liner drilling assembly may be tripped back into the hole. 
     In another example, the liner drilling assembly  100  may be retrieved to a position inside the previously installed casing  10 . In one embodiment, the liner drilling tool  100  may be suspended just below a blow out preventer (“BOP”).  FIG. 2  shows an embodiment of a BOP  200  for suspending a liner drilling assembly in a wellbore. As shown, a liner retaining BOP ram  210  is coupled to a BOP stack having a pipe ram BOP  215  and an annular BOP  220 . It must be noted that the liner retaining BOP ram  210  may be integrated with or an attachment to the BOP stack. The liner top assembly  115  may include a profile  230  for engaging with the ram of the liner retaining BOP  210 . The ram may be hydraulic actuated to move radially into engagement with the profile  230 . Alternately, the liner top  115  may include a hanging shoulder adapted to rest on liner retaining BOP ram. The liner top  115  may be retained using a combination of a profile and/or hanging shoulder. The pipe ram BOP  215  and the annular BOP  220  are then used to close around drill pipe  110  during well control situations. In this respect, the hydraulic forces from the BOP ram are used to park the liner  120  in the wellbore. In one embodiment, one or more sensors may be used to position the liner top assembly  115  relative to the liner retaining BOP ram  210 . An exemplary sensor includes a magnet. The magnet may be positioned on the liner hanger and a sensor may be mounted on the BOP ram  210  to determine the position of the magnet and thereby, the location of the liner hanger (e.g., the profile  230 ). It is contemplated that other suitable sensors such as RFID sensors known to a person of ordinary skill in the art may be used. 
     In operation, the liner drilling assembly  100  is retrieved sufficiently so that the liner top  115  is adjacent the liner retaining BOP  210 . Then, hydraulic forces are applied to radially move the ram into engagement with the liner top, either by way of the profile, the hanging shoulder, or both. Once parked, the liner drilling tool  116  and the drilling latch  140  are released and the BHA is pulled out of the hole. After the BHA is repaired, the BHA is run-in and the liner drilling tool  116  and the drilling latch  140  are actuated to re-engage the liner  120 . Thereafter, the ram is retracted and the liner drilling assembly  100  is released for further drilling. During operation, while the liner drilling assembly is parked in the wellhead  250 , the well may experience an undesired increase in pressure. To prevent a blowout, the other BOP devices (such as pipe rams, annular preventer, and/or shear rams) may be actuated to mitigate wellbore influxes. 
     In another embodiment, the liner retaining BOP  210  may be used to facilitate running in the liner drilling assembly. For example, the liner may be initially run-in to the liner retaining BOP  210 . Thereafter, the BHA is coupled to the drilling latch, liner running tool, and the drill pipe, and is tripped into the liner. Then, the liner running tool and the drilling latch are activated to engage the liner, thereby forming the liner drilling assembly. The retaining BOP  210  is deactivated to release the liner drilling assembly to commence drilling. 
     In another embodiment, the liner top assembly  115  may be adapted to engage a wall of the previously installed casing  10 . The casing may include a liner receiving profile formed on an interior surface of the casing. The liner receiving profile may be adapted to engage the liner hanger of the liner drilling apparatus. In operation, the liner drilling assembly is retrieved sufficiently so that the liner top is adjacent the liner receiving profile. Then, the liner hanger is actuated to engage the profile. Once parked, the liner drilling tool and the drilling latch are released, and the BHA is pulled out of the hole. After the BHA is repaired, the BHA is run-in and the liner drilling tool and the drilling latch are actuated to re-engage the liner. Thereafter, the liner hanger is retracted and the liner drilling apparatus is released for further drilling. It is contemplated that the liner receiving profile may be formed in the previously set casing  10  or the wellhead  250 . Further, it is contemplated that the drilling liner assembly may be retrieved to any suitable portion of the wellbore and suspended therein. It is further contemplated that the liner hanger may engage any portion of the casing, with or without using a liner receiving profile. In this respect, the releasable and re-settable liner hanger may be used to park/hang the liner in the previously set casing  10 . The drilling liner  120  may be left in the open hole or pulled back into the set casing to prevent getting the liner stuck during the BHA replacement trip. The releasable and re-settable liner may be actuated multiple times for potentially multiple BHA trips into and out of the hole. 
     In another embodiment, the releasable and re-settable liner hanger may be used to facilitate run-in of the liner drilling assembly. For example, the liner equipped with a liner hanger is initially run-in to the casing. Thereafter, the liner hanger is activated to engage the casing and suspend the liner. Then, the BHA is coupled to the drilling latch, liner running tool, and the drill pipe, and is tripped into the liner. Then, the liner running tool and the drilling latch are activated to engage the liner, thereby forming the liner drilling assembly. The liner hanger is deactivated to release the liner drilling assembly to commence drilling. 
     In another embodiment, the liner drilling assembly may be run without using the inner string. To retrieve the BHA in the event of failure, the liner is first suspend in the wellbore using any of the above described methods of suspension. Then, a work string is lowered into the wellbore to retrieve the BHA. Exemplary work string includes drill pipe, wireline, coiled tubing, Corod (i.e., continuous rod), and any suitable retrieval mechanism known to a person of ordinary skill in the art. In one embodiment, wireline is used to retrieve the BHA. After the BHA is replaced or repaired, the BHA is lowered back into the liner and the drilling latch is activated. Then, the drill pipe may be lowered and the liner drilling tool is activated to engage an upper portion of the liner. Thereafter, the liner is released from suspension to continue the drilling operation. 
       FIG. 3  shows, another embodiment of the liner drilling assembly  300 . The liner drilling assembly  300  is connected to a drill pipe  310  using a running tool  320 . The running tool  320  may releasably attach the liner  305  to the drill pipe  310  and transmit axial and torsional forces. The liner drilling assembly  300  also includes a liner hanger  325  for hanging the liner  305  in a casing  301 . An inner string  330  connects the running tool  320  to the casing latch  335 . In one embodiment, the inner string  330  may include a pressure and volume balanced extension joint with swivel  337 . The inner string  330  may stab into the latch  335  using a spear  340 , which may be provided with a seal assembly. The latch  335  is adapted to releasably attach to the latch in collar  345  of the liner  305 . Any suitable latch known to a person of ordinary skill in the art may be used. One or more non-rotating or rotating centralizers  350  may be used to centralize the liner  305  relative to the casing  301  or the drilled hole. The lower end of the liner  305  may include a casing shoe  355 . As shown, the BHA  360  extends below the liner  305 . The BHA  360  may include a motor, MWD/LWD, and rotary steerable systems. One or more under-reamer  365  and/or pilot bit  370  may be used to form the wellbore. It must be noted that the BHA  360  may include other components, in the to or in place of above listed items, such as other geophysical measurement sensors, stabilizers such as eccentric or adjustable stabilizers, steerable systems such as bent motor housing, other drill bits such as expandable bit or bits having nozzles or jetting orifices for directional drilling, or any other suitable component as is known to a person of ordinary skill in the art. Further, the components of the BHA may be arranged in any suitable order as is known to a person of ordinary skill in the art. 
     In operation, a sufficient length of liner  305  with the casing shoe  355  and latch in collar  345  is run so that the casing latch  335  and the BHA  360  may be installed in the liner  305 . Then, the remainder of the liner  305  is run in the hole, as illustrated in  FIG. 4 . 
     After running the liner  305 , the liner hanger  325  is installed on top of the liner  305 , as illustrated in  FIG. 5 . The inner string  330  is run inside the liner  305  with the stab in seal assembly  340  on bottom and the pressure volume balanced slip joint  337  below the running tool  320 . The running tool  320  is installed on the end of the inner string  330  and the combined tool  320 /string  330  are installed in the liner hanger  325 . The drilling assembly is now actuated to proceed to drill to the desired depth. Axial and torsional forces may be transmitted from the drill pipe  310  to the liner  305  through the running tool  320  and the latch  345 . In another embodiment, the inner string  330  and the running tool  320  may be connected at the surface and run into the wellbore together for connection with the liner hanger  325 . In yet another embodiment, the liner hanger  325 , inner string  330 , and the running tool  320  may be run in as an assembled apparatus for installation on the liner  305 . 
     After desired depth is reached, the liner hanger  325  is set. In  FIG. 6 , it can be seen that the slips of the liner hanger  325  have been radially extended to engage the previously set casing. The setting of the liner hanger also triggers the release of the running tool  320  from the liner  305 . After the latch  335  is also released the running tool  320  is pulled along with the inner string  330 , casing latch  335 , and BHA  360  out of the hole, as illustrated in  FIG. 6 . 
     In one embodiment, the cementing operation may be performed by running a first (e.g., 16″) packer such as a squeeze packer  381  into the liner  305 . The packer  381  may include slips  383  to engage the interior of the liner  305 . Thereafter, cement is pumped through the packer  381  to squeeze the bottom of the liner  305 , as shown in  FIG. 7 . In another embodiment, a second (e.g., 20″) squeeze packer may be installed in the liner  305  and a cement squeeze is performed at the top of the liner  305 . The cement from this second cement squeeze is directed to the annulus between the top of the liner  305  and the liner hanger  325 , and into the formation just below the bottom of the previously run casing. In one embodiment, pressure is applied through the drill string to the top of the liner below the packer set in the ID of the previously run casing located above the liner top. This applied pressure is typically referred to as break down pressure. After establishing the break down pressure, cement is pumped in from surface, circulated down, then squeezed into the annulus between the casing hanger and the previously run casing until a suitable pressure is achieve, which is typically higher than pump in pressure (squeeze pressure). In this respect, the higher pressure provides an indication that a cement barrier has been established at the top of the liner. 
     In another embodiment, the cementing operation may be performed using subsurface release plugs  375 ,  376 , as shown in  FIG. 8 . Initially, a wireline set packer  385  having a check valve  387  is run in and is set near the bottom of the liner  305 . Then, a modified running tool  390  containing subsurface release (“SSR”) type cementing plugs  375 ,  376  is positioned on top of the liner  305 . A SSR type cementing job is the performed as is known in the art. After cementing, the packing element is set at the top of the liner hanger  325  and the modified running tool  390  is pulled out of the hole. 
       FIG. 9  shows another embodiment of a drilling with liner assembly of the present invention. As shown, the drilling liner assembly  900  extends below a previously installed casing  10 . The drilling liner assembly  900  is run in on drill pipe  910 . A liner drilling tool  916  is used to connect the drill pipe  910  to the liner  920 . The liner drilling tool  916  may be a component of the liner top assembly  915 , which may also include a liner hanger  917  and a polished bore receptacle (“PBR”). In one embodiment, the liner drilling tool functions as a running tool for connecting the drill pipe  910  to the liner  920 . The running tool may include a latch and/or gripping members that may releasably attach and detach from the liner  920 . The running/drilling tool is adapted to transmit axial and torsional forces from the drill pipe  910  to the liner  920 . The running tool may be released from the liner  920  so that the BHA may be retrieved. Preferably, the running tool has torque capability that equals or exceeds the drill pipe capability and is adapted to endure typical bore hole drilling dynamics. Exemplary running tools are disclosed in U.S. Pat. Nos. 5,613,567, 5,531,273, and 6,032,734, which patents are incorporated herein by reference in their entirety. The liner top equipment (liner hanger and PBR) may also include large radial clearance for cuttings bypass and reduced ECD and setting of liner hanger does not reduce the annular clearance area significantly. In one embodiment, setting of the liner hanger and release of drilling tool may be independent of the differential pressure between the inside of the tool and the outside of the liner to prevent premature activation. In another embodiment, the liner top assembly is not equipped with a packer. In yet another embodiment, the liner top assembly utilizes an expandable liner hanger and/or expandable packers. 
     An inner string  930  extends from the liner running/drilling tool  916  to a drilling latch  940  below. The inner string  930  may be used to convey fluid from the drill pipe  910  and/or to retrieve the BHA. Also, it should be noted that fluid may be conveyed outside of the inner string, inside of the inner string, or the flow split between both. In one embodiment, the fluid returning to the surface may flow through the annular area between the wellbore and the outer diameter of the liner and/or the annular area between the inner diameter of the liner and the outer diameter of the inner string. The drilling latch  940  is adapted to releasably connect to the liner  920 . An exemplary drilling latch is disclosed in U.S. Patent Application Publication No. 2004-0216892, filed on Mar. 5, 2004 by Giroux et al. having Ser. No. 10/795,214, entitled Drilling With Casing Latch, which application is herein incorporated by reference in its entirety. The drilling latch  940  is adapted to transfer axial and torsional forces from the liner  920  to the bottom hole assembly (“BHA”). The drilling latch  940  may be hydraulically, mechanically, or remotely actuated. Suitable actuating mechanism includes mud pulse technology, wire line, and fiber optics. 
     As shown in  FIG. 9 , the bottom hole assembly includes one or more stabilizers  955 , a motor  960 , an under-reamer  965 , MWD/LWD  970 , rotary steerable systems  975 , and a drill bit  980 . It must be noted that the BHA may include other components, in addition to or in place of the listed items, such as other geophysical measurement sensors, stabilizers such as eccentric or adjustable stabilizers, steerable systems such as bent motor housing, other drill bits such as expandable bit or bits having nozzles or jetting orifices for directional drilling, or any other suitable component as is known to a person of ordinary skill in the art. Further, the components of the BHA may be arranged in any suitable order as is known to a person of ordinary skill in the art. For example, the under-reamer may be place below the motor and MWD/LWD tool. 
     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.