Abstract:
A method for cementing a tubular string into a wellbore includes: running the tubular string into the wellbore using a workstring having a deployment assembly; delivering an opener activator through the workstring to the deployment assembly, thereby launching an opener plug from the deployment assembly; pumping the opener activator and plug to a stage valve of the tubular string, thereby opening the stage valve; pumping cement slurry into the workstring; pumping a closer activator through the workstring behind the cement slurry, thereby launching a closer plug from the deployment assembly; and pumping the closer activator and plug to the open stage valve, thereby driving the cement slurry into an annulus between the tubular string and the wellbore and closing the stage valve.

Description:
BACKGROUND OF THE DISCLOSURE 
       [0001]    1. Field of the Disclosure 
         [0002]    The present disclosure generally relates to a surge immune stage system for wellbore tubular cementation. 
         [0003]    2. Description of the Related Art 
         [0004]    A wellbore is formed to access hydrocarbon bearing formations, such as 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 drill string. To drill within the wellbore to a predetermined depth, the drill string is often rotated by a top drive or rotary table on a surface platform or rig, and/or by a downhole motor mounted towards the lower end of the drill string. After drilling to a predetermined depth, the drill string and drill bit are removed and a casing string is lowered into the wellbore. An annulus is thus formed between the string of casing and the wellbore. The casing string is cemented into the wellbore by circulating cement slurry into the annulus. The combination of cement and casing strengthens the wellbore and facilitates the isolation of certain formations behind the casing for the production of hydrocarbons. 
         [0005]    Currently, cement flows into the annulus from the bottom of the casing. Due to weak formations or long strings of casing, cementing from the top of the casing may be undesirable or ineffective. When circulating cement into the annulus from the bottom of the casing, problems may be encountered as the cement on the outside of the annulus rises. For example, if a weak earth formation exists, it will not support the cement. As a result, the cement will flow into the formation rather than up the casing annulus. 
         [0006]    To alleviate these issues, stage collars have been employed for casing cementing operations. For subterranean vertical wellbores, a free fall cone is used to open the stage collar. However, the free fall cone is unsuitable for deviated and subsea wellbores. For subsea and deviated wellbores, the stage collar has a pressure operated piston for opening thereof. Such a hydraulically operated stage tool is susceptible to premature activation due to pressure spikes in the bore of the casing string which could have catastrophic consequences. 
       SUMMARY OF THE DISCLOSURE 
       [0007]    The present disclosure generally relates to a surge immune stage system for wellbore tubular cementation. In one embodiment, a method for cementing a tubular string into a wellbore includes: running the tubular string into the wellbore using a workstring having a deployment assembly; delivering an opener activator through the workstring to the deployment assembly, thereby launching an opener plug from the deployment assembly; pumping the opener activator and plug to a stage valve of the tubular string, thereby opening the stage valve; pumping cement slurry into the workstring; pumping a closer activator through the workstring behind the cement slurry, thereby launching a closer plug from the deployment assembly; and pumping the closer activator and plug to the open stage valve, thereby driving the cement slurry into an annulus between the tubular string and the wellbore and closing the stage valve. 
         [0008]    In another embodiment, a system for cementing a tubular string into a wellbore includes: a stage valve for assembly as part of the tubular string and having: a housing, a stage port formed through the housing, a sleeve, a stage port formed through the sleeve, an opener seat connected to the sleeve, and a closer seat linked to the sleeve; and a plug release system for operating the stage valve. The plug release system includes: a closer plug having: a body, a finned seal, a latch sleeve, a lock sleeve for releasing the latch sleeve, and a landing shoulder for engaging the closer seat; and an opener plug having: a body, a finned seal, a latch sleeve, a lock sleeve for releasing the latch sleeve, and a landing shoulder for engaging the opener seat. The system further includes: a closer activator for engaging the closer lock sleeve; and an opener activator for engaging the opener lock sleeve. 
     
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
         [0009]    So that the manner in which the above recited features of the present disclosure can be understood in detail, a more particular description of the disclosure, 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 disclosure and are therefore not to be considered limiting of its scope, for the disclosure may admit to other equally effective embodiments. 
           [0010]      FIGS. 1A-1C  illustrate a drilling system in a cementing mode, according to one embodiment of this disclosure. 
           [0011]      FIG. 2  illustrates a plug release system of a liner deployment assembly of the drilling system. 
           [0012]      FIGS. 3A-3C  illustrate darts for releasing plugs of the plug release system. 
           [0013]      FIGS. 4A and 4B  illustrate a packing stage collar of a liner string deployed by the drilling system. 
           [0014]      FIGS. 5A-5J  illustrate staged cementing of the liner string.  FIG. 5K  illustrates setting of a packer of the liner string. 
       
    
    
     DETAILED DESCRIPTION 
       [0015]      FIGS. 1A-1C  illustrate a drilling system  1  in a cementing mode, according to one embodiment of this disclosure. The drilling system  1  may include a mobile offshore drilling unit (MODU)  1   m , such as a semi-submersible, a drilling rig  1   r , a fluid handling system  1   h , a fluid transport system it, a pressure control assembly (PCA)  1   p , and a workstring  9 . 
         [0016]    The MODU  1   m  may carry the drilling rig  1   r  and the fluid handling system  1   h  aboard and may include a moon pool, through which drilling operations are conducted. The semi-submersible MODU  1   m  may include a lower barge hull which floats below a surface (aka waterline)  2   s  of sea  2  and is, therefore, less subject to surface wave action. Stability columns (only one shown) may be mounted on the lower barge hull for supporting an upper hull above the waterline  2   s . The upper hull may have one or more decks for carrying the drilling rig  1   r  and fluid handling system  1   h . The MODU  1   m  may further have a dynamic positioning system (DPS) (not shown) or be moored for maintaining the moon pool in position over a subsea wellhead  10 . 
         [0017]    Alternatively, the MODU may be a drill ship. Alternatively, a fixed offshore drilling unit or a non-mobile floating offshore drilling unit may be used instead of the MODU. Alternatively, the wellbore may be subsea having a wellhead located adjacent to the waterline and the drilling rig may be a located on a platform adjacent the wellhead. Alternatively, the wellbore may be subterranean and the drilling rig located on a terrestrial pad. 
         [0018]    The drilling rig  1   r  may include a derrick  3 , a floor  4   f , a rotary table  4   t , a spider  4   s , a top drive  5 , a cementing head  7 , and a hoist. The top drive  5  may include a motor for rotating  49  ( FIG. 5A ) the workstring  9 . The top drive motor may be electric or hydraulic. A frame of the top drive  5  may be linked to a rail (not shown) of the derrick  3  for preventing rotation thereof during rotation  49  of the workstring  9  and allowing for vertical movement of the top drive with a traveling block  11   t  of the hoist. The top drive frame may be suspended from the traveling block  11   t  by a drill string compensator  8 . The quill may be torsionally driven by the top drive motor and supported from the frame by bearings. The top drive  5  may further have an inlet connected to the frame and in fluid communication with the quill. The traveling block  11   t  may be supported by wire rope  11   r  connected at its upper end to a crown block  11   c . The wire rope  11   r  may be woven through sheaves of the blocks  11   c,t  and extend to drawworks  12  for reeling thereof, thereby raising or lowering the traveling block  11   t  relative to the derrick  3 . 
         [0019]    The drill string compensator may  8  may alleviate the effects of heave on the workstring  9  when suspended from the top drive  5 . The drill string compensator  8  may be active, passive, or a combination system including both an active and passive compensator. 
         [0020]    Alternatively, the drill string compensator  8  may be disposed between the crown block  11   c  and the derrick  3 . Alternatively, a Kelly and rotary table may be used instead of the top drive  5 . 
         [0021]    When the drilling system  1  is in a deployment mode (not shown), an upper end of the workstring  9  may be connected to the top drive quill, such as by threaded couplings. The workstring  9  may include a liner deployment assembly (LDA)  9   d  and a work stem, such as such as joints of drill pipe  9   p  connected together, such as by threaded couplings. An upper end of the LDA  9   d  may be connected a lower end of the drill pipe  9   p , such as by threaded couplings. The LDA  9   d  may also be connected to a liner string  15 . The liner string  15  may include a polished bore receptacle (PBR)  15   r , a packer  15   p , a liner hanger  15   h , a mandrel  15   m  for carrying the hanger and packer, joints  15   j  of liner, a packing stage collar  15   o , a landing collar  15   c , a float collar  15   f , and a reamer shoe  15   s . The mandrel  15   m , liner joints  15   j , collars  15   c,o,f  and reamer shoe  15   s  may be interconnected, such as by threaded couplings. 
         [0022]    The fluid transport system it may include an upper marine riser package (UMRP)  16   u , a marine riser  17 , a booster line  18   b , and a choke line  18   k . The riser  17  may extend from the PCA  1   p  to the MODU  1   m  and may connect to the MODU via the UMRP  16   u . The UMRP  16   u  may include a diverter  19 , a flex joint  20 , a slip (aka telescopic) joint  21 , and a tensioner  22 . The slip joint  21  may include an outer barrel connected to an upper end of the riser  17 , such as by a flanged connection, and an inner barrel connected to the flex joint  20 , such as by a flanged connection. The outer barrel may also be connected to the tensioner  22 , such as by a tensioner ring. 
         [0023]    The flex joint  20  may also connect to the diverter  19 , such as by a flanged connection. The diverter  19  may also be connected to the rig floor  4   f , such as by a bracket. The slip joint  21  may be operable to extend and retract in response to heave of the MODU  1   m  relative to the riser  17  while the tensioner  22  may reel wire rope in response to the heave, thereby supporting the riser  17  from the MODU  1   m  while accommodating the heave. The riser  17  may have one or more buoyancy modules (not shown) disposed therealong to reduce load on the tensioner  22 . 
         [0024]    The PCA  1   p  may be connected to the wellhead  10  located adjacent to a floor  2   f  of the sea  2 . A conductor string  23  may be driven into the seafloor  2   f . The conductor string  23  may include a housing and joints of conductor pipe connected together, such as by threaded couplings. Once the conductor string  23  has been set, a subsea wellbore  24  may be drilled into the seafloor  2   f  and a casing string  25  may be deployed into the wellbore. The casing string  25  may include a wellhead housing and joints of casing connected together, such as by threaded couplings. The wellhead housing may land in the conductor housing during deployment of the casing string  25 . The casing string  25  may be cemented  26  into the wellbore  24 . The casing string  25  may extend to a depth adjacent a bottom of the upper formation  27   u . The wellbore  24  may then be extended into the lower formation  27   b  using a drill string (not shown). 
         [0025]    The upper formation  27   u  may be non-productive and a lower formation  27   b  may be a hydrocarbon-bearing reservoir. Alternatively, the lower formation  27   b  may be non-productive (e.g., a depleted zone), environmentally sensitive, such as an aquifer, or unstable. 
         [0026]    The PCA  1   p  may include a wellhead adapter  28   b , one or more flow crosses  29   u,m,b , one or more blow out preventers (BOPs)  30   a,u,b , a lower marine riser package (LMRP)  16   b , one or more accumulators, and a receiver  31 . The LMRP  16   b  may include a control pod, a flex joint  32 , and a connector  28   u . The wellhead adapter  28   b , flow crosses  29   u,m,b , BOPs  30   a,u,b , receiver  31 , connector  28   u , and flex joint  32 , may each include a housing having a longitudinal bore therethrough and may each be connected, such as by flanges, such that a continuous bore is maintained therethrough. The flex joints  21 ,  32  may accommodate respective horizontal and/or rotational (aka pitch and roll) movement of the MODU  1   m  relative to the riser  17  and the riser relative to the PCA  1   p.    
         [0027]    Each of the connector  28   u  and wellhead adapter  28   b  may include one or more fasteners, such as dogs, for fastening the LMRP  16   b  to the BOPs  30   a,u,b  and the PCA  1   p  to an external profile of the wellhead housing, respectively. Each of the connector  28   u  and wellhead adapter  28   b  may further include a seal sleeve for engaging an internal profile of the respective receiver  31  and wellhead housing. Each of the connector  28   u  and wellhead adapter  28   b  may be in electric or hydraulic communication with the control pod and/or further include an electric or hydraulic actuator and an interface, such as a hot stab, so that a remotely operated subsea vehicle (ROV) (not shown) may operate the actuator for engaging the dogs with the external profile. 
         [0028]    The LMRP  16   b  may receive a lower end of the riser  17  and connect the riser to the PCA  1   p . The control pod may be in electric, hydraulic, and/or optical communication with a control console  33   c  onboard the MODU  1   m  via an umbilical  33   u . The control pod may include one or more control valves (not shown) in communication with the BOPs  30   a,u,b  for operation thereof. Each control valve may include an electric or hydraulic actuator in communication with the umbilical  33   u . The umbilical  33   u  may include one or more hydraulic and/or electric control conduit/cables for the actuators. The accumulators may store pressurized hydraulic fluid for operating the BOPs  30   a,u,b . Additionally, the accumulators may be used for operating one or more of the other components of the PCA  1   p . The control pod may further include control valves for operating the other functions of the PCA  1   p . The control console  33   c  may operate the PCA  1   p  via the umbilical  33   u  and the control pod. 
         [0029]    A lower end of the booster line  18   b  may be connected to a branch of the flow cross  29   u  by a shutoff valve. A booster manifold may also connect to the booster line lower end and have a prong connected to a respective branch of each flow cross  29   m,b . Shutoff valves may be disposed in respective prongs of the booster manifold. Alternatively, a separate kill line (not shown) may be connected to the branches of the flow crosses  29   m,b  instead of the booster manifold. An upper end of the booster line  18   b  may be connected to an outlet of a booster pump  44 . A lower end of the choke line  18   k  may have prongs connected to respective second branches of the flow crosses  29   m,b . Shutoff valves may be disposed in respective prongs of the choke line lower end. An upper end of the choke line  18   k  may be connected to an inlet of a mud gas separator (MGS)  46 . 
         [0030]    A pressure sensor may be connected to a second branch of the upper flow cross  29   u . Pressure sensors may also be connected to the choke line prongs between respective shutoff valves and respective flow cross second branches. Each pressure sensor may be in data communication with the control pod. The lines  18   b,c  and umbilical  33   u  may extend between the MODU  1   m  and the PCA  1   p  by being fastened to brackets disposed along the riser  17 . Each shutoff valve may be automated and have a hydraulic actuator (not shown) operable by the control pod. 
         [0031]    Alternatively, the umbilical  33   u  may be extended between the MODU  1   m  and the PCA  1   p  independently of the riser  17 . Alternatively, the shutoff valve actuators may be electrical or pneumatic. 
         [0032]    The fluid handling system  1   h  may include one or more pumps, such as a cement pump  13 , a mud pump  34 , and the booster pump  44 , a reservoir, such as a tank  35 , a solids separator, such as a shale shaker  36 , one or more pressure gauges  37   c,k,m,r , one or more stroke counters  38   c,m , one or more flow lines, such as cement line  14 , mud line  39 , and return line  40 , one or more shutoff valves  41   c,k , a cement mixer  42 , a well control (WC) choke  45 , and the MGS  46 . When the drilling system  1  is in a drilling mode (not shown) and the deployment mode, the tank  35  may be filled with drilling fluid (not shown). In the cementing mode, the tank  35  may be filled with chaser fluid  47 . A booster supply line may be connected to an outlet of the mud tank  35  and an inlet of the booster pump  44 . The choke shutoff valve  41   k , the choke pressure gauge  37   k , and the WC choke  45  may be assembled as part of the upper portion of the choke line  18   k.    
         [0033]    A first end of the return line  40  may be connected to the diverter outlet and a second end of the return line may be connected to an inlet of the shaker  36 . The returns pressure gauge  37   r  may be assembled as part of the return line  40 . A lower end of the mud line  39  may be connected to an outlet of the mud pump  34  and an upper end of the mud line may be connected to the top drive inlet. The mud pressure gauge  37   m  may be assembled as part of the mud line  39 . An upper end of the cement line  14  may be connected to a cementing swivel  7   c  and a lower end of the cement line may be connected to an outlet of the cement pump  13 . The cement shutoff valve  41   c  and the cement pressure gauge  37   c  may be assembled as part of the cement line  14 . A lower end of a mud supply line may be connected to an outlet of the mud tank  35  and an upper end of the mud supply line may be connected to an inlet of the mud pump  34 . An upper end of a cement supply line may be connected to an outlet of the cement mixer  42  and a lower end of the cement supply line may be connected to an inlet of the cement pump  13 . 
         [0034]    During deployment of the liner string  15 , the workstring  9  may be lowered by the traveling block  11   t  and the drilling fluid may be pumped into the workstring bore by the mud pump  34  via the mud line  39  and top drive  5 . The drilling fluid may flow down the workstring bore and the liner string bore and be discharged by the reamer shoe  15   s  into an annulus  48  formed between the liner string  15  and the wellbore  24 /casing string  25 . The drilling fluid may flow up the annulus  48  and exit the wellbore  24  and flow into an annulus formed between the riser  17  and the workstring  9  via an annulus of the LMRP  16   b , BOP stack, and wellhead  10 . The drilling fluid may exit the riser annulus and enter the return line  40  via an annulus of the UMRP  16   u  and the diverter  19 . The drilling fluid may flow through the return line  40  and into the shale shaker inlet. The drilling fluid may be processed by the shale shaker  36  to remove any particulates therefrom. 
         [0035]    The float collar  15   c  may include a housing, a check valve, and a body. The body and check valve may be made from drillable materials. The check valve may include a seat, a poppet disposed within the seat, a seal disposed around the poppet and adapted to contact an inner surface of the seat to close the body bore, and a rib. The poppet may have a head portion and a stem portion. The rib may support a stem portion of the poppet. A spring may be disposed around the stem portion and may bias the poppet against the seat to facilitate sealing. During deployment of the liner string  15 , the drilling fluid may be pumped down at a sufficient pressure to overcome the bias of the spring, actuating the poppet downward to allow drilling fluid to flow through the bore of the body and into the annulus  48 . 
         [0036]    The workstring  9  may be lowered until the liner string  15  reaches a desired deployment depth, such as the liner hanger  15   h  being adjacent to a lower portion of the casing string  25 . The workstring  9  may be disconnected from the top drive  5  and the cementing head  7  may be inserted and connected between the top drive  5  and the workstring  9 . The cementing head  7  may include an isolation valve  6 , an actuator swivel  7   a , the cementing swivel  7   c , a release plug launcher  7   r , a control console  7   e , and a setting plug launcher  7   s . The isolation valve  6  may be connected to a quill of the top drive  5  and an upper end of the actuator swivel  7   a , such as by threaded couplings. An upper end of the workstring  9  may be connected to the setting plug launcher  7   s , such as by threaded couplings. 
         [0037]    The cementing swivel  7   c  may include a housing torsionally connected to the derrick  3 , such as by bars, wire rope, or a bracket (not shown). The torsional connection may accommodate longitudinal movement of the cementing swivel  7   c  relative to the derrick  3 . The cementing swivel  7   c  may further include a mandrel and bearings for supporting the housing from the mandrel while accommodating rotation of the mandrel. An upper end of the mandrel may be connected to a lower end of the actuator swivel  7   a , such as by threaded couplings. The cementing swivel  7   c  may further include an inlet formed through a wall of the housing and in fluid communication with a port formed through the mandrel and a seal assembly for isolating the inlet-port communication. The mandrel port may provide fluid communication between a bore of the cementing head  7  and the housing inlet. 
         [0038]    The actuator swivel  7   a  may be similar to the cementing swivel  7   c  except that the housing thereof may have an inlet in fluid communication with a passage formed through the mandrel thereof. The mandrel passage may extend to an outlet for connection to a hydraulic conduit for operating a hydraulic actuator of the release plug launcher  7   r . The actuator swivel inlet may be in fluid communication with a hydraulic power unit (HPU, not shown) operated by the control console  7   e.    
         [0039]    The release plug launcher  7   r  may include a body, a deflector, a canister, a gate, and the actuator. The body may be tubular and may have a bore therethrough. An upper end of the body may be connected to a lower end of the cementing swivel  7   c , such as by threaded couplings, and a lower end of the body may be connected to the setting plug launcher  7   s , such as by threaded couplings. The canister and deflector may each be disposed in the body bore. The deflector may be connected to the cementing swivel mandrel, such as by threaded couplings. The canister may be longitudinally movable relative to the body. The canister may be tubular and have ribs formed along and around an outer surface thereof. Bypass passages (only one shown) may be formed between the ribs. Each canister may further have a landing shoulder formed in a lower end thereof for receipt by a landing shoulder of the setting plug launcher  7   s . The deflector may be operable to divert fluid received from the cement line  14  away from a bore of the canister and toward the bypass passages. A release plug, such as a shutoff dart  66 , may be disposed in the canister bore. 
         [0040]    The gate may include a housing, a plunger, and a shaft. The housing may be connected to a respective lug formed in an outer surface of the body, such as by threaded couplings. The plunger may be longitudinally movable relative to the housing and radially movable relative to the body between a capture position and a release position. The plunger may be moved between the positions by a linkage, such as a jackscrew, with the shaft. Each shaft may be longitudinally connected to and rotatable relative to the housing. Each actuator may be a hydraulic motor operable to rotate the shaft relative to the housing. The actuator may include a reservoir (not shown) for receiving the spent hydraulic fluid or the cementing head  7  may include a second actuator swivel and hydraulic conduit (not shown) for returning the spent hydraulic fluid to the HPU. 
         [0041]    In operation, when it is desired to launch the shutoff dart  66 , the console  7   e  may be operated to supply hydraulic fluid to the launcher actuator via the actuator swivel  7   a . The launcher actuator may then move the plunger to the release position. The canister and dart may then move downward relative to the body until the landing shoulders engage. Engagement of the landing shoulders may close the canister bypass passages, thereby forcing chaser fluid  47  to flow into the canister bore. The chaser fluid  47  may then propel the dart  66  from the canister bore into a bore of the setting plug launcher  7   s  and onward through the workstring  9 . 
         [0042]    The setting plug launcher  7   s  may include a mandrel, a body, a plunger, an actuator. During deployment of the liner string  15 , a setting plug, such as a ball  50  ( FIG. 1C ), may be loaded therein. The launcher body may be connected to the mandrel, such as by threaded couplings. The ball  50  may be disposed in the plunger for selective release and pumping downhole through the drill pipe  9   p  to the LDA  9   d . The plunger may be movable relative to the launcher body between a capture position and a release position. The plunger may be moved between the positions by the actuator. The actuator may be manual, such as a handwheel. 
         [0043]    Alternatively, the actuator swivel  7   a  and release plug launcher actuator may be pneumatic or electric. Alternatively, the release plug launcher actuator may be linear, such as a piston and cylinder. Alternatively, the release plug launcher  7   r  may include a main body having a main bore and a parallel side bore, with both bores being machined integral to the main body. The dart may be loaded into the main bore, and a dart releaser valve may be provided below the dart to maintain it in the capture position. The dart releaser valve may be side-mounted externally and extend through the main body. A port in the dart releaser valve may provide fluid communication between the main bore and the side bore. In a bypass position, the dart may be maintained in the main bore with the dart releaser valve closed. Fluid may flow through the side bore and into the main bore below the dart via the fluid communication port in the dart releaser valve. To release the dart, the dart releaser valve may be turned, such as by ninety degrees, thereby closing the side bore and opening the main bore through the dart releaser valve. The chaser fluid  47  may then enter the main bore behind the dart, causing it to drop downhole. 
         [0044]    The LDA  9   d  may include a setting tool  52 , a running tool  53 , a catcher  54 , and a plug release system  55 . The setting tool  52  may include a debris barrier  51 , a packoff  56 , a hanger actuator  58 , a packer actuator  59 , a mandrel  60 , and a latch  61 . An upper end of the setting tool  52  may be connected to a lower end the drill pipe  9   p , such as by threaded couplings. A lower end of the setting tool  52  may be fastened to an upper end of the running tool  53 . The running tool  53  may also be fastened to the liner mandrel  15   m . An upper end of the catcher  54  may be connected to a lower end of the running tool  53  and a lower end of the catcher may be connected to an upper end of the plug release system  55 , such as by threaded couplings. 
         [0045]    The debris barrier  51  may be engaged with and close an upper end of the PBR  15   r , thereby forming an upper end of a buffer chamber. A lower end of the buffer chamber may be formed by a sealed interface between the packoff  56  and the PBR  15   r . The buffer chamber may be filled with a buffer fluid (not shown), such as fresh water, refined/synthetic oil, or other liquid. The buffer chamber may prevent infiltration of debris from the wellbore  24  from obstructing operation of the LDA  9   d.    
         [0046]    The hanger actuator  58  may include a piston, one or more sleeves, and a cylinder. The latch  61  may releasably connect the piston to the debris barrier  51  and the debris barrier to the PBR  15   r . The actuator sleeves and piston may interconnected, such as by threaded couplings and/or fasteners. The actuator sleeves and piston may be disposed around and extend along an outer surface of the mandrel  60 . The actuator sleeves may also be torsionally connected to the mandrel  60 , such as by a pin and slot linkage. An actuation chamber may be formed between mandrel  60  and the cylinder. A foot of the piston may be disposed in the actuation chamber and may divide the chamber into an upper portion and a lower portion. The actuation chamber upper portion may be in fluid communication with the mandrel bore via an actuation port formed through a wall of the mandrel  60 . 
         [0047]    The piston and sleeves of the hanger actuator  58  may be longitudinally movable relative to the cylinder between an upper position (not shown) and a lower position ( FIG. 1C ) in response to a pressure differential between an upper face of the foot and a lower face of the foot. The piston and sleeves may set the liner hanger  15   h  when moving from the upper position to the lower position. The chamber lower portion may be in fluid communication with a surge chamber via a bypass passage and a bypass port of the running tool  53 . The surge chamber may be formed radially between a lower portion of the LDA  9   d  (below the packoff  56 ) and the liner string  15  and longitudinally between the packoff  56  and a closer plug  65  ( FIG. 2 ) of the plug release system  55 . 
         [0048]    The running tool  53  may include a body, a lock, a clutch, and a latch. The running tool latch may longitudinally and torsionally connect the liner mandrel  15   m  to an upper portion of the LDA  9   d . The latch may include a thrust cap, a longitudinal fastener, such as a floating nut, and a biasing member, such as a lower compression spring. The running tool lock may include one or more actuation ports formed through a wall of the body, a piston, a plug, a fastener, such as a dog, and a sleeve. 
         [0049]    The packer actuator  59  may be longitudinally connected to the mandrel by entrapment between a load shoulder of the mandrel  60  and a top of the running tool  53 . The packer actuator  59  may include the packoff  56 , a plurality of fasteners, such as dogs, a cam, one or more retainers, a thrust bearing, one or more radial bearings, and one or more biasing members, such as compression springs. The dogs may be restrained in a retracted position against the compression springs by engagement with an inner surface of the liner mandrel  15   m.    
         [0050]    The catcher  54  may be a mechanical ball seat including a body and a seat fastened to the body, such as by one or more shearable fasteners. The seat may also be linked to the body by a cam and follower. Once the ball  50  is caught, the seat may be released from the body by a threshold pressure exerted on the ball. The threshold pressure may be greater than a pressure required to set the liner hanger  15   h , unlock the running tool  53 , and release the latch  61 . Once the seated ball  50  has been released, the seat and ball may swing relative to the body into a capture chamber, thereby reopening the LDA bore. 
         [0051]    As the liner string  15  is being advanced into the wellbore  24  by the workstring  9 , resultant surge pressure of the drilling fluid may be communicated to the surge chamber via leakage through the directional seals of plugs  63 - 65 . The surge pressure may then be communicated to the lower face of the actuator piston via the running tool bypass port and the bypass passage. The surge pressure may also be communicated to an upper face of the running tool piston exposed to the surge chamber. This communication of the surge pressure to the lower face of the actuator piston and the upper face of the running tool piston may negate tendency of the surge pressure communicated to an upper face of the actuator piston by the actuation port and to the lower face of the running tool piston by the running tool actuator ports from prematurely setting the liner hanger  15   h  and prematurely unlocking the running tool  53 . 
         [0052]    Once the liner string  15  has been advanced into the wellbore  24  by the workstring  9  to a desired deployment depth and the cementing head  7  has been installed, conditioner  43  ( FIG. 5A ) may be circulated by the cement pump  13  through the valve  41  to prepare for pumping of first stage cement slurry  95   a  ( FIG. 5A ). The setting plug launcher  7   s  may then be operated and the conditioner  43  may propel the ball  50  down the workstring  9  to the catcher  54 . The ball  50  may land in the seat of the catcher  54 . 
         [0053]    Once the ball  50  has landed continued pumping of the conditioner  43  may increase pressure on the seated ball, thereby also pressurizing the actuation chamber of the actuator  58  and exerting pressure on the actuator piston thereof. The actuator piston may in turn exert a setting force on the PBR  15   r  via the actuator sleeves, a lock sleeve of the latch  61 , and the debris barrier  51 . The PBR  15   r  may in turn exert the setting force on an upper portion of the liner hanger  15   h  via the packer  15   p . The liner hanger upper portion may initially be restrained from setting the liner hanger  15   h  by a shearable fastener. Once a first threshold pressure on the actuator piston has been reached, the shearable fastener may fracture, thereby releasing the liner hanger upper portion. The actuator piston, actuator sleeves, lock sleeve, the debris barrier  51 , PBR  15   r , packer  15   p , and liner hanger upper portion may travel downward until slips of the liner hanger  15   h  are set against the casing  25 , thereby halting the movement. 
         [0054]    Continued pumping of the conditioner  43  may further pressurize the actuation chamber until a second threshold pressure is reached, thereby fracturing a shearable fastener and releasing the debris barrier  51  from the actuator piston. The liner hanger  15   h  may be restrained from unsetting by a lower ratchet connection. Downward movement of the actuator piston and actuator sleeves may continue until the actuator piston reaches a lower end of the actuation chamber. Continued pumping of the conditioner  43  may further pressurize the LDA bore (above the seated ball  50 ). An actuation chamber of the running tool  53  may be pressurized and exert pressure on the running tool piston. Once a third threshold pressure on the running tool piston has been reached, a shearable fastener may fracture, thereby releasing the running tool piston. The running tool piston may travel upward, thereby unlocking the running tool  53 . 
         [0055]    Once the liner hanger  15   h  has been set against an inner surface of a lower portion, such as the bottom, of the casing string  25  and the running tool  53  unlocked, the workstring  9  may be rotated, thereby releasing the floating nut of the running tool from a threaded profile of the liner mandrel  15   m . The workstring  9  may be raised to verify successful release and lowered to torsionally engage the running tool  53  with the liner string  15  for rotation during the first stage of the cementing operation. 
         [0056]    Alternatively, the liner string  15  may be hung from another liner string cemented into the wellbore instead of the casing string  25 . 
         [0057]      FIG. 2  illustrates the plug release system  55 . The plug release system  55  may include a relief valve  62  and one or more plugs, such as a shutoff plug  63 , an opener plug  64 , and the closer plug  65 . The relief valve  62  may include a housing  62   h , an outer wall  62   w , a cap  62   c , a piston  62   p , a spring  62   s , a fastener, such as collet  62   f , and a seal insert  62   i . The housing  62   h , outer wall  62   w , and cap  62   c  may be interconnected, such as by threaded couplings. 
         [0058]    The piston  62   p  and spring  62   s  may be disposed in an annular chamber formed radially between the housing  62   h  and the outer wall  62   w  and longitudinally between a shoulder of the housing and a shoulder of the cap  62   c . The piston  62   p  may divide the chamber into an upper portion and a lower portion and carry a seal for isolating the portions. The cap  62   c  and housing  62   h  may also carry seals for isolating the portions. The outer wall  62   w  may have one or more (pair shown) inlet ports  62   n  formed therethrough for providing fluid communication between the surge chamber and a lower face of the piston  62   p . An outlet port may be formed by a gap between a bottom of the housing  62   h  and a top of the cap  62   c . An equalization port  62   e  may be formed through a wall of the housing  62   h  for providing fluid communication between an upper face of the piston  62   p  and the valve bore. 
         [0059]    The piston  62   p  may be longitudinally movable between an upper open position (not shown) and a lower closed position. The spring  62   s  may be disposed between an upper face of the piston  62   p  and an upper end of the chamber, thereby biasing the piston toward the lower closed position. The piston  62   p  may move to the upper open position in response to pressure in the surge chamber being greater than pressure in the valve bore by a pressure differential sufficient to overcome a biasing force of the spring  62   s . The housing  62   h  and cap  62   c  may each carry a seal straddling the outlet port and the piston  62   p  may be aligned with the outlet port and engaged with the seals in the lower closed position, thereby isolating the outlet port from the inlet ports  62   n . The piston  62   p  may be clear of the outlet port in the upper open position, thereby allowing fluid communication between the inlet  62   n  and outlet ports. 
         [0060]    Alternatively, the spring  62   s  may have a nominal stiffness or be omitted and the valve  62  may function as a check valve instead of a relief valve. 
         [0061]    Each plug  63 - 65  may be made from a drillable material and include a respective finned seal  63   f - 65   f , a plug body  63   b - 65   b , a latch sleeve  63   v - 65   v , a lock sleeve  63   k - 65   k , and a landing shoulder  63   r - 65   r . Each latch sleeve  63   v - 65   v  may have a collet formed in an upper end thereof and the closer  65   r  landing shoulder and opener body  64   b  may each have a respective collet profile formed in a lower portion thereof. Each lock sleeve  63   k - 65   k  may have a respective seat  63   s - 65   s  and seal bore  63   e - 65   e  formed therein. Each lock sleeve  63   k - 65   k  may be movable between an upper position and a lower position and be releasably restrained in the upper position by a respective shearable fastener  63   h - 65   h . The shutoff  63   r  and opener  64   r  landing shoulders may each carry a landing seal. The finned seals  63   f - 65   f  (except for glands) may be made from an elastomer or elastomeric copolymer and the sleeves  63   k,v - 65   k,v , bodies  63   b - 65   b , fin glands, and shoulders  63   r - 65   r  may be made from a nonferrous metal or alloy. 
         [0062]    The closer shearable fastener  65   h  may releasably connect the closer lock sleeve  65   k  to the valve housing  62   h  and the closer lock sleeve  65   k  may be engaged with the valve collet  62   f  in the upper position, thereby locking the valve collet into engagement with the collet of the closer latch sleeve  65   v . The opener shearable fastener  64   h  may releasably connect the opener lock sleeve  64   k  to the closer landing shoulder  65   r  and the opener lock sleeve may be engaged with the collet of the opener latch sleeve  64   v , thereby locking the collet into engagement with the collet profile of the opener landing shoulder. The shutoff shearable fastener  63   h  may releasably connect the shutoff lock sleeve  63   k  to the opener body  64   b  and the shutoff lock sleeve may be engaged with the collet of the shutoff latch sleeve  63   v , thereby locking the collet into engagement with the collet profile of the opener body. 
         [0063]    The shutoff plug  63  may include one or more (pair shown) bypass ports formed through a wall of the shutoff body  63   b  and initially sealed by a burst tube  69  to prevent fluid flow therethrough. The burst tube  69  may be operable to rupture when a predetermined pressure is applied thereto. To facilitate subsequent drill-out, the shutoff landing shoulder  63   r  may have a portion of an auto-orienting torsional profile  70   m,f  formed at a bottom thereof. 
         [0064]    Alternatively, the opener landing shoulder  64   r  and/or the closer landing shoulder  65   r  may also have a portion of the auto-orienting torsional profile  70   m,f  formed at a bottom and/or outer surface thereof. Alternatively, the opener plug  64  may also include a one or more (second) bypass ports formed through a wall of the opener body  64   b  and initially sealed by a (second) burst tube to prevent fluid flow therethrough. The second burst tube may be operable to rupture when a predetermined (second) pressure is applied thereto. The second burst tube may be ruptured in the event of failure of the packing stage collar  15   o.    
         [0065]    The landing collar  15   c  may include a housing and a seat disposed therein and connected thereto, such as by threaded couplings. The seat may have longitudinal holes drilled in a wall thereof from a bottom thereof and extending along a length thereof. The holes may terminate adjacent a top of the seat to impart flexibility thereto for receiving the landing shoulder  63   r  of the shutoff plug  63 . The seat may have a bore formed therethrough and the other portion  70   f  of the torsional profile  70   m,f  formed in an upper face thereof for engagement with the portion  70   m  of the shutoff plug  63 . The seat may also have a seal bore formed therein for receiving the landing seal of the landing shoulder  63   r.    
         [0066]      FIGS. 3A-3C  illustrate activators, such as darts  66 - 68 , for releasing the respective plugs  63 - 65 . Each dart  66 - 68  may be made from a drillable material and include a respective finned seal  66   f - 68   f , dart body  66   b - 68   b , landing cap  66   c - 68   c , and retainer head  66   h - 68   h . Each landing cap  66   c - 68   c  may have a respective landing shoulder  66   r - 68   r  and carry a respective landing seal  66   s - 68   s  for engagement with the respective seat  63   s - 65   s  and seal bore  63   e - 65   e . A major diameter of the shutoff shoulder  66   r  may be less than a minor diameter of the opener seat  64   s  and a major diameter of the opener shoulder  67   r  may be less than a minor diameter of the closer seat  65   s  such that the shutoff dart  66  may pass through the closer  65  and opener  64  plugs and the opener dart  67  may pass through the closer plug  64 . The finned seals  66   f - 68   f  (except for glands) and retainer heads  66   h - 68   h  (except for glands) may be made from an elastomer or elastomeric copolymer and the caps  66   c - 68   c , bodies  66   b - 68   b , fin glands, and head glands may be made from a nonferrous metal or alloy. 
         [0067]    Alternatively, one or more of the activators may be balls instead of the darts and the balls may be pumped or dropped to the respective plugs. 
         [0068]      FIGS. 4A and 4B  illustrate the packing stage collar  15   o . The packing stage collar  71  may include a stage valve  71 , an inflator  72 , and a packer  73 . The stage valve  71  may include a housing  74 , a sleeve  75 , an opener seat  76 , and a closer seat  77 . The housing  74  may be a tubular member having threaded couplings formed at each longitudinal end thereof for connection to a liner joint  15   j  at an upper end thereof and for connection to the inflator  72  at a lower end thereof. The sleeve  75  may be disposed in the housing  74  and longitudinally movable relative thereto between a deployment (or upper closed) position (shown), an open position ( FIG. 5E ), and a (lower) closed position ( FIG. 5J ). 
         [0069]    In the deployment position, the closer seat  77  and sleeve  75  may be releasably connected to the housing, such as by one or more (pair shown) shearable fasteners  78   u . The shearable fasteners  78   u  may each be operable to fracture a first time at an outer interface between the housing  74  and the sleeve  75  in response to engagement of the landing shoulder  64   r  of the opener plug  64  with the opener seat  76 , thereby releasing the sleeve  75  and closer seat  77  from the housing  74 . The shearable fasteners  78   u  may each be operable to fracture a second time at an inner interface between the closer seat  77  and the sleeve  75  in response to engagement of the landing shoulder  65   r  of the closer plug  65  with the closer seat, thereby releasing the closer seat from the sleeve  75 . 
         [0070]    A major diameter of the shutoff shoulder  63   r  may be less than a minor diameter of the opener seat  76  and a major diameter of the opener shoulder  64   r  may be less than a minor diameter of the closer seat  77  such that the shutoff plug  63  may pass through the closer  77  and opener  76  seats and the opener plug  64  may pass through the closer seat. The seats  76 ,  77  may be made from a drillable material, such as a nonferrous metal or alloy. 
         [0071]    The closer seat  77  may be longitudinally movable relative to the sleeve  75  between an upper lock position (shown) and a lower release position ( FIG. 5J ). The closer seat  77  may engage a shoulder formed in an inner surface of the sleeve  75  in the release position. The sleeve  75  may also be linked to the housing  74  by a slip joint  79 . The slip joint  79  may include one or more (pair shown) slots  790  formed in an inner surface of the housing  74 , one or more (pair shown) fasteners, such as dogs  79   d , and a groove  79   i  formed in an outer surface of the closer seat  77 . A (non-grooved) portion of the closer seat outer surface may serve as a locking sleeve of the slip joint  79  when aligned (shown) in the lock position. The dogs  79   d  may be carried in respective sockets formed through a wall of the sleeve  75  and may be radially movable thereto between an extended position (shown) and a retracted position ( FIG. 5J ). The dogs  79   d  may extend into the respective slots  790  in the extended position, thereby torsionally connecting the sleeve  75  and the housing  74  while allowing relative longitudinal movement therebetween. The dogs  79   d  may be allowed to retract by alignment of the groove  79   i  therewith when the closer seat  77  is in the release position. 
         [0072]    The sleeve  75  may have one or more (pair shown) stage ports  80   m  formed through a wall thereof and the housing  74  may have one or more (pair shown) corresponding stage ports  80   h  formed through a wall thereof. The sleeve  75  may carry a pair of seals  81   a,b  straddling the stage ports  80   m  thereof and also carry a lower seal  81   c  adjacent to a lower end thereof for isolating the housing stage ports  80   h  in the deployment position. An outer surface of the sleeve  75  may cover the housing stage ports  80   h  in the deployment and closed positions and the sleeve stage ports  80   m  may be aligned with the housing stage ports in the open position. The closer seat  76  may be connected to the sleeve  75 , such as by threaded couplings. 
         [0073]    The inflator  72  may include a stop  82 , a switch valve  83 , a body  84 , a check valve  85 , one or more (pair shown) biasing members, such as compression springs  86 , and an upper portion of a mandrel  87 . The stop  82  may be a ring fastened to the housing  74  and sealingly engaged with the switch valve  83 , such as by a lap joint. The switch valve  83  may be disposed along an outer surface of the housing  74  and longitudinally movable relative thereto between an upper inflation position (shown) and a lower cementing position ( FIG. 5G ). In the inflation position, the switch valve  83  may be releasably connected to the housing  74 , such as by one or more (pair shown) shearable fasteners  78   b . In the inflation position, the switch valve  83  may isolate the housing ports  80   h  from fluid communication with the annulus  48  and instead divert fluid flow therefrom down an upper annular gap  88   u  formed between the switch valve and the housing, one or more (pair shown) flow passages  88   p  formed in a wall of the body  84 , and a lower annular gap  88   b  formed between the body and the mandrel  87 . The fluid may flow down the flow path  88   u,p,b  to the check valve  85 . The switch valve  83  may move to the lower cementing position in response to sufficient fluid pressure exerted on a piston shoulder thereof to fracture the shearable fasteners  78   b . The switch valve  83  may then move downward until a bottom thereof engages a shoulder formed in an outer surface of the valve body  84 . 
         [0074]    The body  84  may be a tubular member having threaded couplings formed at each longitudinal end thereof for connection to the housing  74  at an upper end thereof and for connection to the mandrel  87  at a mid portion thereof. The mandrel  87  may be a tubular member having threaded couplings formed at each longitudinal end thereof for connection to the body  84  at an upper end thereof and for connection to a liner joint  15   j  at a lower end thereof. A bottom of the body  84  may be beveled for receiving the check valve  85 . The check valve  85  may be longitudinally movable relative to the body  84  between a closed position (shown) and an open position ( FIG. 5F ). The check valve  85  may have a beveled top carrying a seal for closing against the body  84 . The springs  86  may be disposed between the check valve  85  and the packer  73  for biasing the check valve toward the closed position. Fluid pressure exerted on the beveled top of the check valve  85  may drive the check valve toward the open position against the springs  86 . 
         [0075]    The packer  73  may include a lower portion of the mandrel  87 , an upper retainer  89   u , a lower retainer  89   b , an upper gland  90   u , a lower gland  90   b , a bladder  91 , a seal keeper  92 , and a sliding seal  93 . The upper retainer  89   u  may be fastened to the valve body  84  and connected to the upper gland  90   u , such as by threaded couplings. The bladder  91  may include an outer packing element made from an elastomer or elastomeric copolymer and one or more (two shown) inner layers of reinforcement. Each longitudinal end of the bladder  91  may be molded on or bonded to the respective gland  90   u,b.    
         [0076]    The bladder  91  may extend along an outer surface of the mandrel  87  and be radially displaceable between a deflated position (shown) and an inflated position ( FIG. 5F ). The bladder  91  may be inflated by fluid flowing down the flow path  88   u,p,b , through the open check valve  85 , and down an upper annular gap  94   u  formed between the check valve  85  and the upper retainer  89   u , a circumferential space (not shown) formed between the springs  86 , and a lower annular gap  94   b  formed between the mandrel  87  and the upper retainer  89   u . The fluid may flow to an inflation chamber formed between the bladder  91  and the mandrel  87  and exert inflation pressure against the sliding seal  93  isolating an interface formed between the lower retainer  89   b  and the mandrel  87 . 
         [0077]      FIGS. 5A-5J  illustrate staged cementing of the liner string  15 . Referring specifically to  FIG. 5A , the workstring  9  and liner string  15  (except for the set hanger  15   h ) may be rotated  49  from surface by the top drive  5  and rotation may continue during the cementing operation. Rotation of the rest of the liner string  15  relative to the set hanger  15   h  may be facilitated by a thrust bearing. The first stage cement slurry  95   a  may be pumped from the mixer  42  into the cementing swivel  7   c  via the valve  41   c  by the cement pump  13 . The first stage cement slurry  95   a  may flow into the launcher  7   r  and be diverted past the shutoff dart  66  via the diverter and bypass passages. 
         [0078]    Once the desired quantity of the first stage cement slurry  95   a  has been pumped, the shutoff dart  66  may be released from the launcher  7   r  by operating the launcher actuator. The desired quantity of the first stage cement slurry  95   a  may correspond to a volume of the annulus  48  between the packing stage collar  15   o  and the reamer shoe  15   s . Chaser fluid  47  may be pumped into the cementing swivel  7   c  via the valve  41   c  by the cement pump  13 . The chaser fluid  47  may flow into the launcher  7   r  and be forced behind the shutoff dart  66  by closing of the bypass passages, thereby propelling the shutoff dart into the workstring bore. Pumping of the chaser fluid  47  by the cement pump  13  may continue until residual cement in the cement line  14  has been purged. Pumping of the chaser fluid  47  may then be transferred to the mud pump  34  by closing the valve  41   c  and opening the valve  6 . The shutoff dart  66  and first stage cement slurry  95   a  may be driven through the workstring bore by the chaser fluid  47 . 
         [0079]    Once a slug  47   s  of chaser fluid  47  has been pumped, a second release plug launcher (not shown) of the cementing head  7  may be operated to launch the opener dart  67 . A volume of the slug  47   s  may correspond to, such as being slightly greater than, a volume of the liner string bore between the landing collar  15   c  and the opener seat  76 . A train of the opener dart  67 , slug  47   s , shutoff dart  66 , and first stage cement slurry  95   a , may be driven through the workstring bore by the chaser fluid  47 . 
         [0080]    Referring specifically to  FIG. 5B , the shutoff dart  66  may reach the shutoff plug  63  and the landing shoulder  66   r  and seal  66   s  of the dart may engage the seat  63   s  and seal bore  63   e  of the plug. Continued pumping of the chaser fluid  47  may increase pressure in the workstring bore against the seated shutoff dart  66  until a release pressure is achieved, thereby fracturing the shearable fastener  63   h . The shutoff dart  66  and lock sleeve  63   k  may travel downward until reaching a stop of the shutoff plug  63 , thereby freeing the collet of the latch sleeve  63   v  and releasing the plug from the rest of the plug release system  55 . 
         [0081]    Referring specifically to  FIG. 5C , continued pumping of the chaser fluid  47  may drive the first stage cement slurry  95   a  and engaged shutoff dart  66  and plug  63  through the liner bore. The first stage cement slurry  95   a  may be driven downward through the float collar  15   f  and the reamer shoe  15   s  and upward into the annulus  48  until the landing shoulder  63   r  engages the seat of the landing collar  15   c.    
         [0082]    Referring specifically to  FIG. 5D , continued pumping of the chaser fluid  47  may increase pressure in the workstring and liner bore against the seated shutoff dart  66  and plug  63  until the rupture pressure is achieved, thereby rupturing the burst tube  69  and opening the bypass ports of the shutoff plug. A portion of the slug  47   s  may flow around the shutoff dart  66  and through the shutoff plug  63 , thereby allowing the opener dart  67  to reach the opener plug  64 . The landing shoulder  67   r  and seal  67   s  of the opener dart  67  may engage the seat  64   s  and seal bore  64   e  of the opener plug  64 . Continued pumping of the chaser fluid  47  may increase pressure in the workstring bore against the seated opener dart  67  until a release pressure is achieved, thereby fracturing the shearable fastener  64   h . The opener dart  67  and lock sleeve  64   k  may travel downward until reaching a stop of the opener plug  64 , thereby freeing the collet of the latch sleeve  64   v  and releasing the plug from the rest of the plug release system  55 . 
         [0083]    Referring specifically to  FIG. 5E , continued pumping of the chaser fluid  47  may drive the engaged opener dart  67  and plug  64  through the liner bore to the packing stage collar  15   o . The landing shoulder  64   r  and seal thereof may engage the opener seat  76  (and a seal bore thereof) of the packing stage collar  15   o . Continued pumping of the chaser fluid  47  may increase pressure in the workstring and liner bore against the seated opener plug  64  until a release pressure is achieved, thereby fracturing the shearable fasteners  78   u  at the outer interface. The opener dart  67 , plug  64 , and seat  76 , the sleeve  75 , and the closer seat  77  may travel downward until the dogs  79   d  engage a bottom of the slots  790 , thereby aligning the sleeve ports  80   m  with the housing ports  80   h . Rotation  49  of the liner string  15  may then be halted by torsionally disengaging the running tool  53  from the liner string  15  (workstring  9  may then continue to be rotated) or by halting rotation by the top drive  5 . 
         [0084]    Referring specifically to  FIG. 5F , continued pumping of the chaser fluid  47  may open the check valve  85  and inflate the bladder  91  against an exposed wall of the wellbore  24 , thereby isolating the first stage cement slurry  95   a  in a lower portion of the annulus  48  from an upper portion of the annulus. The closer dart  68  may be loaded into the launcher  7   r  or the cementing head  7  may have a third launcher. 
         [0085]    Referring specifically to  FIG. 5G , conditioner  43  may again be circulated by the cement pump  13  through the valve  41  to prepare for pumping of second stage cement slurry  95   b . As the conditioner is being pumped into the workstring bore, pressure may increase until a release pressure is achieved, thereby fracturing the shearable fasteners  78   b . The switch valve  83  may travel downward until reaching the stop of the body  84 , thereby exposing the housing ports to the upper portion of the annulus  48  and allowing circulation of the conditioner  43  through the annulus upper portion. 
         [0086]    Referring specifically to  FIG. 5H , the second stage cement slurry  95   b  may be pumped from the mixer  42  into the cementing swivel  7   c  via the valve  41   c  by the cement pump  13 . Once the desired quantity of the second stage cement slurry  95   b  has been pumped, the closer dart  68  may be released from the launcher  7   r  by operating the launcher actuator. The closer dart  68  and second stage cement slurry  95   b  may be driven through the workstring bore by the chaser fluid  47 . The closer dart  68  may reach the closer plug  65  and the landing shoulder  68   r  and seal  68   s  of the dart may engage the seat  65   s  and seal bore  65   e  of the plug. Continued pumping of the chaser fluid  47  may increase pressure in the workstring bore against the seated closer dart  68  until a release pressure is achieved, thereby fracturing the shearable fastener  65   h . The closer dart  68  and lock sleeve  65   k  may travel downward until reaching a stop of the closer plug  65 , thereby freeing the collet of the latch sleeve  65   v  and releasing the plug from the relief valve  62 . 
         [0087]    Referring specifically to  FIG. 5I , continued pumping of the chaser fluid  47  may drive the engaged closer dart  68  and plug  65  through the liner bore to the packing stage collar  15   o . The second stage cement slurry  95   b  may be driven through the aligned sleeve  80   m  and housing  80   p  ports into the upper annulus portion and upward through the annulus  48  to the liner hanger  15   h.    
         [0088]    Referring specifically to  FIG. 5J , the landing shoulder  65   r  may engage the closer seat  77  and continued pumping of the chaser fluid  47  may increase pressure in the workstring and liner bore against the seated closer plug  65  until a release pressure is achieved, thereby fracturing the shearable fasteners  78   u  at the inner interface. The closer dart  68 , plug  65 , and seat  77 , may travel downward until a bottom of the closer seat  77  engages the sleeve shoulder, thereby freeing the dogs  79   d . The opener and closer darts  67 ,  68 , plugs  64 ,  65 , and seats  76 ,  77  and the sleeve  75  may travel downward until a bottom of the sleeve engages a top of the body  84 , thereby closing the stage valve  71 . 
         [0089]      FIG. 5K  illustrates setting of the packer  15   p . The workstring  9  (except for the lock sleeve and debris barrier  51 ) may be raised until the actuator cylinder top engages the lock sleeve bottom. Continued raising may exert a threshold force to fracture shearable fasteners, thereby releasing the lock sleeve from the debris barrier  51 . Continued raising may move the lock sleeve from engagement with dogs of the latch  61  and release the debris barrier  51  from the PBR  15   r . The raising may continue and torsional profiles of the cylinder and debris barrier may engage. The raising may continue until the packer actuator  59  exits the PBR  15   r , thereby allowing the dogs thereof to extend and engage the PBR top. 
         [0090]    The workstring  9  may be rotated and lowered, thereby exerting weight on the PBR  15   r  via the engaged dogs. The PBR  15   r  may in turn exert the weight on the packer upper portion. A shearable fastener may fracture, thereby releasing the packer upper portion from the liner mandrel  15   m  and expanding the packer  15   p  into engagement with the casing  25 . The packer  15   p  may be restrained from unsetting by a ratchet connection. The workstring  9  may then be raised, thereby rotating the debris barrier  51  via the engaged cylinder torsional profile and chaser fluid circulated to ream and wash away any excess second stage cement slurry  95   b . The workstring  9  may then be retrieved to the MODU  1   m.    
         [0091]    Alternatively, the shutoff dart  66  and plug  63  may be omitted and the lower portion of the annulus  48  not be cemented. This alternative may be especially useful for a lower portion of the liner string  15  being slotted, sand screen, or expandable sand screen instead of solid liner joints  15   j.    
         [0092]    Alternatively, the stage valve  71  may be assembled as part of the liner string  15  without the inflator  72  and packer  73 . In this alternative, the first stage cement slurry  95   a  would be allowed to cure before pumping the second stage cement slurry. 
         [0093]    Alternatively, the stage valve  71  and a separate packer may be assembled as part of the liner string  15  and the shutoff plug  63  used to inflate the separate packer. 
         [0094]    Alternatively, the plug release system  55 , darts  66 - 68 , and packing stage collar  15   o  (or any alternatives discussed above) may be used to cement a subsea casing string into the wellbore  24  instead of the liner string  15 . The subsea casing string may extend to and be hung from the subsea wellhead  10 . 
         [0095]    While the foregoing is directed to embodiments of the present disclosure, other and further embodiments of the disclosure may be devised without departing from the basic scope thereof, and the scope of the invention is determined by the claims that follow.