Patent Publication Number: US-9416599-B2

Title: Rotating continuous flow sub

Description:
BACKGROUND OF THE INVENTION 
     1. Field of the Invention 
     The present invention relates to a rotating continuous flow sub. 
     2. Description of the Related Art 
     In many drilling operations in drilling in the earth to recover hydrocarbons, a drill string made by assembling pieces or joints of drill tubulars or pipe with threaded connections and having a drill bit at the bottom is rotated to move the drill bit. Typically drilling fluid, such as oil or water based mud, is circulated to and through the drill bit to lubricate and cool the bit and to facilitate the removal of cuttings from the wellbore that is being formed. The drilling fluid and cuttings returns to the surface via an annulus formed between the drill string and the wellbore. At the surface, the cuttings are removed from the drilling fluid and the drilling fluid is recycled. 
     As the drill bit penetrates into the earth and the wellbore is lengthened, more joints of drill pipe are added to the drill string. This involves stopping the drilling while the tubulars are added. The process is reversed when the drill string is removed or tripped, e.g. to replace the drilling bit or to perform other wellbore operations. Interruption of drilling may mean that the circulation of the mud stops and has to be re-started when drilling resumes. This can be time consuming, can cause deleterious effects on the walls of the wellbore being drilled, and can lead to formation damage and problems in maintaining an open wellbore. Also, a particular mud weight may be chosen to provide a static head relating to the ambient pressure at the top of a drill string when it is open while tubulars are being added or removed. The weighting of the mud can be very expensive. 
     To convey drilled cuttings away from a drill bit and up and out of a wellbore being drilled, the cuttings are maintained in suspension in the drilling fluid. If the flow of fluid with cuttings suspended in it ceases, the cuttings tend to fall within the fluid. This is inhibited by using relatively viscous drilling fluid; but thicker fluids require more power to pump. Further, restarting fluid circulation following a cessation of circulation may result in the overpressuring of a formation in which the wellbore is being formed. 
       FIG. 1  is a prior art diagrammatic view of a portion of a continuous flow system.  FIG. 1A  is a sectional elevation of a portion of the union used to connect two sections of drill pipe, showing a short nipple to which is secured a valve assembly.  FIG. 1B  is a sectional view taken along the line  1 B- 1 B of  FIG. 1A . 
     A derrick  1  supports long sections of drill pipe  8  to be lowered and raised through a tackle having a lower block  2  supporting a swivel hook  3 . The upper section of the drill string includes a tube or Kelly  4 , square or hexagonal in cross section. The Kelly  4  is adapted to be lowered through a square or hexagonal hole in a rotary table  5  so, when the rotary table is rotated, the Kelly will be rotated. To the upper end of the Kelly  4  is secured a connection  6  by a swivel joint  7 . The drill pipe  8  is connected to the Kelly  4  by an assembly which includes a short nipple  10  which is secured to the upper end of the drill pipe  8 , a valve assembly  9 , and a short nipple  25  which is directly connected to the Kelly  4 . A similar short nipple  25  is connected to the lower end of each section of the drill pipe. 
     Each valve assembly  9  is provided with a valve  12 , such as a flapper, and a threaded opening  13 . The flapper  12  is hinged to rotate around the pivot  14 . The flapper  12  is biased to cover the opening  13  but may pivot to the dotted line position of  FIG. 1A  to cover opening  15  which communicates with the drill pipe or Kelly through short a nipple  25  into the screw threads  16 . The flapper  12  pivots to cover opening  15  in response to switching of circulation from hose  19  to hose  29 . The flapper  12  is provided with a screw threaded extension  28  which is adapted to project into the threaded opening  13 . A plug member  27  is adapted to be screwed on extension  28  as shown in  FIG. 1A , normally holding the valve  12  in the position covering the side opening in the valve assembly. Normally, before drilling commences, lengths of drill pipe are assembled in the vicinity of the drill hole to form “stands” of drill pipe. Each stand may include two or more joints of pipe, depending upon the height of the derrick, length of the Kelly, type of drilling, and the like. The sections of the stand are joined to one another by a threaded connection, which may include nipples  25  and  10 , screwed into each other. At the top of each stand, a valve assembly  9  is placed. It will be observed that the valve body acts as a connecting medium or union between the Kelly and the drill string. 
     Normally, oil well fluid circulation is maintained by pumping drilling fluid from the sump  11  through pipe  17  through which the pump  18  takes suction. The pump  18  discharges through a header  39  into valve controlled flexible conduit  19  which is normally connected to the member  6  at the top of the Kelly, as shown in  FIG. 1 . The mud passes down through the drill pipe assembly out through the openings in the drill bit  20 , into the wellbore  21  where it flows upwardly through the annulus and is taken out of the well casing  22  through a pipe  23  and is discharged into the sump  11 . The Kelly  4 , during drilling, is being operated by the rotary table  5 . When the drilling has progressed to such an extent that is necessary to add a new stand of drill pipe, the tackle is operated to lift the drill string so that the last section of the drill pipe and the union assembly composed of short nipple  25 , valve assembly  9 , and short nipple  10  are above the rotary table. The drill string is then supported by engaging a slips (not shown). 
     The plug  27  is unscrewed from the valve body and a hose  29 , which is controlled by a suitable valve, is screwed into the screw threaded opening  13 . While this operation takes place, the circulation is being maintained through hose  19 . When connection is made, the valve controlling hose  29  is opened and momentarily mud is being supplied through both hoses  19  and  29 . The valve controlling hose  19  is then closed and circulation takes place as before through hose  29 . The Kelly is then disconnected and a new stand is joined to the top of the valve body, connected by screw threads  16 . After the additional stand has been connected, the valve controlling hose  19  is again opened and momentarily mud is being circulated through both hoses  19  and  29 . Then the valve controlling hose  29  is closed, which permits the valve  12  to again cover opening  13 . The hose  29  is then disconnected and the plug  27  is replaced. 
     SUMMARY OF THE INVENTION 
     In one embodiment, a method for drilling a wellbore includes drilling the wellbore by advancing the tubular string longitudinally into the wellbore; stopping drilling by holding the tubular string longitudinally stationary; adding a tubular joint or stand of joints to the tubular string while injecting drilling fluid into a side port of the tubular string, rotating the tubular string, and holding the tubular string longitudinally stationary; and resuming drilling of the wellbore after adding the joint or stand. 
     In another embodiment, a method for drilling a wellbore, includes a) while injecting drilling fluid into a top of a tubular string disposed in the wellbore and having a drill bit disposed on a bottom thereof and rotating the tubular string: drilling the wellbore by advancing the tubular string longitudinally into the wellbore; and stopping drilling by holding the tubular string longitudinally stationary; b) injecting drilling fluid into a side port of the tubular string while injecting drilling fluid into the top, rotating the tubular string, and holding the tubular string longitudinally stationary; c) while injecting drilling fluid into the port, rotating the tubular string, and holding the tubular string longitudinally stationary: stopping injection of drilling fluid into the top; adding a tubular joint or stand of joints to the tubular string; and injecting drilling fluid into the top; and d) stopping injection of drilling fluid into the port while injecting drilling fluid into the top, rotating the tubular string, and holding the tubular string longitudinally stationary. 
     In another embodiment, method for drilling a wellbore, includes drilling the wellbore by rotating a tubular string using a top drive and advancing the tubular string longitudinally into the wellbore; rotationally unlocking an upper portion of the tubular string having a side port from a rest of the tubular string; adding a tubular joint or stand of joints to the upper portion while injecting drilling fluid into the side port and rotating the rest of the tubular string using a rotary table; rotationally locking the upper portion to the rest of the tubular string after adding the joint or stand; and resuming drilling of the wellbore after rotationally locking the upper portion. 
     In another embodiment, a continuous flow sub (CFS) for use with a drill string, includes a tubular housing having a central longitudinal bore therethrough and a port formed through a wall thereof and in fluid communication with the bore; a sleeve or case disposed along an outer surface of the housing, the sleeve or case having a port formed through a wall thereof; one or more bearings disposed between the housing and the sleeve/case, the bearings supporting rotation of the housing relative to the sleeve/case; one or more seals disposed between the housing and the sleeve/case and providing a sealed fluid path between the sleeve/case port and the housing port; and a closure member operable to prevent fluid flow through the fluid path. 
    
    
     
       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  is a diagrammatic view of a prior art continuous flow system.  FIG. 1A  is a sectional elevation of a portion of the union used to connect two sections of drill pipe, showing a short nipple to which is secured a valve assembly.  FIG. 1B  is a sectional view taken along the line  1 B- 1 B of  FIG. 1A . 
         FIG. 2  is a cross-sectional view of a rotating continuous flow sub (RCFS) in a top injection mode, according to one embodiment of the present invention.  FIG. 2A  is an enlargement of a portion of the RCFS. 
         FIG. 3  is a cross-sectional view of the RCFS in a side injection mode.  FIG. 3A  is an enlargement of a portion of the RCFS. 
         FIG. 4A  is an isometric-sectional view of hydraulic ports of the RCFS.  FIG. 4B  is a hydraulic diagram illustrating a clamp and a hydraulic power unit for operating the RCFS between the positions.  FIG. 4C  is a table illustrating operation of the RCFS. 
         FIGS. 5A-5I  illustrate a drilling operation using the RCFS, according to another embodiment of the present invention. 
         FIG. 6  is a cross-sectional view of a portion of an RCFS, according to another embodiment of the present invention.  FIG. 6A  is an enlargement of a plug of the RCFS.  FIG. 6B  is a cross-sectional view of a clamp for removing and installing the plug. 
         FIG. 7A  is a cross-sectional view of a bore valve for the RCFS, according to another embodiment of the present invention.  FIG. 7B  is a cross-sectional view of a portion of an RCFS, according to another embodiment of the present invention.  FIG. 7C  is a cross-sectional view of a portion of an RCFS, according to another embodiment of the present invention.  FIG. 7D  is a cross-sectional view of a portion of an RCFS, according to another embodiment of the present invention. 
         FIG. 8  is a cross-sectional view of an RCFS, according to another embodiment of the present invention.  FIG. 8A  is an isometric view of the locking swivel. 
         FIGS. 9A-9D  are cross-sectional views of wellbores being drilled with drill strings employing downhole RCFSs, according to other embodiments of the present invention.  FIG. 9E  is a cross-sectional view of a rotating control device (RCD) for use with one or more of the downhole RCFSs. 
     
    
    
     DETAILED DESCRIPTION 
       FIG. 2  is a cross-sectional view of a rotating continuous flow sub (RCFS)  100  in a top injection mode, according to one embodiment of the present invention.  FIG. 2A  is an enlargement of a portion of the RCFS  100 .  FIG. 3  is a cross-sectional view of the RCFS  100  in a side injection mode.  FIG. 3A  is an enlargement of a portion of the RCFS  100 . 
     The RCFS  100  may include a tubular housing  105   u,l , a bore valve  110 , a swivel  120 , and a side port valve  150 . The tubular housing  105   u,l , may include one or more sections, such as an upper section  105   u  and a lower  105   l  section, each section connected together, such as by fastening with a threaded connection. The tubular housing  105   u,l  may have a central longitudinal bore therethrough and one or more radial flow ports  101  formed through a wall thereof in fluid communication with the bore. The flow ports  101  may be spaced circumferentially around the housing and each of the ports may be formed as a longitudinal series of small ports to improve structural integrity. The housing  105   u,l  may also have a threaded coupling at each longitudinal end, such as box  105   b  formed in an upper longitudinal end and a threaded pin  105   p  formed on a lower longitudinal end, so that the housing may be assembled as part of the drill string. Except where otherwise specified, the RCFS  100  may be made from a metal or alloy, such as steel or stainless steel. 
     A length of the housing  105   u,l , may be equal to or less than the length of a standard joint of drill pipe  8 . Additionally, the housing  105   u,l , may be provided with one or more pup joints (not shown) in order to provide for a total assembly length equivalent to that of a standard joint of drill pipe. The pup joints may include one or more stabilizers or centralizers or the stabilizers or centralizers may be mounted on the housing. 
     Additionally, the housing  105   u,l , may further include one or more external stabilizers or centralizers (not shown). Such stabilizers or centralizers may be mounted directly on an outer surface of the housing &amp;/or proximate the housing above and/or below it (as separate housings). The stabilizers or centralizers may be of rigid construction or of yielding, flexible, or sprung construction. The stabilizers or centralizers may be constructed from any suitable material or combination of materials, such as metal or alloy, or a polymer, such as an elastomer, such as rubber. The stabilizers or centralizers may be molded or mounted in such a way that rotation of the sub about its longitudinal axis also rotates the stabilizers or centralizers. Alternatively, the stabilizers or centralizers may be mounted such that at least a portion of the stabilizers or centralizers may be able to rotate independently of the housing. 
     The bore valve  110  may include a closure member, such as a ball  110   b , and a seat (not shown). The seat may be made from a metal/alloy, ceramic/cermet, or polymer and may be connected to the housing, such as by fastening. The ball  110   b  may be disposed in a spherical recess formed in the housing and rotatable relative thereto. The ball  110   b  operable between an open position ( FIG. 2 ) and a closed position ( FIG. 3 ). The ball  110   b  may have a bore therethrough corresponding to the housing bore and aligned therewith in the open position. A wall of the ball may close the bore in the closed position. The ball may have a receiver  110   r  extending into an actuation port  102  formed radially through a wall of the housing. The receiver  110   r  may receive a stem (not shown) of an external actuator (not shown) operable to rotate the ball  110   b  between the open and the closed positions. The actuator may be manual, hydraulic, pneumatic, or electric. 
     Alternatively, the bore valve  110  may be replaced by a float valve, such as a flapper ( FIG. 7A ) or poppet valve. 
     The swivel  120  may include a sleeve  121 , one or more bearings, such as an upper bearing  122   u  and a lower bearing  122   l , and one or more seals  123   a - d . The sleeve  121  may be disposed between the upper  105   u  and lower  105   l  housing sections, thereby longitudinally coupling the sleeve to the housing. The sleeve  121  may have a radial port  121   p  formed through a wall thereof and the port may be aligned with the housing ports  101 . The bearings  122   u,l  may be disposed between respective ends of the sleeve  121  and a respective housing section  105   u,l , thereby facilitating rotation of the housing relative to the sleeve. The bearings  122   u,l  may be radial bearings, such as rolling element or hydrodynamic bearings. The seals  123   a - d  may each be a seal stack of polymer seal rings or rotating seals, such as mechanical face seals, labyrinth seals, or controlled gap seals. 
     The port valve  150  may include a closure member, such as a sleeve  151 , an actuator, and one or more seals  154   a - d . The valve sleeve  151  may be disposed in an annulus radially formed between the swivel sleeve  121  and the lower housing section  105   l . The valve sleeve  151  may be free to rotate relative to both the swivel sleeve  121  and the housing  105   u,l . The annulus may be longitudinally formed between a bottom of the upper housing section  105   u  and a shoulder  104  of the lower housing section  105   l . The valve sleeve  151  may be longitudinally movable between an open position ( FIG. 2A ) and a closed position ( FIG. 3A ) by the actuator. In the open position, the housing ports  101  and the swivel port  121   p  may be in fluid communication via a radial fluid path. In the closed position, the valve sleeve  151  may isolate the housing ports  101  from the swivel port  121   p , thereby preventing fluid communication between the ports. The actuator may be hydraulic and include a piston  151   p , a biasing member, such as a spring  152 , one or more hydraulic ports, such as an inlet  153   i  and an outlet  153   o , one or more seals  154   a - c , a hydraulic chamber  155 , and one or more hydraulic valves  156   i,o  (see  FIGS. 4A and 4B ). Alternatively, the actuator may be electric or pneumatic. 
     The annulus may be divided into a spring chamber, the hydraulic chamber  155 , and the fluid path. The spring  152  may be disposed in the spring chamber and may be disposed against the bottom of the upper housing section  105   u  and the piston  151   p , thereby biasing the valve sleeve  151  toward the closed position. A top of the valve sleeve  151  may form the piston  151   p  and the piston may isolate the spring chamber from the hydraulic chamber. The seals  123   a ,  154   a  may be respectively disposed between the swivel sleeve  121  and the upper housing section  105   u  and between the upper housing section and the lower housing section  105   l  and may seal the top of the spring chamber. The seal  154   a  may be one or more polymer seal rings. One or more equalization ports  103  may be formed radially through a wall of the lower housing section  105   l  and may provide fluid communication between the spring chamber and the housing bore. The seal  154   b  may be disposed in an outer surface of the piston  151   p , may isolate the spring chamber from the hydraulic chamber  155 , and may be a stack of polymer seal rings. The seal  154   c  may be disposed in an inner surface of the piston  151   p , may isolate the spring chamber from the fluid path, and may be a stack of polymer seal rings. The seal  123   b  may be disposed in an inner surface of the swivel sleeve  121  and may isolate the hydraulic chamber  155  from the fluid path. The seals  123   c,d  may be respectively disposed in an inner surface of the swivel sleeve  121  and between the swivel sleeve and the lower housing section  105   l  and may seal the bottom of the annulus. 
     Additionally, the RCFS  100  may include one or more lubricant reservoirs (not shown) in fluid communication with a respective one of the bearings  122   u,l . The reservoirs may each be pressurized by a balance piston in fluid communication with the housing bore. 
       FIG. 4A  is an isometric-sectional view of the hydraulic ports  153   i,o  of the RCFS  100 . Although shown as longitudinal/radial ports in  FIGS. 2 and 3 , the hydraulic ports  153   i,o  may actually extend radially and circumferentially through the wall of the swivel sleeve  121 . One of the hydraulic valves  156   i,o  may be disposed in a respective hydraulic port  153   i,o . The hydraulic valves  156   i,o  are shown externally of the ports in  FIG. 4B  for the sake of clarity only. The inlet hydraulic valve  156   i  may be a check valve operable to allow hydraulic fluid flow from a hydraulic power unit (HPU)  170  to the chamber  155  and prevent reverse flow from the chamber to the HPU. The check valve  156   i  may include a spring having substantial stiffness so as to prevent return fluid from entering the chamber should an annulus pressure spike occur while the RCFS  100  is in the wellbore  21 . The outlet hydraulic valve  156   o  may be a pressure relief valve operable to allow hydraulic fluid flow from the chamber to the HPU when pressure in the chamber exceeds pressure in the HPU by a predetermined differential pressure. 
       FIG. 4B  is a hydraulic diagram illustrating a clamp  160  and the HPU  170  for operating the RCFS  100  between the positions. The clamp  160  may include a body  161 , one or more bands  162  pivoted to the body, such as by a hinge (not shown, see  315  in  FIG. 6B ), and a latch (not shown, see  320   p ,  322   p  in  FIG. 6B ) to operable to fasten the bands to the body. The clamp  160  may be movable between an opened position (not shown) for receiving the RCFS  100  and a closed position for surrounding an outer surface of the swivel sleeve  121 . The clamp  160  may further include a tensionser (not shown, see  FIG. 6B ) operable to tightly engage the clamp with the swivel sleeve  121  after the latch has been fastened. The body  161  may have a circulation port  161   p  formed therethrough and hydraulic ports  161   i,o  formed therethrough corresponding to each of the swivel sleeve ports  153   i,o . The body  161  may further have a profile (not shown) for connection of the hose  29 . The body  161  may further have one or more seals  163   i,o,p  disposed in an inner surface thereof corresponding to each of the body ports  161   i,o,p . When engaged with swivel sleeve  121 , the seals  163   i,o,p  may provide sealed fluid communication between the body ports  161   i,o ,p and respective swivel sleeve ports  153   i,o ,  121   p . Each of the body  161  and the swivel sleeve  121  may further include mating locator profiles (see dowel  329  in  FIG. 6B ) for alignment of the clamp body with the swivel sleeve. 
     Alternatively, the bands  162  and latch may be replaced by automated (i.e., hydraulic) jaws. Such jaws are discussed and illustrated in U.S. Pat. App. Pub. No. 2004/0003490, which is herein incorporated by reference in its entirety. 
     Additionally, the clamp  160  may be deployed using a beam assembly, discussed and illustrated in the &#39;607 provisional application at FIG. 4A and the accompanying discussion therewith. The beam assembly may include a one or more fasteners, such as bolts, a beam, such as an I-beam, a fastener, such as a plate, and a counterweight. The counterweight may be clamped to a first end of the beam using the plate and the bolts. A hole may be formed in the second end of the beam for connecting a cable (not shown) which may include a hook for engaging the hoist ring. One or more holes (not shown) may be formed through a top of the beam at the center for connecting a sling which may be supported from the derrick  1  by a cable. Using the beam assembly, the clamp  160  may be suspended from the derrick  1  and swung into place adjacent the RCFS  100  when needed for adding joints or stands to the drill string and swung into a storage position during drilling. 
     Alternatively, the clamp  160  may be deployed using a telescoping arm, discussed and illustrated in the &#39;607 provisional application at FIGS. 4B-4D and the accompanying discussion therewith. The telescoping arm may include a piston and cylinder assembly (PCA) and a mounting assembly. The PCA may include a two stage hydraulic piston and cylinder which is mounted internally of a telescopic structure which may include an outer barrel, an intermediate barrel and an inner barrel. The inner barrel may be slidably mounted in the intermediate barrel which is, may be in turn, slidably mounted in the outer barrel. The mounting assembly may include a bearer which may be secured to a beam by two bolt and plate assemblies. The bearer may include two ears which accommodate trunnions which may project from either side of a carriage. In operation, the clamp  160  may be moved towards and away from the RCFS  100  by extending and retracting the hydraulic piston and cylinder. 
     The HPU  170  may include a pump  172 , one or more control valves  171   a - c , a reservoir  173  having hydraulic fluid  174 , and hydraulic conduits  175   i,o  connecting the pump, reservoir, and control valves to respective hydraulic ports of the clamp body. The control valves  171   a - c  may each be directional valves having an electric, hydraulic, or pneumatic actuator in communication with a programmable logic controller (PLC, see  FIG. 5A )  180 . Each control valve  171   a - c  may be operable between an open and a closed position and may fail to the closed position. In the open position, each control valve  171   a - c  may provide fluid communication between one or more of the RCFS hydraulic valves  156   i,o  and one or more of the pump  172  and reservoir  173 . 
       FIG. 4C  is a table illustrating operation of the RCFS  100 . In operation, when a joint or stand needs to be added to the drill string, the clamp  160  may be closed around the swivel sleeve  121  and tightened to engage the swivel sleeve. The PLC  180  may then open control valve  171   a , thereby providing fluid communication between the HPU pump  172  and the inlet valve  156   i  and between the HPU reservoir  173  and the outlet valve  1560 . The pump  172  may then inject hydraulic fluid  174  into the chamber  155 . Once pressure in the chamber  155  exceeds the differential pressure, fluid  174  may exit the chamber  155  through the outlet valve  156   o  to the HPU reservoir  173 , thereby displacing any air from the chamber. Once the RCFS chamber  155  has been bled, the PLC  180  may close the control valve  171   a  and then open the control valve  171   b , thereby providing fluid communication between the HPU pump  172  and the inlet valve  156   i  and preventing fluid communication between the HPU reservoir and the outlet valve  1560 . The pump  172  may then inject hydraulic fluid  174  into the chamber. 
     Once pressure in the chamber  155  exerts a fluid force on a lower face of the piston  151   p  sufficient to overcome a fluid force exerted on an upper face of the piston exerted by the drilling fluid and the force exerted by the spring  152 , the port sleeve  151  may move upward to the open position ( FIG. 3A ). Drilling fluid may then be injected into the RCFS ports  101  and the joint/stand added to the drill string. Once the joint/stand has been added, the PLC  180  may close the control valve  171   b  and then open the control valve  171   c , thereby providing fluid communication between the hydraulic valves  156   i,o  and the HPU reservoir  173 . The forces exerted on the upper face of the piston  151   p  may pressurize the fluid in the hydraulic chamber  155  until the hydraulic fluid  174  exceeds the differential pressure. The hydraulic fluid  174  may then exit the chamber  155  through the outlet valve  156   o  and to the reservoir  173 , thereby allowing the valve sleeve  151  to close. Once the valve sleeve  151  has closed, the PLC  180  may close the control valve  171   c  and the clamp  160  may be removed. The differential pressure may be set to be equal to or substantially equal to the drilling fluid pressure so that the pressure in the hydraulic chamber remains equal to or slightly greater than the drilling fluid pressure, thereby ensuring that drilling fluid does not leak into the hydraulic chamber  155 . 
       FIGS. 5A-5I  illustrate a drilling operation using a plurality of RCFSs  100   a,b , according to another embodiment of the present invention. 
     The drilling rig may include the derrick  1  ( FIG. 1 ), a top drive  50 , a torque sub  52 , a compensator  53 , a grapple  54 , a pipe handler  55 , an elevator (not shown), a control system, and a rotary table  70  supported from a platform  71 . The platform  71  may be located adjacent a surface of the earth over the wellbore  21  extending into the earth. Alternatively, the platform  71  may be located adjacent a surface of the sea and the wellbore  21  may be subsea. The rig may further include a traveling block  2  ( FIG. 1 ) that is suspended by wires from draw works and holds a quill or drive shaft of the top drive  50 . The top drive  50  may include a motor for rotating a drill string  60 . The top drive motor may be either electrically or hydraulically driven. Additionally or alternatively, the drill bit  20  may be rotated by a mud motor (not shown) assembled as part of the drill string proximate to the drill bit. Additionally, the top drive  50  may be coupled to a rail of the rig for preventing rotational movement of the top drive during rotation of the drill string and allowing for vertical movement of the top drive under the traveling block  2 . The grapple  54  may longitudinally and rotationally couple the drill string  60  to the quill. The grapple  54  may be a torque head. The torque head  54  may be hydraulically operated to grip or release the drill string  60 . Periodically, one or more joints of drill pipe  8  may be added to the drill string  60  to continue drilling of the wellbore  21 . 
     The rotary table  70  may include a drive motor ( FIG. 1 ), slips  73 , a bowl  72 , and a piston  74 . The slips  73  may be wedge-shaped arranged to slide along a sloped inner wall of the bowl  72 . The slips  73  may be raised and lowered by the piston  74 . When the slips  73  are in the lowered position, they may close around the outer surface of the drill string  60 . The weight of the drill string  60  and the resulting friction between the drill string  60  and the slips  73  may force the slips downward and inward, thereby tightening the grip on the drill string. When the slips  73  are in the raised position, the slips are opened and the drill string  60  is free to move longitudinally in relation to the slips. The drive motor may be operable to rotate the rotary table relative to the platform  71 . 
     The rotary table  70  may further include a stationery slip ring  75 . The stationery slip ring  75  may be positioned around the outside of the bowl  72 . The stationery slip ring  75  may include couplings to secure fluid paths between the rotary table  70  and the stationery platform  71 . These fluid paths may conduct hydraulic fluid to operate the piston  74 . The fluid paths may port to the outside of the bowl  72  and align with corresponding recesses along the inside of the slip ring  75 . Seals may prevent fluid loss between the bowl  74  and the slip ring  75 . The couplings may connect hydraulic line, such as hoses, that supply the fluid paths. The rotary table  70  may also include a rotary speed sensor. 
     The control system may include the PLC  180 , the HPU  170 , one or more pressure sensors G 1 -G 3 , a flow meter FM, and one or more control valves V 1 -V 5 . Control valves V 1 , V 2  may be shutoff valves, such as ball or butterfly, or they may be metered type, such as needle. If control valves V 1  and V 2  are metered valves, the PLC  180  may gradually open or close them, thereby minimizing pressure spikes or other deleterious transient effects. Pressure sensors G 1 -G 3  may be disposed in the header  39 , pressure sensor G 2  may be disposed downstream of control valve V 1 , and pressure sensor G 3  may be disposed downstream of control valve V 2 . The flow meter FM may be disposed in communication with an outlet of the mud pump  18 . The pressure sensors G 1 -G 3  and flow meter FM may be in data communication with the PLC  180 . The PLC  180  may also be in communication with actuators of the control valves V 1 -V 5 , the draw works, the top drive motor, the torque sub  52 , the compensator  53 , the grapple  54 , the pipe handler  55 , the HPU  170 , and the rotary table  70  to control operation thereof. The PLC  180  may be microprocessor based and include an analog and/or digital user interface. The PLC  180  may further include an additional HPU (not shown) or the HPU  170  may instead be connected to the rig components for operation thereof (except the top drive motor and the draw works may have their own power units and the PLC may interface with those power units). The PLC  180  may further be in communication with the mud pump for control thereof. Alternatively, the rig components may be pneumatically or electrically actuated. 
     The torque sub  52  is discussed and illustrated in the &#39;607 provisional application at FIG. 15A and the accompanying discussion therewith. The torque sub may include a torque shaft having one or more strain gages disposed thereon and oriented to measure torsional deflection of the torque shaft. The torque sub may further include a wireless power coupling and/or a wireless data transmitter/transceiver. The torque sub may further include a turns counter. 
     A suitable pipe handler  55  is discussed and illustrated in U.S. Pat. Pub. No. 2004/0003490, which is herein incorporated by reference in its entirety. The pipe handler  55  may include a base at one end for coupling to the derrick, a telescoping arm for radially moving a head about the base, and the head having jaws for gripping the drill string. 
     Alternatively, the top drive  50  may be connected to the drill string  60  with a threaded connection directly to the quill or via a thread saver instead of using the grapple  54  and the top drive  50  may include a back-up tong to makeup or breakout the threaded connection with the drill string  60 . Alternatively, the pipe handler  55  may be omitted. 
     Referring specifically to  FIG. 5A , the top drive  50  may rotate  80   t  the drill string  60  having the drill bit  20  at an end thereof while drilling fluid ( FIG. 1 ), such as mud, is injected through the drill string  60  and bit  20  and while the top drive  50  and drill string  60  are being advanced  85  longitudinally into the wellbore  21 , thereby drilling the wellbore. The mud pump  18  may inject drilling fluid into a top of the drill string  60  via header  39 , hose  19 , swivel  51 , and the top drive quill. The valves V 1 , V 3 , and  110  may be open. 
     Referring specifically to  FIG. 5B , once it is necessary to extend the drill string  60 , drilling may be stopped by stopping advancement  85  and rotation  80   t  of the top drive  50 . The slips  73  may then be lowered to engage the drill string  60 , thereby longitudinally supporting the drill string  60  from the platform  71 . The clamp  160  may be transported to the RCFS  100 , closed, and engaged by the rig crew. The driller may maintain or substantially maintain the current mud pump flow rate or change the mud pump flow rate. The change may be an increase or decrease. The PLC  180  may then close valve V 3  and apply pressure to the clamp circulation port  161   p  by opening valve V 2  and then closing valve V 2 . If the clamp  160  is not securely engaged, drilling fluid will leak past the seal  163   p . The PLC  180  may verify sealing integrity by monitoring pressure sensor G 3 . The PLC  180  may then relieve pressure by opening valve V 3 . The PLC  180  may then close valve V 3 . 
     Referring specifically to  FIG. 5C , the PLC  180  may then operate the HPU  170  to open the valve sleeve  151 , as discussed above. Once the valve sleeve  151  is open, the PLC  180  may verify opening by monitoring pressure sensor G 3 . The PLC  180  may then open valve V 2  to inject the drilling fluid through the RCFS side ports  101  and into the drill string bore. Drilling fluid may be flowing into the drill string through both the side ports  101  and the top. 
     Referring specifically to  FIG. 5D , the PLC  180  may then close valve V 1 . The rig crew may then close the bore valve  110 . The PLC  180  may then open valve V 4 , thereby relieving pressure from the top drive  50 . The PLC may verify that the bore valve  110  is closed by monitoring pressure sensor G 2 . The table drive motor may then be operated to rotate  80   r  the bowl  72  and drill string  60 . The table drive motor may rotate the drill string  60  at an angular speed equal to, less than, or substantially less than an angular speed that the top drive  50  rotated the drill string  60  during drilling, such as less than or equal to three-quarters, two-thirds, or one-half the drilling angular speed. The torque head  54  may then be operated to release the drill string  60  and the top drive  50  may be moved upward away from the drill string  60 . 
     Alternatively, if the threaded connection with the quill is used instead of the torque head  54 , the top drive  50  may hold the quill rotationally stationary while the rotary table  70  rotates the drill string  60 , thereby breaking out the connection between the quill and the drill string. The compensator  53  may be operated to account for longitudinal movement of the connection. 
     Referring specifically to  FIG. 5E , the top drive  50  may then engage the stand  62  from a stack or the V-door with the aid of the elevator and the pipe handler  55 . The stand  62  may be preassembled and include an RCFS  100   b  connected to one or more joints of drill pipe  8  by a threaded connection. Engagement of the stand  62  by the top drive  50  may include grasping the stand using the torque head  54 . The top drive  50  may then move the stand  62  into position above the drill string  60 . The top drive  50  and/or pipe handler  55  may then rotate  80   t  the stand  62  at an angular speed corresponding to the drill string  60  being rotated by the rotary table. 
     Alternatively, only an RCFS without drill pipe joints may be added to the drill string  60 . 
     Referring specifically to  FIG. 5F , a pin of the stand  62  may then be engaged with the box  105   b  of the RCFS housing  105   u . The rotational speed of the top drive/pipe handler  50 , 55  may be increased relative to the drill string  60 , thereby making up the threaded connection between the stand  60  and the RCFS  100 . If the pipe handler  55  is equipped with a spinner, the pipe handler  55  may make up a first portion of the connection and the top drive  50  may make up a second portion of the connection. The compensator  53  may be operated to account for vertical movement of the threaded connection. The torque sub  52  may measure torque and rotation of the stand relative to the drill string as the connection is made up. The pipe handler  55  may also compensate for longitudinal movement during makeup. 
     Alternatively, the stand pin may be engaged with the box thread before rotation of the stand by the top drive. 
     Referring specifically to  FIG. 5G , once the threaded connection between the stand  62  and the drill string  60  is made up, rotation of the drill string  60 , 62  may be stopped. The bore valve  110  may be opened by the rig crew. The PLC  180  may then close valve V 4 . The PLC may open the valve V 1 , thereby allowing drilling fluid flow from the mud pump  18 , through the hose  19 , and into a top of the drill string  60 , 62 . The PLC  180  may verify opening of the valve V 1  by monitoring the pressure sensor G 2 . 
     Referring specifically to  FIG. 5H , the PLC  180  may then close valve V 2  and operate the HPU  170  to close the valve sleeve  151 , as discussed above. The PLC  180  may confirm closure of the valve sleeve  151  by opening valve V 3  to relieve pressure, closing valve V 3 , and monitoring pressure sensor G 3 . The PLC  180  may then open the valve V 3 . The rig crew may then disengage the clamp  160 , open the clamp, and transport the clamp away from the RCFS  100 . 
     Referring specifically to  FIG. 5I , the PLC  180  may then disengage the slips  73 , return the mud pump flow rate (if it was changed from the drilling flow rate), rotate  80   t  the drill string  60  at the drilling angular speed, and advance  85  the drill string  60 , 62  into the wellbore  21 , thereby resuming drilling of the wellbore. 
     If, at any time, a dangerous situation should occur, an emergency stop button (not shown) may be pressed, thereby opening the vent valves V 3 -V 5  and closing the supply valves V 1  and V 2 , (some of the valves may already be in those positions). 
     Advantageously, rotation of the drill string  60  while making up the connection may reduce likelihood of differential sticking of the drill string to the wellbore. 
     A similar process may be employed if/when the drill string  60  needs to be tripped, such as for replacement of the drill bit  20  and/or to complete the wellbore. The steps may be reversed in order to disassemble the drill string. Alternatively, the method may be utilized for running casing or liner to reinforce and/or drill the wellbore, or for assembling work strings to place wellbore components in the wellbore. Alternatively, a power tong may be used to make up the connection between the stand and the drill string instead of the top drive and/or pipe handler. Additionally, a backup tong may be used with the power tong. 
       FIG. 6  illustrates a portion of an RCFS  200 , according to another embodiment of the present invention. The RCFS  200  may include a tubular housing  205   u,l , a bore valve (not shown, see  110 ), a swivel  220 , and a plug  250 . The housing  205   u,l , may be similar to the housing  105   u,l  and include the pin  205   p  and the ports  201 . The swivel  220  may include a case  221 , one or more bearings, such as an upper bearing  222   u  and a lower bearing  222   l , and one or more seals  223   u,l . The seals  223   u,l  and bearings  222   u,l  may be similar to the seals  123   a - c  and bearings  122   u,l , respectively. 
     The case  221  may be disposed between the upper  205   u  and lower  205   l  housing sections, thereby longitudinally coupling the case to the housing. The case  221  may have a radial port  221   p  formed through a wall thereof and the radial port  221   p  may be aligned with the housing ports  201 . The case  221  may also have one or more longitudinal passages  221   l  formed through a wall thereof. The bearings  222   u,l  may be disposed between respective ends of the case  221  and a respective housing section, thereby facilitating rotation of the housing  205   u,l  relative to the case. The case  221  may an outer diameter greater or substantially greater than that of the housing  205   u,l . The case  221  may serve as a centralizer or stabilizer during drilling and may be made from a wear and erosion resistant material, such as a high strength steel or cermet. In order to maintain a tubular seal face  221   f  for engagement with a clamp  300 , the longitudinal passages  221   l  may serve to conduct returns therethrough during drilling so that the enlarged case does not obstruct the flow of returns. The case  221  may further have an alignment profile  221   a  for engagement with the clamp  300 . 
       FIG. 6A  is an enlargement of the plug  250  of the RCFS  200 . The plug  250  may have a curvature corresponding to a curvature of the case  221 . The plug  250  may include a body  251 , a latch  252 ,  256 , one or more seals, such as o-rings  253 , a retainer, such as a snap ring  254 , and a spring, such as a disc  255  or coil spring. The latch may include a locking sleeve  252  and one or more balls  256 . The body  251  may be an annular member having an outer wall, an inner wall, an end wall, and an opening defined by the walls. The outer wall may taper from an enlarged diameter to a reduced diameter. The outer wall may form an outer shoulder  251   os  and an inner shoulder  251   is  at the taper. The outer wall may have a radial port therethrough for each ball  256 . The outer shoulder  251   os  may seat on a corresponding shoulder  221   s  formed in the case port  221   p . The balls  256  may seat in a corresponding groove  201   g  formed in the wall defining the housing port  201 , thereby fastening the body to the case  221 . The case port  221   p  may further include a taper  221   r . The plug  250  may be shielded from contacting the wellbore by the taper  221   r , thereby reducing risk of becoming damaged and compromising sealing integrity. One or more seals, such as o-rings  253 , may seal an interface between the plug body  251  and the case  221 . 
     The locking sleeve  252  may be disposed in the body  251  between the inner and outer walls and may be longitudinally movable relative thereto. The locking sleeve  252  may be retained in the body by a fastener, such as snap ring  254 . The disc spring  255  may be disposed between the locking sleeve and the body and may bias the locking sleeve toward the snap ring. An outer surface of the locking sleeve  252  may taper to form a recess  252   r , an enlarged outer diameter  252   od , and a shoulder  252   os . One or more protrusions may be formed on the outer shoulder  252   os  to prevent a vacuum from forming when the outer shoulder seats on the body inner shoulder  251   is . An inner surface of the locking sleeve may taper to form an inclined shoulder  252   is  and a latch profile  252   p.    
       FIG. 6B  is a cross-sectional view of the clamp  300  for removing and installing the plug  250 . The clamp  300  may include a hydraulic actuator, such as a retrieval piston  301  and a retaining piston  302 ; an end cap  303 , a chamber housing  304 , a piston rod  305 , a fastener, such as a snap ring  306 ; one or more seals, such as o-rings  306 - 311 ,  334 ,  336 ,  339 ; one or more fasteners, such as set screws  312 ,  313 ; one or more fasteners, such as nuts  314  and cap screws  315 ; one or more fasteners, such as cap screws  316 ; one or more fasteners, such as a tubular nut  317 ; one or more clamp bands  318 , 319 ; a clamp body  320 ; a clamp handle  321 ; a clamp latch  322 ; one or more handles, such as a clamp latching handle  323  and a clamp unlatching handle  325 ; one or more springs, such as torsion spring  324  and coil spring  331 ; a rod sleeve  326 ; a flow nipple  327 ; a hoist ring  328 ; a locator, such as dowel  329 ; a plug  330 ; a tension adjuster, such as bolt  332   a  and stopper  332   b ; one or more seals, such as rings  333 ; a latch, such as collet  335 ; one or more hydraulic ports  337 ,  338 , and a fastener, such as nut  340 . Alternatively, the clamp actuator may be pneumatic or electric. A more detailed discussion of the clamp components and operation thereof may be found in the &#39;607 provisional at FIGS. 3, 3A, and 5A-E and the accompanying discussion therewith. Any of the deployment options and alternatives discussed above for the clamp  160  also apply to the clamp  300 . 
     In operation, the RCFS  200  and the clamp  300  may be used in the drilling method, discussed above, instead of the RCFS  100  and the clamp  160 . The HPU  170  may be modified (not shown) to operate the clamp  300 . 
       FIG. 7A  is a cross-sectional view of a portion of an RCFS  400 , according to another embodiment of the present invention. The RCFS  400  may be similar to either of the RCFSs  100 ,  200  except for the substitution of a bore float valve  410  for the bore ball valve  110  and accompanying modifications to the RCFS housing  105   u  (now  405   u ). The float valve  410  may include a closure member, such as a flapper  410   f , a body  411 , and a locking sleeve  412 . The body  411  may be disposed in a recess formed in the upper housing section  405   u . The float valve  410  may be longitudinally coupled to the housing  705  by disposal between shoulders  406   u,l  formed in the upper housing section. Alternatively, the upper shoulder  406   u  may be omitted and the float valve  410  may be inserted into the upper housing section  405   u  via the box  405   b  and fastened to the housing  405   u , such as by a threaded connection and a snap ring. 
     The locking sleeve  412  may have a shoulder  412   s  formed in an inner surface thereof and a fastener, such as a snap ring  412   f , disposed in an outer surface thereof. The locking sleeve  412  may be movable between an unlocked position (shown) and a locked position. The locking sleeve  412  may be fastened to the body  411  in the upper position by one or more frangible fasteners, such as shear screws  411   f . A seal  411   s  may be disposed along an outer surface of the body  411 . The flapper  410   f  may be pivoted  410   p  to the body  411  and movable between an open position and a closed position (shown). The flapper  410   f  may be biased toward the closed position by a biasing member, such as a torsion spring (not shown). The flapper  410   f  may be movable to an open position in response to fluid pressure above the flapper exceeding fluid pressure below the flapper (plus resistance by the torsion spring). 
     If a thru-tubing operation needs to be conducted through the drill string  60 , such as to remediate a well control situation, a shifting tool (not shown) may be deployed using a deployment string, such as wireline, slickline, or coiled tubing. The shifting tool may include a plug having a shoulder corresponding to the locking sleeve shoulder  412   s  and a shaft extending from the plug. The shaft may push the flapper  410   f  at least partially open as the plug seats against the locking sleeve shoulder  412   s  and, thereby equalizing pressure across the flapper. Weight of the plug may then be applied to the shoulder  410   s  by relaxing the deployment string or fluid pressure may be exerted on the plug from the surface or through the deployment string. 
     The shear screws  411   f  may then fracture allowing the locking sleeve  412  to be moved longitudinally relative to the body  411  until the snap ring  412   f  engages a groove  411   g  formed in an inner surface of the body. The locking sleeve  412  may engage and open the flapper  410   f  as the locking sleeve is being moved. The snap ring  412   f  may engage the groove  411   g , thereby fastening the locking sleeve  412  in the locked position with the flapper  410   f  held open. The operation may be repeated for every RCFS  400  disposed along the drill string  60 . In this manner, every RCFS  400  in the drill string  60  may be locked open in one trip. Remedial well control operations may then be conducted through the drill string in the same trip or retrieving the deployment string to surface and changing tools for a second deployment. 
     In operation, the RCFS  400  may be used in the drilling method, discussed above, instead of the RCFSs  100 ,  200 . Since the float valve  410  may respond automatically, the steps of manually opening and closing the bore valve  110  are obviated. In a further alternative, the rotation stoppages of the drill string at  FIGS. 5B, 5C, 5G, and 5H  may be omitted by connecting the clamp  160  before engaging the slips  73  of the rotary table  70  (for  5 B and  5 C) and by disengaging the slips before removing the clamp (for  5 G and  5 H). Rotation of the drill string  60  may then be continuously maintained while adding the stand  62  to the drill string. 
       FIG. 7B  is a cross-sectional view of a portion of an RCFS  425 , according to another embodiment of the present invention. The RCFS  425  may include one or more tubular housing sections  430   l  (upper housing section not shown, see  105   u ,  405   u ), a bore valve (not shown, see  110 ,  410 ), and a port valve. The lower housing section  430   l  may have one or more radial ports  426  formed through a wall thereof. The radial ports  426  may be circumferentially spaced around the lower housing section  430   l . The RCFS  425  may be used with a modified clamp  440  equipped with a swivel, such as rotary sleeve  445  or rollers (not shown), allowing the housing  430   l  to rotate relative to the clamp. The port valve may include a sleeve  435  and a biasing member, such as a spring  438 . The sleeve  435  may be disposed in a recess formed in the lower housing section  430   l . The sleeve  435  may have a piston shoulder  435   s  having a seal  436  for engaging an inner surface of the lower housing section  430   l . The sleeve  435  may be longitudinally movable relative to the housing  430   l  between an open position and a closed position. The spring  438  may bias the sleeve  435  toward the closed position where the sleeve isolates the housing ports  426  from the housing bore. The clamp  440  may engage the housing  430   l . When pressure is exerted on a flow passage  441  through the clamp  440 , the pressure may act on the piston shoulder  435   s  of the sleeve  435 , thereby pushing the sleeve longitudinally from the closed position to the open position and allowing side circulation. When circulation through the side ports  426  is halted, the spring  438  may return the sleeve  435  to the closed position. The RCFS  425  may further include upper  431  and lower  432  seals for further isolating the ports  426  from the bore. Alignment of the clamp port  441  with the housing port  426  is not required for fluid communication of the ports. 
       FIG. 7C  is a cross-sectional view of a portion of an RCFS  450 , according to another embodiment of the present invention. The RCFS  450  may include a tubular housing  455   l  (upper housing section not shown, see  105   u ,  405   u ), a bore valve (not shown, see  110 ,  410 ), a swivel  460 , and a plug  250 . The lower housing section  455   l  may have a port  451  formed through a wall thereof in communication with the bore. The swivel  460  may include a sleeve  461 , one or more bearings  462 , and one or more seals  463 . The clamp  300  may engage the rotary sleeve  461  while the housing  455   l  may rotate relative to the sleeve  461  and the clamp  300 . To remove and install the plug  250 , rotation of the RCFS  450  may be stopped so the clamp  300  may be aligned with the port  451  to access the plug  250 . 
       FIG. 7D  is a cross-sectional view of a portion of an RCFS  475 , according to another embodiment of the present invention. The RCFS  475  may include a tubular housing  480   l  (upper housing section not shown, see  105   u ,  405   u ), a bore valve (not shown, see  110 ,  410 ), and a plug  250 . The housing  480   l  may have a side port  481  and the plug may be installed and removed from the side port. As compared to the RCFS  450 , the swivel has been omitted and the clamp  440  may be used with the RCFS  475  instead of the clamp  300 . 
       FIG. 8  is a cross-sectional view of an RCFS  500 , according to another embodiment of the present invention. The RCFS  500  may include a non-rotating CFS (NCFS)  500   a  and a locking swivel  560 . The NCFS  500   a  may be similar to the RCFS  100  except that the bearings  122   u,l  may be omitted so that the sleeve  521  does not rotate relative to the housing, the seals disposed between the housing and the sleeve  521  do not have to accommodate rotation, and a bottom of the lower housing has a threaded coupling for connecting to the locking swivel  560  instead of a pin for connecting to a pup joint/drill pipe. 
       FIG. 8A  is an isometric view of the locking swivel  560 . The locking swivel  560  may include an upper housing  561  and a lower housing  562 . The upper housing  561  may include one or more lugs  561   p  extending from an outer surface thereof. A lock ring  563  may be disposed around an outer the outer surface of the upper housing  561  so that the lock ring  563  is longitudinally moveable along the upper housing  561  between an unlocked position and a locked position. The lock ring  563  may include a key  563   k  for each lug  561   p . The lower housing  562  may include a keyway  562   w  for receiving a respective lug  561   p  and a shoulder  562   s  for engaging a respective lug  561   p  once the lug  561   p  has been inserted into the keyway  562   w  and rotated relative to the lower housing until the lug  561   p  engages the shoulder  562   s . Once each lug  561   p  has engaged the respective shoulder  562   s , the lock ring  563  may be moved into the locked position, thereby engaging each key  563   k  with a respective keyway  562   w . The upper housing  561  may include one or more holes laterally formed in an outer surface thereof, each hole corresponding to respective set of holes  563   h  formed through the lock ring  563 . Engaging the keys  563   k  with the keyways  562   w  may align the holes for receiving a respective fastener, such as pin  564 , thereby fastening the upper housing  561  to the lower housing  562 . The lower housing  562  may further include a seal mandrel  562   m  extending along an inner portion thereof. The seal mandrel  562   m  may include a seal (not shown) and a bearing (not shown) disposed along an outer surface for engaging an inner surface of the upper housing  561  to seal the interface therebetween and allow relative rotation of the lower housing  562  relative to the upper housing  561 . 
     In operation, the RCFS  500  may be used in the drilling method, discussed above, instead of the RCFS  100 . The locking swivel  560  may be unlocked during the first rotation stoppage. The rotary table  70  may then rotate the drill string  60  excluding the upper housing  561  and NCFS  500   a  which may remain rotationally stationary. The locking swivel  560  may then be locked during the second rotation stoppage. 
     Alternatively, the NCFS  500   a  may be used in a non-rotating continuous flow drilling method (without the locking swivel and having the conventional pin coupling at a bottom of the lower housing). 
       FIGS. 9A-9D  are cross-sectional views of wellbores  800 ,  810 ,  820 ,  830  being drilled with drill strings  802  employing downhole RCFSs  805 ,  825   a,b , according to other embodiments of the present invention. 
     Referring to  FIG. 9A , the wellbore  800  may have a tubular string of casing  801   c  cemented therein. A tubular liner string  801   l  may be hung from the casing  801   c  by a liner hanger  801   h . The liner hanger may include a packer for sealing the casing-liner interface. The liner  801   l  may be cemented in the wellbore  800 . A tieback casing string  801   t  may be hung from a wellhead (not shown, see  FIG. 1 ) and may extend into the wellbore  800  proximately short of the hanger  801   h  so that a flow path is defined between the distal end of the tieback string  801   t  and the liner hanger  801   h  or top of the liner  801   l . Alternatively, a parasite string may be used instead of the tieback string  801   t . A drill string  802  may extend from a top drive or Kelly located at the surface (not shown, see  FIG. 1 ). The drill string  802  may include a drill bit  803  located at a distal end thereof and a CFS  805 . 
     The RCFS  805  may include a tubular housing have a longitudinal flow bore therethrough and a radial port through a wall thereof. A float valve  805   f  may be disposed in the housing bore and may be similar to the float valve  410 . A check valve  805   c  may be disposed in the housing port. The check valve  805   c  may be operable between an open position in response to external pressure exceeding internal pressure (plus spring pressure) and a closed position in response external pressure being less than or equal to internal pressure. The check valve  805   c  may include a body, one or more seals for sealing the housing-port interface, a valve member, such as a ball, flapper, poppet, or sliding sleeve and a spring disposed between the body and the valve member for biasing the valve member toward a closed position. 
     The RCFS  805  may further include an annular seal  805   s . The annular seal  805   s  may engage an outer surface of the CFS housing and an inner surface of the tie-back string  805   t  so that an upper portion of an annulus formed there-between is isolated from a lower portion thereof. The annular seal  805   s  may be longitudinally positioned below the check valve  805   c  so that the check valve is in fluid communication with the upper annulus portion. A cross-section of the annular seal may take any suitable shape, including but not limited to rectangular or directional, such as a cup-shape. The annular seal  805   s  may be configured to engage the tie-back string only when drilling fluid is injected into the tie-back/drill string annulus, such as by using the directional configuration. The annular seal may be part of a seal assembly that allows rotation of the drill string relative thereto. 
     The seal assembly may include the annular seal, a seal mandrel, and a seal sleeve. The seal mandrel may be tubular and may be connected to the CFS housing by a threaded connection. The seal sleeve may be longitudinally coupled to the seal mandrel by one or more bearings so that the seal sleeve may rotate relative to the seal mandrel. The annular seal may be disposed along an outer surface of the seal sleeve, may be longitudinally coupled thereto, and may be in engagement therewith. An interface between the seal mandrel and seal sleeve may be sealed with one or more of a rotating seal, such as a labyrinth, mechanical face seal, or controlled gap seal. For example, a controlled gap seal may work in conjunction with mechanical face seals isolating a lubricating oil chamber containing the bearings. A balance piston may be disposed in the oil chamber to mitigate the pressure differential across the mechanical face seals. 
     Additionally, the CFS port may be configured with an external connection. The external connection may be suitable for the attachment of a hose or other such fluid line. The annular seal  805   s  may also function as a stabilizer or centralizer. 
     The CFS  805  may be assembled as part of the drill string  802  within the wellbore  800 . Once the CFS  805  is within the tie-back string  805   t , drilling fluid  804   f  may be injected from the surface into the tieback/drill string annulus. The drilling fluid  804   f  may then be diverted by the seal  805   c  through the check valve  805   c  and into the drill string bore. The drilling fluid may then exit the drill bit  803  and carry cuttings from the bottomhole, thereby becoming returns  804   r . The returns  804   r  may travel up the open wellbore/drill string annulus and through the liner/drill string annulus. The returns  804   r  may then be diverted into the casing/tie-back annulus by the annular seal  805   s . The returns  804   r  may then proceed to the surface through the casing/tie-back annulus. The returns may then flow through a variable choke valve (not shown), thereby allowing control of the pressure exerted on the annulus by the returns. 
     Inclusion of the additional tie-back/drill string annulus obviates the need to inject drilling fluid through the top drive. Thus, joints/stands may be added/removed to/from the drill string  802  while maintaining drilling fluid injection into the tie-back/drill string annulus. Further, an additional CFS  805  is not required each time a joint/stand is added to the drill string. During drilling, drilling fluid may be injected into the top drive and/or the tie-back/drill string annulus. If drilling fluid is injected into only the top drive, the drilling fluid may be diverted to the tie-back/drill string annulus when adding/removing a joint/stand to/from the drill string. The tie-back/drill string annulus may be closed at the surface while drilling. If drilling fluid is injected into only the tie-back/drill string, injection of the drilling fluid may remain constant regardless of whether drilling or adding/removing a stand/joint is occurring. 
     Referring to  FIG. 9B , the RCFS  805  may also be deployed for drilling a wellbore  810  below a surface  812   s  of the sea  812 . A tubular riser string  801   r  may connect a fixed or floating drilling rig (not shown), such as a jack-up, semi-submersible, barge, or ship, to a wellhead  811  located on the seafloor  812   f . A conductor casing string  801   cc  may extend from the wellhead  811  and may be cemented into the wellbore. A surface casing string  801   sc  may also extend from the wellhead  811  and may be cemented into the wellbore  810 . A tubular return string  801   p  may be in fluid communication with a riser/drill string annulus and extend from the wellhead  811  to the drilling rig. The riser/drill string annulus may serve a similar function to the tie-back/drill string annulus discussed above. The surface casing string/drill string annulus may serve a similar function to the liner/drill string annulus, discussed above. The returns  804   r , instead of being diverted into the casing/tie-back annulus may be instead diverted into the return string. 
     Alternatively, the riser string may be concentric, thereby obviating the need for the return string  801   p . A suitable concentric riser string is illustrated in FIGS. 3A and 3B of International Patent Application Pub. WO 2007/092956 (hereinafter &#39;956 PCT), which is herein incorporated by reference in its entirety. The concentric riser string may include riser joints assembled together. Each riser joint may include an outer tubular having a longitudinal bore therethrough and an inner tubular having a longitudinal bore therethrough. The inner tubular may be mounted within the outer tubular. An annulus may be formed between the inner and outer tubulars. 
     Referring to  FIG. 9C , the subsea wellbore  820  may be drilled using the CFS  825   a  instead of the CFS  805 . The CFS  825   a  may differ from the CFS  805  by removal of the annular seal  805   s . Instead, a rotating control device (RCD)  821  may be used to divert the drilling fluid  904   f  into the drill string and the returns  804   r  into the returns string  801   p . Instead of longitudinally moving with the drill string  802 , the RCD  821  may be longitudinally connected to the wellhead  811 . 
       FIG. 9D  illustrates the bottom of the wellbore  820  extended to a second, deeper depth relative to  FIG. 9C . Once the CFS  825   a  nears the RCD  821 , a second CFS  825   b  may be added to the drill string  802 . The second CFS  825   b  may continue the function of the CFS  825   a . Once drilling fluid  804   f  is diverted into the drill string  802 , the drilling fluid may open the float valve  805   f  in the CFS  825   a  and close the check valve  805   c  in the CFS  825   a . Since the CFS  825   a  may not include the annular seal  805   s , the CFS  825   a  may pass through the RCD  821  unobstructed. 
     In operation, any of the downhole CFSs  805 ,  825   a,b  may be used in the drilling method, discussed above, instead of the RCFS  100 . Use of the downhole CFSs may obviate the rotation stoppages of the drill string at  FIGS. 5B, 5C, 5G, and 5H . Rotation of the drill string may then be continuously maintained while adding the stand to the drill string. 
       FIG. 9E  is a cross-sectional view of one embodiment of the RCD  821 . The RCD  821  may be located and secured within a housing  864  which includes a head  860  and a body  862 . In the illustrated embodiment, the RCD  821  is removably held in place by a packing unit  868  energized by piston  866  within the housing  864 . Alternatively, the RCD may be removably secured with the housing  864  using an appropriate latch, or the RCD  821  may be permanently secured within the housing  864 . 
     The RCD  821  may further include a bearing assembly  878 . The bearing assembly  878  may be attached to at least one of a top stripper rubber  882  and a bottom stripper rubber  884 . The bearing assembly  878  allows stripper rubbers  882 ,  884  to rotate relative to the housing  864 . Each rubber  882 ,  884  may be directional and the upper rubber  882  may be oriented to seal against the drill string  802  in response to higher pressure in the riser  801   r  than the wellbore  820  and the lower rubber  884  may be oriented to seal against the drill string in response to higher pressure in the wellbore than the riser. In operation, the drill string  802  can be received through the bearing assembly  878  so that one of the rubbers  882 ,  884  may engage the drill string depending on the pressure differential. The RCD  821  may provide a desired barrier or seal in the riser  801   r  both when the drill string  802  is stationary or rotating. Alternatively, an active seal RCD may be used. 
     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.