Patent Publication Number: US-8118106-B2

Title: Flowback tool

Description:
CROSS-REFERENCE TO RELATED APPLICATIONS 
     This application claims benefit of U.S. Provisional Pat. App. No. 61/068,892, filed Mar. 11, 2008, which is hereby incorporated by reference in its entirety. 
    
    
     BACKGROUND OF THE INVENTION 
     In wellbore construction and completion operations, a wellbore is initially formed to access hydrocarbon-bearing formations (i.e., crude oil and/or natural gas) by the use of drilling. Drilling is accomplished by utilizing a drill bit that is mounted on the end of a tubular string, commonly known as a drill string. To drill within the wellbore to a predetermined depth, the drill string is often rotated by a top drive or rotary table and Kelly on a surface platform or rig, and/or by a downhole motor mounted towards the lower end of the drill string. A pumping system is used to inject drilling fluid through the top drive or Kelly, down the drill string, through the rotating drill bit, and back to the surface via an annulus formed between the borehole wall and the drill bit. As the drilling fluid exits the bit, the fluid carries cuttings from the bit and the drilling fluid and cuttings are typically referred to as returns. Typically, the drilling fluid is a mud including a base fluid, typically water or oil, and various additives suspended, dissolved, and/or emulsified in the base fluid. 
     After drilling to a predetermined depth, the drill string and drill bit are removed and another tubular string of casing (or liner) is lowered into the wellbore. An annulus is thus formed between the string of casing and the formation. The casing string is temporarily hung from the surface of the well. A cementing operation is then conducted in order to fill the annular area with cement. The casing string is cemented into the wellbore by circulating cement into the annular area defined between the outer wall of the casing and the borehole. The combination of cement and casing strengthens the wellbore and facilitates the isolation of certain areas of the formation behind the casing for the production of hydrocarbons. 
     A drilling rig is constructed on the earth&#39;s surface to facilitate the insertion and removal of tubular strings (i.e., drill strings or casing strings) into a wellbore. Alternatively, the drilling rig may be disposed on a jack-up platform, semi-submersible platform, or a drillship for drilling a subsea wellbore. The drilling rig includes a platform and power tools, such as a top drive, power tongs, and a spider, to engage, assemble, and lower the tubulars into the wellbore. 
     In order to drill and case the wellbore, it is necessary deploy tubular strings into the wellbore and may be necessary to remove tubular strings from the wellbore. Further intervention operations, such as fishing a broken or stuck tubular or tool, and workover operations also require deploying and removing tubular strings. When tubular strings are being run into or pulled from the wellbore, it is often necessary to fill the tubular string, take returns from the tubular string, or circulate fluid through the tubular string. This requires that the tubular string be threaded to the top drive (or Kelly hose) or be connected a circulation head. Previous circulation heads are firmly attached to the traveling block or top drive. In either case, precise spacing is required of the seal assembly relative to the tubular and elevators. In the case where slip-type elevators are used, the spacing of the seal could be such that when the elevators were near the upset of the tubular, the seal could be out of the tubular. When required, the slips at the rig floor must be set on the tubular and the traveling block or top drive lowered in order to move the seal into sealing engagement with the tubular. This requires that the running or pulling of the tubular stop until the slips were set at the rig floor and the seal engagement be made. This is not desirable when a well kick occurs or fluid is overflowing from the tubular. 
     In the case where “side door” or latching elevators are used, the seal must be engaged in the tubular prior to latching the elevators below the upset portion of the tubular. This requires that the seal be engaged in the tubular at all times that the elevators are latched on the tubular. When joints or stands of tubulars are racked back in the derrick, it is difficult to insert the seal into the tubular prior to latching the elevators with the top of the tubular far above the derrick man. Also, with the seal engaged in the tubular at all times, this is a disadvantage when there is a need to access the top of the tubular while the tubulars are in the elevators or when the tubular is being filled with fluid and the air in the tubular begins to be entrained in the fluid column rather than escaping the tubular. For example, if a high-pressure line was to be attached to the tubular and the tubular moved at the same time, all previous devices had to be “laid down” to allow a hard connection to be made to the tubular since they are in the way of the tubular connection. 
     Mudsaver valves are usually connected to the lower end of the top drive/Kelly or circulation head to prevent spillage of mud when the top drive/Kelly hose or circulation head are disconnected from the tubular. The use of a mudsaver valve is desirable to prevent the loss of mud, to prevent unsafe operating conditions for personnel, and to minimize contamination of the environment. 
     SUMMARY OF THE INVENTION 
     In one embodiment, a flowback tool for running a tubular string into a wellbore includes a tubular housing having a bore therethrough and a tubular mandrel. The mandrel: has a bore therethrough in communication with the housing bore, is longitudinally movable relative to the housing, is torsionally coupled to the housing, and has a threaded coupling for engaging a threaded coupling of the tubular string. The flowback tool further includes a nose: longitudinally coupled to the mandrel, operable to receive an end of the tubular string, and including a seal operable to engage a surface of the tubular string, thereby providing fluid communication between a bore of the tubular string and the mandrel bore. The flowback tool further includes an actuator operable to move the mandrel and the nose longitudinally relative to the housing for engaging and disengaging the tubular string. 
     In another embodiment, a method for running a tubular string into a wellbore includes engaging a tubular string with an elevator and operating an actuator of a flowback tool in fluid communication with a Kelly hose. Operation of the actuator: lowers a nose of the flowback tool to an end of the tubular string relative to a housing of the flowback tool, engages a seal of the nose with a surface of the tubular string, and provides fluid communication between a bore of the tubular string and the Kelly hose. The housing is longitudinally coupled to a traveling block of a drilling rig and the mandrel is torsionally coupled to the housing and has a threaded coupling for engaging a threaded coupling of the tubular string. The method further includes lowering the tubular string into the wellbore using the elevator. 
    
    
     
       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  illustrates a flowback tool assembled with a top drive, according to one embodiment of the present invention.  FIG. 1A  illustrates the flowback tool in a retracted position.  FIG. 1B  illustrates the flowback tool in an engaged position. 
         FIG. 2  is a cross section of the flowback tool in a retracted position.  FIG. 2A  is a cross section of the mudsaver valve of the flowback tool in a closed position.  FIG. 2B  is a cross section of a nose of the flowback tool in an unlocked position. 
         FIG. 3  is a cross section of the flowback tool in an engaged position.  FIG. 3A  is a cross section of a nose of the flowback tool in a locked position. 
         FIG. 4A  is a cross section of the mudsaver valve of the flowback tool in a fill or circulation position.  FIG. 4B  is a cross section of the mudsaver valve of the flowback tool in a returns position. 
         FIG. 5  is a cross section of the flowback tool in a well control position. 
         FIG. 6  illustrates a clamp connected to the flowback tool for disconnecting the flowback tool from the tubular string.  FIG. 6A  illustrates a portion of the clamp. 
     
    
    
     DETAILED DESCRIPTION 
       FIG. 1  illustrates a flowback tool  100  assembled with a top drive  1 , according to one embodiment of the present invention. The top drive  1  may include a non-rotating frame, a motor, a Kelly hose connection, a hydraulic swivel, and a backup tong. The top drive  1  may be hoisted from the drilling rig by a traveling block  5 . The frame of the top drive may receive a hook of the traveling block, thereby longitudinally coupling the frame to the traveling block  5 . The top drive motor may be electric or hydraulic. The frame may be torsionally coupled to a rail (not shown) of the rig so that the top drive  1  may longitudinally move relative to the rail. The hydraulic swivel may provide fluid communication between the non-rotating Kelly hose connection and a rotating quill of the motor for injection of drilling fluid from the rig mud pumps (not shown) through the top drive  1 . The hydraulic swivel may also connect to the traveling block  5  for transferring weight of the top drive from the rotating quill to the non-rotating traveling bock. The manifold may connect hydraulic, electrical, and/or pneumatic conduits from the rig floor to the top drive  1 . The manifold may be longitudinally and torsionally coupled to the frame. 
     An elevator  10  may be longitudinally and torsionally coupled to the top drive frame via bails  15 . The elevator  10  may include a gripper, such as slips and a cone, for grabbing and hoisting a tubular joint or stand  20 , such as drill pipe (shown) or casing. The elevator and the top drive may deliver the joint/stand  20  to a tubular string  20  where the joint/stand may be made up with the tubular string. The flowback tool  100  may be longitudinally and torsionally connected to a quill of the top drive, such as by a threaded connection. 
       FIG. 1A  illustrates the flowback tool  100  in a retracted position.  FIG. 1B  illustrates the flowback tool  100  in an engaged position. Except for seals, components of the flowback tool  100  may be made from a metal or alloy. Seals of the flowback tool  100  may be made from a polymer, such as an elastomer. The flowback tool  100  may include a cap  105 , a housing  110 , a mandrel  115 , a nose  120 , and an actuator. The mandrel  115  and the nose  120  may be longitudinally movable relative to the housing  110  between the retracted position and the engaged position by the actuator. The nose  120  may sealingly engage an outer surface of the tubular  20  in the engaged position, thereby providing fluid communication between the top drive  1  and the bore of the tubular  20 . 
     The actuator may include two or more piston and cylinder assemblies (PCAs)  125 , a first swivel  130 , and a second swivel  135 . Each PCA  125  may be longitudinally coupled to the housing  110  via the first swivel  130  and longitudinally coupled to the nose  120  via the second swivel  135 . The swivel  130  may include arms for engaging the bails  15 , thereby torsionally coupling the PCAs  125  to the bails  15 . Each of the swivels  130 ,  135  may include one or more bearings, thereby allowing relative rotation between the PCAs  125  and the housing  110 . Hydraulic conduits (not shown), such as hoses, may extend from each of the PCAs  125  to the top drive manifold or a separate hydraulic pump added to the top drive frame to provide for extension and retraction of the PCAs. As discussed below, a hydraulic conduit may also extend to the swivel  135  which may be in fluid communication with the nose  120  via port  135   p.    
       FIG. 2  is a cross section of the flowback tool  100  in a retracted position. The cap  105  may be annular and have a bore therethrough. A first longitudinal end of the cap  105  may include a threaded coupling, such as a box  105   b , for connection with a threaded coupling of the quill, such as a pin, thereby longitudinally and torsionally coupling the quill and the cap  105 . One or intermediate subs (not shown), such as a thread saver crossover, and/or well control valve, may connect between the quill and the cap. The cap  105  may taper outwardly so that a second longitudinal end may have a substantially greater diameter than the first longitudinal end. An inner surface of the second longitudinal end of the cap  105  may be threaded for receiving a threaded first longitudinal end of the housing  110 , thereby longitudinally coupling the cap and the housing. The second longitudinal end of the cap  105  and the first longitudinal end of the housing  110  may include one or more keyways formed therein. A key  111  may be disposed in each keyway, thereby torsionally coupling the housing and the cap. A retainer plate  112  may be fastened to the housing  110  or the cap  105  for retaining each of the keys  111 . 
     The housing  110  may be tubular and have a bore formed therethrough. An outer surface of the housing  110  may be grooved for receiving the bearings, such as ball bearings  131 , thereby longitudinally coupling the housing and the swivel  130 . A second longitudinal end of the housing  110  may be longitudinally splined for engaging longitudinal splines formed on an outer surface of the mandrel  115 , thereby torsionally coupling the housing  110  and the mandrel  115 . The second longitudinal end of the housing  110  may form a shoulder  110   s  for receiving a corresponding shoulder  115   s  formed at a first longitudinal end of the mandrel  115 , thereby longitudinally coupling the housing  110  and the mandrel  115 . The PCAs  125  may be capable of supporting weight of the nose  120  and the mandrel  115  and the shoulders  110   s ,  115   s , when engaged, may be capable of supporting weight of the tubular string  20 . The shoulders  110   s ,  115   s  may engage before the PCAs  125  bottom out, thereby ensuring that string weight is not transferred to the PCAs. 
     A second longitudinal end of the mandrel  115  may form a threaded coupling, such as a pin  115   p , for engaging a threaded coupling, such as a box  20   b , formed at a first longitudinal end of the tubular  20 . An outer surface of the mandrel  115  near the second longitudinal end may be threaded and form a shoulder for receiving a threaded inner surface and shoulder of the nose  120 , thereby longitudinally and torsionally coupling the nose  120  and the mandrel  115 . One or more seals, such as O-rings, may be disposed between the mandrel  115  and the nose  120 , thereby isolating a seal chamber of the nose  120  (discussed below) from an exterior of the flowback tool  100 . A substantial portion of the mandrel bore may be sized to receive a body  205  of a mudsaver valve (MSV)  200 . One or more seals, such as O-rings, may be disposed between the body  205  and the mandrel  115  (on mandrel as shown), thereby isolating the first longitudinal end of the mandrel  115  from the housing bore. Isolating the first longitudinal end of the mandrel  115  may prevent the mandrel end from acting as a piston and longitudinally exerting a downward force on the mandrel  115  and the nose  120 . 
       FIG. 2A  is a cross section of the MSV  200  of the flowback tool  100  in a closed position. The flowback tool  100  may further include the MSV  200 . The MSV  200  may include the body  205 , a seat  210 , a poppet  215 , a stem  220 , a seat spring  225 , a poppet spring  230 , a baffle  235 , and a sleeve  240 . The body  205  may be tubular and have a bore formed therethrough. A first longitudinal end of the body  205  may be received in a recess  105   r  formed in the cap  105 . The cap recess  105   r  may include a shoulder and the body  205  may abut the shoulder. The cap  105  may include one or more holes formed through a wall thereof for receiving respective fasteners, such as set screws, thereby longitudinally coupling the body  205  and the cap  105 . One or more seals, such as O-rings, may be disposed between the body  205  and the cap  105  and, along with the seal between the body  205  and the mandrel  115 , thereby isolating the body bore from the housing bore. 
     The body  205  may include a first shoulder formed second shoulder formed between the longitudinal ends thereof and a second shoulder formed at a second longitudinal end thereof. The seat spring  225  may be disposed longitudinally against the second shoulder. The seat  210  may be tubular and include a shoulder  210   s  formed at a first longitudinal end and engaging the seat spring  225 , thereby longitudinally biasing the seat toward the poppet  215 . A seal, such as an O-ring, may be disposed between the seat shoulder  210   s  and the body  205 , thereby isolating a first face of the seat shoulder  210   s  from a second face of the seat shoulder. The second face of the seat shoulder  210   s  and the spring chamber may be in fluid communication with the mandrel bore via leakage between a second longitudinal end of the seat  210  and the body  205  (no seal). 
     The baffle  235  may be annular and have a recess formed therein partially enclosed by a first longitudinal end thereof. The first longitudinal end may include a central bore and one or more eccentric flow ports formed longitudinally therethrough. The baffle bore may receive the stem  220 . A second longitudinal end of the baffle  235  may abut the body second shoulder and the seat shoulder  210   s  (in the closed position). The stem  220  may be a rod and have a conical first end for minimizing flow disruption and a threaded second end received by a threaded opening formed in the poppet  215 , thereby longitudinally coupling the stem  220  and the poppet  215 . The poppet spring  230  may be disposed along the stem  220  and abut the baffle  235  and the poppet  215 , thereby longitudinally biasing the poppet  215  toward the seat  210 . 
     The poppet  215  may have a first longitudinal flat face for receiving the stem  220  and the poppet spring  230  and a dual tapering outer surface. The first taper in the poppet outer surface may minimize flow disruption and a second taper in the poppet outer surface may mate with a taper formed in an inner surface of the seat  210 . The mating tapered surfaces may have a smooth finish for metal-to-metal sealing engagement. The poppet  215  may further have a second longitudinal flat face for receiving fluid pressure. An inner diameter of the baffle recess may be greater than a maximum outer diameter of the poppet  215  to define a flow path therebetween. The sleeve  240  may be tubular and have a bore formed therethrough. A first longitudinal end of the sleeve  240  may abut the cap shoulder and a second longitudinal end of the sleeve  240  may abut the first longitudinal end of the baffle  235 , thereby longitudinally coupling the baffle  235  and the cap  105 . 
     The sleeve  240 , baffle  235 , poppet  215 , stem  230 , and seat  210  may be hardened, such as by case hardening, or made from a hard metal or alloy, to resist erosion. A stiffness of the seat spring  210  may be selected to exert a closing force greater than or equal to an opening force exerted by hydrostatic pressure of drilling fluid contained in the top drive  1 , thereby preventing spillage of the drilling fluid when the flowback tool  100  is disengaged from the tubular  20 . A stiffness of the seat spring  210  may also be selected such that the closing force is substantially less than an opening force exerted by discharge pressure of the rig mud pump so that the seat  210  moves longitudinally away from the poppet  215  upon activation of the mud pump (due to the shoulder  210   s  acting as a piston). A stiffness of the poppet spring  230  may be selected to maintain tight sealing engagement between the poppet  215  and the seat  210  and may be less or substantially less than a stiffness of the seat spring  210 . 
       FIG. 2B  is a cross section of a nose  120  of the flowback tool  100  in an unlocked position. The nose  120  may include a body  250 , a piston  255 , one or more locks, such as dogs  260 , a seal retainer  265 , a seal  270 , a stop  275 , and a valve  180 . The body  250  may be annular and have a bore therethrough. The body  250  may include a groove  250   b  formed in an outer surface for receiving the ball bearings  131 . A port  250   p  may be formed through the wall of the housing  250  providing fluid communication between the groove  250   b  and an outer surface of the piston  255 . The body  250  may include one or more slots  250   s  formed in an inner surface for receiving respective dogs  260 . Each slot  250   s  may have an inclined face for radially moving the dogs  260  from a retracted position to an extended position as the piston  255  moves longitudinally relative to the body  250 . 
     The piston  255  may include corresponding slots formed therethrough for receiving the dogs  260 . Each piston slot may include a lip (not shown) for abutting a respective lip (not shown) formed in each dog, thereby radially retaining the dogs in the slot. Each dog  260  may include a tapered inner surface for engaging an end of the tubular  20  when the tubular is being moved longitudinally relative to the body  250  from the locked position to the well control position, thereby longitudinally moving the piston  255  and radially moving the dogs  260  from the extended position to the retracted position. The body  250  may include a groove  250   o  formed in an inner surface for receiving a seal, such as an o-ring, for engagement with the mandrel  115  (discussed above). The body  250  may include a keyway (not shown) and the outer surface of the piston  255  may have a key (not shown) formed therein (or vice versa) for ensuring and maintaining torsional alignment of the piston  255  and the body  250 . 
     The body  250  may include a vent  250   v  formed through a wall thereof and in fluid communication with a seal chamber, defined by a portion of the nose bore between the seal  270  and the mandrel seal, and the valve  180  for safely disposing of residual fluid left in the seal chamber before disengaging the tubular  20 . The vent  250   v  may be threaded for receiving a threaded coupling of the valve  180 , thereby longitudinally and torsionally coupling the valve and the body  250 . The body  250  may include a recess  250   r  formed at a second longitudinal end thereof for receiving the seal retainer  265  and the stop  275 . One or more holes may be formed through the housing wall for receiving fasteners, such as set screws, thereby longitudinally coupling the seal retainer  265  and the body  250 . The body  250  may include a profile  250   a  formed therein for receiving a corresponding profile formed in an outer surface of the piston  255 . 
     The piston  255  may be annular and have a bore formed therethrough. The piston  255  may be disposed in the body  250  and longitudinally movable relative thereto between a locked position ( FIG. 3A ) and the unlocked position. The piston may include the profile on the outer surface thereof. Upper and lower seals, such as o-rings, may be disposed between the piston  255  and the body  250  (on piston as shown) so as to straddle the port  250   p , thereby isolating a piston chamber from the remainder of the nose  120 . A shoulder may be formed as part of the piston profile, thereby providing a piston surface. The piston  255  may have a port formed therethrough in alignment with the vent  250   v  when the piston is in the locked position and partially aligned with the vent when the piston is in the unlocked position. The piston  255  may abut the stop  275  in the locked position. 
     The seal retainer  265  may be annular and may have a substantially J-shaped cross section for receiving and retaining the seal  270 . The seal  270  may include a base portion having a lip for engaging a corresponding lip of the retainer  265  and a cup portion for engaging the outer surface of the tubular  20 . An outer surface of the cup portion may be inclined for receiving fluid pressure to press the cup portion into engagement with the tubular  20 . When engaged, the cup portion may be supported by a tapered inner surface of the stop  275  and/or the piston  255 . The seal  270  may be molded into the retainer  265  or pressed therein. The stop  275  may abut a shoulder of the recess  250   r  and a first longitudinal end of the retainer  265 , thereby longitudinally coupling the stop  275  and the body  250 . 
     Alternatively, the nose  120  and seal  270  may be arranged so that the seal  270  engages an inner surface of the tubular  20 . This alternative may be accomplished simply by removing the seal retainer  265  (and seal  270 ) from the nose  120  and replacing the seal retainer  265  with an alternative seal retainer (not shown) configured to extend into the tubular string  20  with a seal configured to engage an inner surface of the tubular string  20 . The seal  270  engaging the outer surface may be more suitable when the tubular string  20  is smaller drill pipe and the seal engaging the inner surface of the tubular string  20  may be more suitable when the tubular string  20  is larger casing. 
     The nose  120  and/or the second longitudinal end of the mandrel  115  may be configured so that the nose and the mandrel are biased away (i.e., upward) from the tubular string  20  in the engaged position ( FIG. 3 ) by fluid pressure from the tubular string  20 . Alternatively, the nose  120  and/or the second longitudinal end of the mandrel  115  may be configured so that the nose and the mandrel are not biased relative to the tubular string  20  in the engaged position ( FIG. 3 ) by fluid pressure from the tubular string  20 . 
       FIG. 3  is a cross section of the flowback tool  100  in an engaged position.  FIG. 3A  is a cross section of a nose  120  in a locked position. Once a joint or stand  20  is made up with the tubular string (not shown), the tubular string  20  may be ready to be advanced into the wellbore. Hydraulic fluid from the top drive manifold/hydraulic pump may be injected into the nose  120  via the second swivel  135 , thereby locking the piston  255  or moving the piston  255  into the locked position and locking the piston  255 . Hydraulic pressure may be maintained on the piston  255  during advancement of the tubular  20  into the wellbore, thereby rigidly locking the piston  255  and the dogs  260 . Hydraulic fluid may be then injected into the PCAs  125 , thereby lowering the nose  120  and the mandrel  115  until an outer surface of the box  20   b  engages the seal  270  and then the dogs  260 . Hydraulic pressure may be maintained on the PCAs  125  during advancement of the tubular  20  into the wellbore, thereby overcoming the upward bias from fluid pressure, discussed above, and ensuring that the dogs  260  and seal  270  remain engaged to the tubular  20  during advancement of the tubular  20  into the wellbore. Engagement of the seal  270  with the box  20   b  may provide fluid communication between the tubular string  20  and the top drive  1 , thereby allowing the joint/stand  20  to be filled with drilling fluid, circulation of drilling fluid through the tubular string  20  during advancement of the joint/stand  20  into the wellbore, and/or receiving returns displaced by advancement of the joint/stand  20  into the wellbore. 
     Once the joint/stand  20  has been advanced into the wellbore, the spider (not shown) may be set. The valve  180  may be connected to a disposal line (not shown) and fluid may be bled through the vent  250   v  by opening the valve  180 . Hydraulic pressure to the PCAs may be reversed, thereby raising the nose and the mandrel to the retracted position. Hydraulic pressure may be relieved from the piston (although the piston may not return to the unlocked position). The elevator  10  may then release the joint/stand  20 . The top drive  1  may be moved proximate to another joint/stand (not shown) and the elevator  10  operated to grab the joint/stand. The joint/stand may be moved into position over the tubular string  20 , engaged with the tubular string  20 , and the elevator  10  released. The joint/stand may be made up with the tubular string and the elevator  10  may engage the tubular string  20 . The flowback tool  100  may then again be operated by repeating the cycle. Operation of the flowback tool  100  may be similar for removing the tubular string  20  from the wellbore. 
       FIG. 4A  is a cross section of the MSV  200  in a fill or circulation position. If it desired to fill the tubular before/during advancement into the wellbore or circulate fluid through the tubular string during before/during/after advancement into the wellbore, drilling fluid from the mud pump may be injected into and through the top drive  1  via the Kelly hose. The fluid may exit the quill and enter the cap  105 , flow through the cap bore, through the baffle  235 , around the poppet  215 , and to the seat shoulder  210   s . Fluid pressure exerted on the seat  210  may push the seat  210  longitudinally away from the poppet  215  and against the seat spring  225 , thereby compressing the seat spring  225  and creating a flow path. Fluid may exit the MSV  200 , flow through the mandrel bore, and into the tubular  20 . 
       FIG. 4B  is a cross section of the MSV  200  in a returns position. Returns displaced by the advancing tubular  20  may flow from the tubular string  20 , through the nose  120 , and the mandrel  115 , and to the poppet  215 . The displaced fluid may exert pressure on the second poppet face, thereby moving the poppet  215  and the stem  220  against the poppet spring  230  and toward the baffle  235  and away from the seat  210 , thereby compressing the poppet spring  230  and opening a fluid path between the poppet  215  and the seat  210 . The returns flow may continue through the top drive  1  and the Kelly hose and may be diverted to the rig returns system. 
       FIG. 5  is a cross section of the flowback tool  100  in a well control position. While the sealing capability of the seal  270  may be substantial, it may nevertheless be insufficient to handle a well control event, such as a kick or underbalance pressure situation. If/when such an event is detected, advancement of the tubular string  20  may be halted and the spider set to support the tubular string  20 . Fluid pressure may be relieved from the piston  255 . Fluid pressure may then be supplied (or maintained) to the PCAs  125  to lower the nose  120  until the mandrel shoulder  115   s  abuts the housing shoulder  110   s . As discussed above, abutment of the housing and mandrel shoulders  110   s ,  115   s  may occur before the PCAs  125  bottom out, thereby preventing the PCAs from supporting weight of the tubular string  20 . 
     Since pressure has been relieved from the piston  255 , the tubular  20  may push the piston  255  toward the unlocked position via engagement with the dogs  270 . The remaining stroke length of the mandrel/housing may be insufficient to completely move the piston  255  to the unlocked position. If so, then the elevator  10  may be disengaged and the top drive  1  lowered until the tubular  20  completely pushes the piston to the unlocked position, thereby radially pushing the dogs  260  into the recess  250   r  and engaging the box  20   b  with the mandrel pin  115   p . The top drive backup tong may engage the tubular  20  and the top drive motor may then be operated to rotate the mandrel pin  115   p  relative to the box  20   b , thereby making up the threaded connection. The seal  270  may remain engaged to the tubular  20  while shifting from the engaged position to the well control position. 
     With the substantial increase in sealing capability afforded by the threaded connection between the box  20   b  and the pin  115   p , remedial action may be taken to regain pressure control over the wellbore, such as circulation of heavy weight mud or kill fluid until the annulus of the wellbore is filled with the kill fluid or circulation of the wellbore with drilling fluid until the kick subsides. Further, if necessary, a well control valve in the top drive may be closed. Once control of the wellbore is regained, advancement of the tubular string  20  may continue. The spider may be disengaged from the tubular string. The elevator may not need to be reengaged as engagement of the housing and mandrel shoulders  110   s ,  115   s  may support the weight of the tubular string  20 . The tubular string  20  may then be advanced into the wellbore until another joint/stand needs to be added. Further, the tubular string  20  may be rotated while advanced. 
       FIG. 6  illustrates a clamp  605  connected to the flowback tool  100  for disconnecting the flowback tool  100  from the tubular string  20 .  FIG. 6A  illustrates a portion  607  of the clamp  605 . To disengage the mandrel pin  115   p  from the box  20   b  so another joint/stand may be added, the spider may be engaged with the tubular string  20 . The pistons of the PCAs  125  may be removed from the second swivel  135  and retracted into the cylinders of the PCAs  125  to allow access to the mandrel  115 . A clamp  605  may be assembled around the mandrel  115 . The clamp may include two semi-annular segments  607 . Each segment  607  may have a longitudinally splined inner surface for engaging the splined mandrel outer surface, thereby torsionally coupling the clamp to the mandrel. The segments may be retained together by retainers  609 . Each retainer  609  may include holes formed therethrough for receiving fasteners, such as screws. Each segment  607  may include corresponding holes for receiving the fasteners. Each segment  607  may include a handle  610  to facilitate carrying. Each segment  607  may have a smooth outer surface for receiving jaws of the drive tong (not shown). The clamp  605  may be set on the first longitudinal end of the nose  120 . A backup tong may be engaged with the tubular string  20  and a drive tong may be engaged with an outer surface of the clamp  605 . The drive tong may be operated to break out the mandrel pin  215   p  from the box  20   b . Use of the clamp  605  instead of the top drive  1  to break out the connection  115   p ,  20   b  may ensure that the connection between the cap  105  and the quill is not unintentionally loosened or broken out. Once the connection  115   p ,  20   b  is broken, normal operation of the flowback tool  100  may resume. 
     In another embodiment, discussed and illustrated in  FIGS. 1-11  of the &#39;892 provisional (incorporated above), an annular piston may be used instead of the PCAs to actuate the flowback tool and the flowback tool may further include a well control valve. 
     In another embodiment, discussed and illustrated in  FIGS. 12-13  of the &#39;892 provisional, an alternate well control valve is used. 
     In another embodiment, discussed and illustrated in  FIGS. 14-18  of the &#39;892 provisional, the nose may be longitudinally moved by rotating the top drive instead of using the PCAs and the mandrel may be moved by disengaging the elevator and lowering the top drive. 
     In another embodiment, discussed and illustrated in  FIGS. 19-20  of the &#39;892 provisional, the nose and the mandrel may be longitudinally moved by rotating the top drive instead of using the PCAs. 
     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.