Patent Publication Number: US-9416620-B2

Title: Cement pulsation for subsea wellbore

Description:
BACKGROUND OF THE DISCLOSURE 
     1. Field of the Disclosure 
     The present disclosure generally relates to cement pulsation for a subsea wellbore. 
     2. Description of the Related Art 
     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 tubular string, such 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 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 section of casing is lowered into the wellbore. An annulus is thus formed between the string of casing and the formation. The casing string is cemented into the wellbore by circulating cement into the annulus 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. 
     It is common to employ more than one string of casing or liner in a wellbore. In this respect, the well is drilled to a first designated depth with a drill bit on a drill string. The drill string is removed. A first string of casing is then run into the wellbore and set in the drilled out portion of the wellbore, and cement is circulated into the annulus behind the casing string. Next, the well is drilled to a second designated depth, and a second string of casing or liner, is run into the drilled out portion of the wellbore. If the second string is a liner string, the liner is set at a depth such that the upper portion of the second string of casing overlaps the lower portion of the first string of casing. The liner string may then be hung off of the existing casing. The second casing or liner string is then cemented. This process is typically repeated with additional casing or liner strings until the well has been drilled to total depth. In this manner, wells are typically formed with two or more strings of casing/liner of an ever-decreasing diameter. 
     The migration of gas from a hydrocarbon bearing formation into the cement slurry may occur after the cement has been pumped, but before it has fully cured. The consequences include gas cut cement, sustained casing pressure, and/or blow outs to the surface. The control of gas migration is one of the most costly and challenging technical problems in well cementing. The basic cause of gas migration is believed to be the loss of hydrostatic pressure within the cement column as it makes the transformation from a liquid slurry to a solid. The development of gel strength in the static column of the curing cement slurry is primarily responsible for this loss of hydrostatic pressure. This loss of hydrostatic pressure allows an influx of gas before the cement slurry has completed the curing process. 
     Gas migration can be prevented if gelling of the cement slurry can be prevented or delayed until the cement slurry develops enough viscosity to prevent the movement of gas within the slurry. Gelling can be disrupted by mechanical agitation, such as by rotation of the casing or liner string. However, rotation must be stopped when the drag on the casing or liner string at the bottom of the well becomes too high and before torque builds to the point that the casing or liner string might be twisted off. This may occur before the cement slurry is viscous enough to prevent gas migration at shallower depths because the cement slurry tends to cure faster at the bottom of the wellbore due to the higher temperature. Gas pulsation has also been used to disrupt gelling in subterranean and shallow water wells having surface wellheads but is unsuitable for deeper wells having subsea wellheads due to the risk of riser collapse and/or buoyancy destabilization of the floating offshore drilling unit. 
     SUMMARY OF THE DISCLOSURE 
     The present disclosure generally relates to cement pulsation for a subsea wellbore. In one embodiment, a method for cementing a tubular string into a wellbore from a drilling unit includes: running the tubular string into the wellbore using a workstring; hanging the tubular string from a wellhead or from a lower portion of a casing string set in the wellbore; and pumping cement slurry through the workstring and tubular string and into an annulus formed between the tubular string and the wellbore. The method further includes, during thickening of the cement slurry: circulating a liquid or mud through a loop closed by a seal engaged with an outer surface of the workstring, the closed loop being in fluid communication with the annulus, and periodically choking the liquid or mud, thereby pulsing the cement slurry. 
     In another embodiment, a method for cementing a tubular string into a subsea wellbore from an offshore drilling unit includes: running the tubular string into the subsea wellbore using a workstring; hanging the tubular string from a subsea wellhead or from a lower portion of a casing string set in the subsea wellbore; pumping cement slurry through the workstring and tubular string and into an annulus formed between the tubular string and the subsea wellbore; closing a seal against an outer surface of the workstring and closing a return line, thereby forming a closed heave chamber in fluid communication with the annulus; and maintaining the closed heave chamber during thickening of the cement slurry, thereby utilizing heaving of the offshore drilling unit to pulsate the cement slurry. 
     In another embodiment, a method for cementing a tubular string into a subsea wellbore from an offshore drilling unit includes: running the tubular string into the subsea wellbore using a workstring having a deployment assembly; hanging the tubular string from a subsea wellhead or from a lower portion of a casing string set in the subsea wellbore; pumping cement slurry through the workstring and tubular string and into an annulus formed between the tubular string and the subsea wellbore; releasing the deployment assembly from the tubular string; raising the deployment assembly from the tubular string to accommodate heave; and anchoring the workstring to the offshore drilling unit. The method further includes, during thickening of the cement slurry and while a seal is engaged with an outer surface of the workstring: using a heave sensor to monitor the heave, injecting liquid or mud into a return line in fluid communication with the annulus during a swab stroke of the heave, the liquid or mud being injected upstream of a fast acting choke valve, and operating the fast acting choke valve to dampen a pulse exerted on the cement slurry by the heave. 
    
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
       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. 
         FIGS. 1A-1C  illustrate a drilling system in a cement injection mode, according to one embodiment of this disclosure. 
         FIGS. 2A-2C  illustrate injection of cement slurry into a casing annulus using the drilling system. 
         FIGS. 3A-3C  illustrate operation of the drilling system in a cement pulsation mode during curing of the cement slurry. 
         FIG. 4  illustrates completion of the cementing operation. 
         FIG. 5  illustrates operation of a first alternative drilling system in a cement pulsation mode during curing of the cement slurry, according to another embodiment of this disclosure. 
         FIGS. 6A-6C  illustrate operation of a second alternative drilling system in a cement pulsation mode during curing of the cement slurry, according to another embodiment of this disclosure. 
         FIGS. 7A-7C  illustrate operation of a third alternative drilling system in a cement pulsation mode during curing of the cement slurry, according to another embodiment of this disclosure. 
         FIGS. 8A-8G  illustrate operation of a fourth alternative drilling system in a cement pulsation mode during curing of the cement slurry, according to another embodiment of this disclosure. 
         FIG. 9  illustrates cement pulsation during curing of a temporary abandonment cement plug, according to another embodiment of this disclosure. 
         FIG. 10  illustrates cement pulsation of curing cement slurry in an annulus of a liner string, according to another embodiment of this disclosure. 
     
    
    
     DETAILED DESCRIPTION 
       FIGS. 1A-1C  illustrate a drilling system  1  in a cement injection 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  1   t , a pressure control assembly (PCA)  1   p , and a workstring  9 . 
     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 . 
     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. 
     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  54  ( FIG. 2A ) 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 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 . 
     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. Alternatively, 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. 
     In the deployment mode, 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 casing deployment assembly (CDA)  9   d  and a deployment string, such as such as joints of drill pipe  9   p  connected together, such as by threaded couplings. An upper end of the CDA  9   d  may be connected a lower end of the drill pipe  9   p , such as by threaded couplings. The CDA  9   d  may be connected to the inner casing string  15 , such as by engagement of a bayonet lug with a mating bayonet profile formed in an upper end of the inner casing string  15 . The inner casing string  15  may include a packer  15   p , a casing hanger  15   h , a mandrel  15   m  for carrying the hanger and packer and having a seal bore formed therein, joints of casing  15   j , a float collar  15   c , and a guide shoe  15   s . The inner casing components may be interconnected, such as by threaded couplings. 
     Once deployment of the inner casing string  15  has concluded, 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   h , a cementing swivel  7   c , one or more release plug launchers, such as a first dart launcher  7   a  and a second dart launcher  7   b , and a control console  7   e . The isolation valve  6  may be connected to a quill of the top drive  5  and an upper end of the actuator swivel  7   h , such as by threaded couplings. An upper end of the workstring  9  may be connected to a lower end of the cementing head  7 , such as by threaded couplings. 
     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 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, 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 cementing mandrel port may provide fluid communication between a bore of the cementing head and the housing inlet. The actuator swivel  7   h  may be similar to the cementing swivel  7   c  except that the housing may have three inlets in fluid communication with respective passages formed through the mandrel. The mandrel passages may extend to respective outlets of the mandrel for connection to respective hydraulic conduits (only one shown) for operating respective hydraulic actuators of the dart launchers  7   a,b . The actuator swivel inlets may be in fluid communication with a hydraulic power unit (HPU, not shown) operated by the control console  7   e.    
     Each dart launcher  7   a,b  may include a body, a diverter, a canister, a latch, and the actuator. Each body may be tubular and may have a bore therethrough. To facilitate assembly, each body may include two or more sections connected together, such as by threaded couplings. An upper end of the top dart launcher body may be connected to a lower end of the actuator swivel  7   h , such as by threaded couplings and a lower end of the bottom dart launcher body may be connected to the workstring  9 . Each body may further have a landing shoulder formed in an inner surface thereof. Each canister and diverter may each be disposed in the respective body bore. Each diverter may be connected to the respective body, such as by threaded couplings. Each canister may be longitudinally movable relative to the respective body. Each canister may be tubular and have ribs formed along and around an outer surface thereof. Bypass passages may be formed between the ribs. Each canister may further have a landing shoulder formed in a lower end thereof corresponding to the respective body landing shoulder. Each diverter may be operable to deflect fluid received from a cement line  14  away from a bore of the respective canister and toward the bypass passages. A release plug, such as a top dart  43   u  or a bottom dart  43   b , may be disposed in the respective canister bore. 
     Each latch may include a body, a plunger, and a shaft. Each latch body may be connected to a respective lug formed in an outer surface of the respective launcher body, such as by threaded couplings. Each plunger may be longitudinally movable relative to the respective latch body and radially movable relative to the respective launcher body between a capture position and a release position. Each plunger may be moved between the positions by interaction, such as a jackscrew, with the respective shaft. Each shaft may be longitudinally connected to and rotatable relative to the respective latch body. Each actuator may be a hydraulic motor operable to rotate the shaft relative to the latch body. 
     Alternatively, the actuator swivel and launcher actuators may be pneumatic or electric. Alternatively, the dart launcher actuators may be linear, such as piston and cylinders. 
     In operation, when it is desired to launch one of the darts  43   u,b , the console  7   e  may be operated to supply hydraulic fluid to the appropriate launcher actuator via the actuator swivel  7   h . The selected launcher actuator may then move the plunger to the release position (not shown). The respective canister and dart  43   u,b  may then move downward relative to the body until the landing shoulders engage. Engagement of the landing shoulders may close the respective canister bypass passages, thereby forcing fluid to flow into the canister bore. The fluid may then propel the respective dart  43   u,b  from the canister bore into a lower bore of the body and onward through the workstring  9 . 
     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. 
     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  60  ( FIG. 3A ) 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 . 
     The diverter  19  may include an outer housing  19   h  ( FIG. 3A ), a latch, an actuator, and an inner packer  19   p . The housing  19   h  may include a plurality of sections connected together and the actuator may be disposed between adjacent sections of the housing and in fluid communication with a actuator hydraulic port formed through a wall of the housing. The actuator may include a resilient ring inwardly displaceable by injection of hydraulic fluid to the actuator port. The packer  19   p  may be releasably connected to the housing by engagement with the latch. The latch may be connected to the housing  19   h  and in fluid communication with a hydraulic latch port formed through the housing wall. The latch may be engaged and disengaged by the application and removal of hydraulic fluid to the latch port. The resilient ring may be engagable with an outer surface of a packing element of the packer  19   p  and may drive the packing element inward into engagement with the drill pipe  9   p.    
     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 an outer casing string  25  may be deployed into the wellbore. The outer 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 outer 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). 
     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. 
     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.    
     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. 
     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. 
     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 . 
     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. 
     Alternatively, the umbilical may be extended between the MODU and the PCA independently of the riser. Alternatively, the shutoff valve actuators may be electrical or pneumatic. 
     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   k,r , a cement mixer  42 , a well control (WC) choke  45 , the MGS  46 , and a relief valve  49 . In the drilling mode, the tank  35  may be filled with drilling fluid, such as mud (not shown). In the casing deployment mode, the tank  35  may be filled with conditioner  55  ( FIG. 2A ). In the cement injection 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.    
     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 , a return shutoff valve  41   r , and the relief valve  49  may be assembled as part of the return line  40 . The relief valve  49  may be pressure operated and have an inlet in fluid communication with a portion of the return line  40  upstream of the return shutoff valve  41   r  and an outlet in fluid communication with a portion of the return line downstream of the shutoff valve  41   r . 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 the cementing swivel inlet 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 . 
     The CDA  9   d  may include a running tool  50 , a plug release system  52 ,  53   u,b , and a packoff  51 . The packoff  51  may be disposed in a recess of a housing of the running tool  50  and carry inner and outer seals for isolating an interface between the inner casing string  15  and the CDA  9   d  by engagement with the seal bore of the mandrel  15   m . The running tool housing may be connected to a housing of the plug release system  52 ,  53   u,b , such as by threaded couplings. 
     The plug release system  52 ,  53   u,b  may include an equalization valve  52 , a top wiper plug  53   u  and a bottom wiper plug  53   b . The equalization valve  52  may include a housing, an outer wall, a cap, a piston, a spring, a collet, and a seal insert. The housing, outer wall, and cap may be interconnected, such as by threaded couplings. The piston and spring may be disposed in an annular chamber formed radially between the housing and the outer wall and longitudinally between a shoulder of the housing and a shoulder of the cap. The piston may divide the chamber into an upper portion and a lower portion and carry a seal for isolating the portions. The cap and housing may also carry seals for isolating the portions. The spring may bias the piston toward the cap. The cap may have a port formed therethrough for providing fluid communication between an annulus  48  formed between the inner casing string  15  and the wellbore  24 /outer casing string  25  and the chamber lower portion and the housing may have a port formed through a wall thereof for venting the upper chamber portion. An outlet port may be formed by a gap between a bottom of the housing and a top of the cap. As pressure from the annulus  48  acts against a lower surface of the piston through the cap passage, the piston may move upward and open the outlet port to facilitate equalization of pressure between the annulus and a bore of the housing to prevent surge pressure from prematurely releasing one or more of the wiper plugs  53   u,b.    
     Each wiper plug  53   u,b  may be made from a drillable material and include a respective finned seal, a plug body, a latch sleeve, and a lock sleeve. Each latch sleeve may have a collet formed in an upper end thereof and the top latch sleeve may have a respective collet profile formed in a lower portion thereof. Each lock sleeve may have a respective seat and seal bore formed therein. Each lock sleeve may be movable between an upper position and a lower position and be releasably restrained in the upper position by a respective shearable fastener. Each dart  43   u,b  may be made from a drillable material and include a respective finned seal and dart body. Each dart body may have a respective landing shoulder and carry a respective landing seal for engagement with the respective seat and seal bore. A major diameter of the bottom landing shoulder may be less than a minor diameter of the top seat such that the bottom dart  43   b  may pass through the top wiper plug  53   u.    
     The top shearable fastener may releasably connect the top lock sleeve to the valve housing and the top lock sleeve may be engaged with the valve collet in the upper position, thereby locking the valve collet into engagement with the collet of the top latch sleeve. The bottom shearable fastener may releasably connect the bottom lock sleeve to the top latch sleeve and the bottom lock sleeve may be engaged with the collet of the bottom latch sleeve, thereby locking the collet into engagement with the collet profile of the bottom latch sleeve. The bottom wiper plug  53   b  may include one or more bypass ports formed through a wall of the bottom lock sleeve initially sealed by a burst tube to prevent fluid flow therethrough. The burst tube may be adapted to rupture when a pressure is applied thereto and a rupture pressure of the burst tube may be substantially greater than a release pressure necessary to fracture the bottom shearable fastener of the bottom wiper plug  50   b.    
     To facilitate subsequent drill-out, each plug body may further have a portion of an auto-orienting torsional profile formed at a longitudinal end thereof. The top plug body may have the female portion and male portion formed at respective upper and lower ends thereof (or vice versa). The bottom plug body may have only the male portion formed at the lower end thereof. 
     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 body may have a bore formed therethrough and the torsional profile female portion formed in an upper end thereof for receiving the bottom wiper plug  53   b . 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 inner casing string  15 , the conditioner  55  may be circulated to prepare the annulus  48  for cementing. The conditioner  55  may be pumped down at a sufficient pressure to overcome the bias of the spring, actuating the poppet downward to allow conditioner to flow through the bore of the body. 
     The guide shoe  15   s  may include a housing and a nose made from a drillable material. The nose may have a rounded distal end to guide the inner casing  15  down into the wellbore  24 . 
     During deployment of the inner casing string  15 , the workstring  9  may be lowered by the traveling block  11   t  and the conditioner  55  may be pumped into the workstring bore by the mud pump  34  via the mud line  39  and top drive  5 . The conditioner  55  may flow down the workstring bore and the liner string bore and be discharged by the guide shoe  15   s  into the annulus  48 . The conditioner  55  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 conditioner  55  may exit the riser annulus and enter the return line  40  via an annulus of the UMRP  16   u  and the diverter  19 . The conditioner  55  may flow through the return line  40  and into the shale shaker inlet. The conditioner  55  may be processed by the shale shaker  36  to remove any particulates therefrom. 
     The workstring  9  may be lowered until the inner casing hanger  15   h  seats against a mating shoulder of the subsea wellhead  10 . The workstring  9  may continued to be lowered, thereby releasing a shearable connection of the casing hanger  15   h  and driving a cone thereof into dogs thereof, thereby extending the dogs into engagement with a profile of the wellhead  10  and setting the hanger. 
       FIGS. 2A-2C  illustrate injection of cement slurry  56  into the annulus  48  using the drilling system  1 . Once the inner casing hanger  15   h  has been set, the inner casing string may be rotated  54  by operation of the top drive  5  (via the workstring  9 ) and rotation may continue during injection of the cement slurry  56 . The bottom dart  43   b  may be released from the first launcher  7   a  by operating the first plug launcher actuator. Cement slurry  56  may be pumped from the mixer  42  into the cementing swivel  7   c  via the valve  41   c  by the cement pump  13 . The cement slurry  56  may flow into the second launcher  7   b  and be diverted past the top dart  43   u  via the diverter and bypass passages. The cement slurry  56  may flow into the first launcher  7   a  and be forced behind the bottom dart  43   b  by closing of the bypass passages, thereby propelling the bottom dart into the workstring bore. 
     Once the desired quantity of cement slurry  56  has been pumped, the top dart  43   u  may be released from the second launcher  7   b  by operating the second plug launcher actuator. The chaser fluid  47  may be pumped into the cementing swivel  7   c  via the valve  41  by the cement pump  13 . The chaser fluid  47  may flow into the second launcher  7   b  and be forced behind the bottom dart  43   b  by closing of the bypass passages, thereby propelling the second 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 train of darts  43   u,b  and cement slurry  56  may be driven through the workstring bore by the chaser fluid  47 . The bottom dart  43   b  may reach the bottom wiper plug  53   b  and the landing shoulder and seal of the bottom dart may engage the seat and seal bore of the bottom wiper plug. 
     Continued pumping of the chaser fluid  47  may increase pressure in the workstring bore against the seated bottom dart  43   b  until the release pressure is achieved, thereby fracturing the bottom shearable fastener. The bottom dart  43   b  and lock sleeve of the bottom wiper plug  53   b  may travel downward until reaching a stop of the bottom wiper plug, thereby freeing the collet of the bottom latch sleeve and releasing the bottom wiper plug from the top wiper plug  53   u . The released bottom dart  43   b  and bottom wiper plug  53   b  may travel down the bore of the inner casing string  15  wiping the inner surface thereof and forcing the conditioner  55  therethrough. The top dart  43   u  may then reach the top wiper plug  53   u  and the landing shoulder and seal of the top dart may engage the seat and seal bore of the top wiper plug. 
     Continued pumping of the chaser fluid  47  may increase pressure in the workstring bore against the seated top dart  43   u  until the release pressure is achieved, thereby fracturing the top shearable fastener. The top dart  43   u  and lock sleeve of the top wiper plug  53   u  may travel downward until reaching a stop of the top wiper plug, thereby freeing the collet of the top latch sleeve and releasing the top wiper plug from the equalization valve  52 . Continued pumping of the chaser fluid  47  may drive the train of darts  43   u,b , wiper plugs  53   u,b , and cement slurry  56  through the inner casing bore until the bottom wiper plug  53   b  bumps the float collar  15   c.    
     Continued pumping of the chaser fluid  47  may increase pressure in the inner casing bore against the seated bottom dart  43   b  and bottom wiper plug  53   b  until the rupture pressure is achieved, thereby rupturing the burst tube and opening the bypass ports of the bottom wiper plug. The cement slurry  56  may flow around the bottom dart  43   b  and through the bottom wiper plug  53   b  and the guide shoe  15   s , and upward into the annulus  48 . 
     Pumping of the chaser fluid  47  may continue to drive the cement slurry  56  into the annulus  48  until the top wiper plug  53   u  bumps the seated bottom wiper plug  53   b . Pumping of the chaser fluid  47  may then be halted and rotation  54  of the inner casing string  15  may also be halted. The float collar check valve may close in response to halting of the pumping. 
       FIGS. 3A-3C  illustrate operation of the drilling system  1  in a cement pulsation mode during curing of the cement slurry  56 . The bayonet connection between the CDA  9   d  and the inner casing string  15  may be released. The cementing head  7  (minus the isolation valve  6 ) may be removed and the workstring  9  connected to the isolation valve  6  and raised to create sufficient clearance between the equalization valve  52  and the casing hanger  15   h  to accommodate heave  60  of the workstring  9 . The spider  4   s  may then be operated to engage the drill pipe  9   p , thereby longitudinally supporting the workstring  9  from the rig floor  4   f . However, once the workstring  9  is supported from the rig floor  4   f , the drill string compensator  8  can no longer alleviate heaving of the workstring with the MODU  1   m  (depicted by phantom). 
     A trip tank  57  filled with conditioner  55  may connected to the diverter  19  via spool  58 . The spool  58  may have a check valve  59  assembled as part thereof. The check valve  59  may be oriented to allow fluid flow from the trip tank  57  to the diverter  19  and prevent reverse flow from the diverter to the trip tank. The packing element of the diverter  19  may be expanded into engagement with the drill pipe  9   p  by supplying hydraulic fluid to the actuator port thereof. The isolation valve  6  and the return shutoff valve  41   r  may be closed, thereby creating a heave chamber  61 . The heave chamber  61  may be closed to contain positive pressure (below a set pressure of the relief valve  49 ) at an upper portion via the check valve  59 , the closed diverter packer  19   p , the closed return valve  41   r , and the closed isolation valve  6  and at a lower portion via the top dart  43   u  and top wiper plug  53   u . The heave chamber  61  may be in fluid communication with the annulus  48  due to the casing packer  15   p  being in the unset position. The conditioner  55  and chaser fluid  47  may each be a liquid or mud. The heave chamber  61  may be purged of any gas present therein such that the heave chamber  61  and annulus  48  are filled with the relatively incompressible conditioner  55 , chaser fluid  47 , and cement slurry  56 . 
     Alternatively, the workstring or top drive may have a check valve for automatically closing the bore of the workstring instead of the isolation valve. 
     The workstring  9  and MODU  1   m  may then heave  60  relative to the stationary riser string  17  (due to the slip joint  21 ), PCA  1   p , subsea wellhead  10 , and inner casing string  15 . Heaving  60  of the workstring  9  may include an upward stroke and a downward stroke. Displacement of fluid volume by the drill pipe  9   p  may cause a corresponding surge in pressure of the heave chamber  61  during the downward stroke and a corresponding swab of pressure of the heave chamber during the upward stroke. Addition of the conditioner  55  from the trip tank  57  may negate the swab from the upward stroke of the heave  60 , thereby leaving positive pressure pulses  62  from the repeated downward strokes. The pulses  62  may disrupt gelling of the cement slurry  56  and pulsing may continue until the entire column of the cement slurry  56  has thickened sufficiently to prevent gas migration. The thickening time may be predetermined and may range between two and twelve hours, such as four to six hours. The thickening time may be determined empirically by laboratory testing and/or theoretically by computer modeling or provided by the vendor of the cement pre-mixture. 
     The relief valve  49  may be set at a pressure corresponding to, such as equal to or slightly less than, a maximum allowable pressure of the lower formation  27   b , such as a fracture pressure thereof, minus the bottomhole pressure generated by the hydrostatic head of the cement slurry  56  plus the hydrostatic head of the conditioner  55  to ensure that the heave pulses  62  do not overpressure the lower formation  27   b . A magnitude of the pulses  62  may be low compared to the bottomhole pressure, such as less than or equal to one-fifth, one-tenth, or one-twentieth of the bottomhole pressure. In absolute terms, a magnitude of the heave pulses  62  may range from fifty to five hundred psi, such as between eighty and two hundred psi. 
       FIG. 4  illustrates completion of the cementing operation. Once the cement slurry  56  has cured to the thickened state, the spider  4   s  may be operated to release the workstring  9  and the workstring lowered to reengage the CDA  9   d  with the casing hanger  15   h . The bayonet connection may be reconnected and continued lowering of the workstring  9  may drive a wedge of the casing packer  15   p  into a metallic seal ring thereof, thereby extending the seal ring into engagement with a seal bore of the wellhead  10  and setting the packer. The bayonet connection may be released and the workstring  9  may be retrieved to the rig  1   r.    
       FIG. 5  illustrates operation of a first alternative drilling system in a cement pulsation mode during curing of the cement slurry  56 , according to another embodiment of this disclosure. The first alternative drilling system may be similar to the drilling system  1  except for modification of the diverter  19  by removing the packer  19   p  from the diverter housing  19   h  and adding a rotating control device (RCD) converter  63  thereto so that the CDA  9   d  may remain engaged to the casing packer  15   p  and the drill string compensator  8  may remain operational during pulsation by the workstring  9  being suspended from the top drive  5 . The heave pulses  62  may instead be generated by the heaving  60  of the modified diverter  19   h ,  63 , flex joint  20 , and the inner barrel of the slip joint  21  relative to the stationary drill pipe  9   p.    
     The RCD converter  63  may include a housing having an upper section and lower section. The upper housing section may include a circumferential flange, which may be positioned on the diverter housing. The lower housing section may include a cylindrical insert and an upset ring. The upper housing section may be connected with the lower housing section, such as by threaded couplings. One or more anti-rotation pins may be placed through aligned openings in the threaded connection between the upper and lower housing sections. The upset ring may be connected to the cylindrical insert, such as by threaded couplings. A seal sleeve may be disposed along and around an outer surface of the cylindrical insert and may be disposed between a conical upper portion of the insert and the upset ring. Expansion of the diverter actuator ring against the seal sleeve may both fasten the RCD converter  63  to the diverter housing  19   h  and seal the interface therebetween. 
     The RCD converter  63  may further include a bearing assembly fastened to the upper housing section, such as by a clamp. The bearing assembly may include an outer sleeve, a dynamic seal, such as a stripper, and a bearing pack. The stripper may include a retainer and a seal. The stripper seal may be directional and oriented to seal against drill pipe  9   p  in response to higher pressure in the UMRP  16   u  than the environment. The stripper seal may have a conical shape for fluid pressure to act against a respective tapered surface thereof, thereby generating sealing pressure against the drill pipe  9   p . The stripper seal may have an inner diameter slightly less than a pipe diameter of the drill pipe  9   p  to form an interference fit therebetween. 
     The stripper seal may be flexible enough to accommodate and seal against threaded couplings of the drill pipe  9   p  having a larger tool joint diameter. The drill pipe  9   p  may be received through a bore of the bearing assembly so that the stripper seal may engage the drill pipe  9   p . The stripper seal may be better suited to withstand the heave of the diverter  19  relative to the drill pipe  9   p  as compared to the packing element of the diverter packer  19   p . The bearing pack may support the stripper from the outer sleeve such that the strippers may rotate relative to the converter housing. The bearing pack may include one or more radial bearings, one or more thrust bearings, and a self contained lubricant system. The bearing pack may be disposed above the stripper and be housed in and connected to the outer sleeve, such as by threaded couplings and/or fasteners. 
     Alternatively, for either or both of the drilling system  1  or the first alternative drilling system, immediately after the top wiper plug  53   u  bumps the bottom wiper plug  53   b  and the heave chamber  61  has been created, a shutoff valve of the booster manifold and a shutoff valve of one of the choke prongs may be opened. The booster pump  44  may be operated to pump conditioner  55  down the booster line  18   b  and into the PCA  1   p . The conditioner  55  may flow from the PCA  1   p  and up the choke line  18   k  and through the WC choke  45 . The WC choke  45  may be set to exert a predetermined back pressure on the cement slurry  56  in the annulus  48 . Once the back pressure has been achieved, the booster pump  44  may be shut down while closing the shutoff valve of the booster manifold and the shutoff valve of the choke prong, thereby sealing the annulus  48  with the exerted back pressure. The back pressure may protect against U-tubing of the cement slurry  56  and/or dislodgement of the wiper plugs  53   u,b  during heave pulsing of the cement slurry. 
       FIGS. 6A-6C  illustrate operation of a second alternative drilling system  65  in a cement pulsation mode during curing of the cement slurry  56 , according to another embodiment of this disclosure. The drilling system  65  may include the MODU  1   m , the drilling rig  1   r , a fluid handling system  65   h , a fluid transport system  65   t , the PCA  1   p , and the workstring  9 . 
     The fluid transport system  65   t  may include an UMRP  64 , the marine riser  17 , the booster line  18   b , and the choke line  18   k . The UMRP  64  may include the diverter  19 , the flex joint  20 , the slip joint  21 , the tensioner  22 , and an RCD  66 . A lower end of the RCD  66  may be connected to an upper end of the riser  17 , such as by a flanged connection. The slip joint outer barrel may be connected to an upper end of the RCD  66 , such as by a flanged connection. 
     The RCD  66  may include a docking station and a bearing assembly. The docking station may be submerged adjacent the waterline  2   s . The docking station may include a housing, a latch, and an interface. The RCD housing may be tubular and have one or more sections connected together, such as by flanged connections. The RCD housing may have one or more fluid ports formed through a lower housing section and the docking station may include a connection, such as a flanged outlet, fastened to one of the ports. 
     The latch may include a hydraulic actuator, such as a piston, one or more fasteners, such as dogs, and a body. The latch body may be connected to the housing, such as by threaded couplings. A piston chamber may be formed between the latch body and a mid housing section. The latch body may have openings formed through a wall thereof for receiving the respective dogs. The latch piston may be disposed in the chamber and may carry seals isolating an upper portion of the chamber from a lower portion of the chamber. A cam surface may be formed on an inner surface of the piston for radially displacing the dogs. The latch body may further have a landing shoulder formed in an inner surface thereof for receiving a protective sleeve (not shown) or the bearing assembly. 
     Hydraulic passages may be formed through the mid housing section and may provide fluid communication between the interface and respective portions of the hydraulic chamber for selective operation of the piston. An RCD umbilical may have hydraulic conduits and may provide fluid communication between the RCD interface and a HPU (not shown). The RCD umbilical may further have an electric cable for providing data communication between a control console (not shown) and the RCD interface via a controller. 
     The bearing assembly may include a catch sleeve, one or more dynamic seals, such as strippers, and a bearing pack. Each stripper may include a gland or retainer and a seal. Each stripper seal may be directional and oriented to seal against drill pipe  9   p  in response to higher pressure in the riser  17  than the UMRP  64 . Each stripper seal may have a conical shape for fluid pressure to act against a respective tapered surface thereof, thereby generating sealing pressure against the drill pipe  9   p . Each stripper seal may have an inner diameter slightly less than a pipe diameter of the drill pipe  9   p  to form an interference fit therebetween. Each stripper seal may be flexible enough to accommodate and seal against threaded couplings of the drill pipe  9   p  having a larger tool joint diameter. The drill pipe  9   p  may be received through a bore of the bearing assembly so that the stripper seals may engage the drill pipe  9   p . The stripper seals may provide a desired barrier in the riser  17  either when the drill pipe  9   p  is stationary, rotating, or heaving. 
     The catch sleeve may have a landing shoulder formed at an outer surface thereof, a catch profile formed in an outer surface thereof, and may carry one or more seals on an outer surface thereof. Engagement of the latch dogs with the catch sleeve may connect the bearing assembly to the docking station. The gland may have a landing shoulder formed in an inner surface thereof and a catch profile formed in an inner surface thereof for retrieval by a bearing assembly running tool. The bearing pack may support the strippers from the catch sleeve such that the strippers may rotate relative to the docking station. The bearing pack may include one or more radial bearings, one or more thrust bearings, and a self contained lubricant system. The bearing pack may be disposed between the strippers and be housed in and connected to the catch sleeve, such as by threaded couplings and/or fasteners. 
     Alternatively, the bearing assembly may be non-releasably connected to the housing. Alternatively, the RCD may be located above the waterline and/or along the UMRP at any other location besides a lower end thereof. Alternatively, the RCD may be assembled as part of the riser at any location therealong or as part of the PCA. Alternatively, an active seal RCD may be used instead. 
     The fluid handling system  65   h  may include the cement pump (not shown), the mud pump  34 , the fluid tank  35 , the shale shaker  36 , the pressure gauge  37   k , the cement line (not shown), the mud line  39 , the cement mixer (not shown), the booster pump  44 , the WC choke  45 , the MGS  46 , one or more pressure sensors  67   m,r , a return line  68 , one or more flow meters  69   b,m,r , a toggle valve  71 , an automated variable choke valve, such as a managed pressure (MP) choke  72 , a gas detector  73 , and one or more shutoff valves  74   a - e.    
     The mud line  39  may have the flow meter  69   m  and the pressure sensor  67   m  assembled as part thereof. An upper end of the booster line  18   b  may have the flow meter  69   b  assembled as part thereof. A lower end of the return line  68  may be connected to an outlet of the RCD  66  and an upper end of the return line may be connected to a first flow tee. The returns pressure sensor  67   r , the toggle valve  71 , the MP choke  72 , the returns flow meter  69   r , the gas detector  73 , and the first shutoff valve  74   a  may be assembled as part of the return line  68 . An upper end of the choke line  18   k  may be connected to a second flow tee and the pressure gauge  37   k , WC choke  45 , and the fifth shutoff valve  74   e  may be assembled as part thereof. A crossover spool may connect the first and second tees and have the fourth shutoff valve  74   d  assembled as part thereof. An MGS spool may connect the first tee and an inlet of the MGS  46  and have the second shutoff valve  74   b  assembled as part thereof. A shaker spool may connect the second tee to an inlet of the shaker  36  and have the fourth shutoff valve  74   d  and a third flow tee assembled as part thereof. A splice line may connect the third tee to a liquid outlet of the MGS  46 . 
     Each pressure sensor  67   m,r  may be in data communication with a programmable logic controller (PLC)  70 . The returns flow meter  69   r  may be a mass flow meter, such as a Coriolis flow meter, and may be in data communication with the PLC  70 . The returns flow meter  69   r  may be operable to monitor a flow rate of return fluid (drilling returns or conditioner  55 , depending on the operation being conducted). Each of the flow meters  69   b,m  may be a volumetric flow meter, such as a Venturi flow meter, and may be in data communication with the PLC  70 . The flow meter  69   m  may be operable to monitor a flow rate of the mud pump  34 . The flow meter  69   b  may be operable to monitor a flow rate of the booster pump  44 . The PLC  70  may have a density measurement of the conditioner  55  or chaser fluid  47  to determine a mass flow rate of the particular fluid from the volumetric measurement of the flow meters  69   b,m.    
     Alternatively, a stroke counter may be used to monitor a flow rate of the mud pump and/or booster pump instead of the volumetric flow meters. Alternatively, either or both of the volumetric flow meters may be mass flow meters. 
     The gas detector  73  may be operable to extract a gas sample from the return fluid to detect contamination by formation fluid (not shown) and analyze the captured sample to detect hydrocarbons and/or non-hydrocarbon components of the sample. The gas detector  73  may include a body, a probe, a chromatograph, and a carrier/purge system. The carrier/purge system may be connected to the probe and a carrier gas may be injected into the probe inlet to displace sample gas trapped therein. The carrier/purge system may then transport the sample gas to the chromatograph for analysis. The carrier purge system may also be routinely run to purge the probe of condensate. The chromatograph may be in data communication with the PLC  70  to report the analysis of the sample. 
     The return line  68  may further include a fourth flow tee, a bypass splice line  68   f , and a choke splice line  68   k  assembled as part thereof. The bypass splice line  68   f  may connect a first outlet of the toggle valve  71  to the fourth flow tee and the choke splice line  68   k  may connect the a second outlet of the toggle valve to the fourth flow tee and have the MP choke  72  assembled as part thereof. The MP choke  72  may include a valve  72   v  and a hydraulic actuator  72   a  operated by the PLC  70  via an HPU to generate pulses  75  during curing of the cement slurry  56 . 
     The toggle valve  71  may include a housing, a valve member  71   v , and a linear actuator  71   a  for moving the valve member between an upper position and a lower position. The housing may have an inlet and the first and second outlets formed through a wall thereof. The linear actuator  71   a  may be fast acting, such as a solenoid having a shaft connected to the valve member  71   v  and a coil for longitudinally driving the shaft relative to the housing between the upper and lower positions. The valve member  71   v  may carry seals (four shown) on an outer surface thereof for selectively opening and closing the housing outlets. The valve member  71   v  may have a first passage formed therethrough for opening the first outlet and a second passage formed therethrough for opening the second outlet. The first passage may be straight and straddled by the first and second seals and the second passage may be z-shaped and have an upper portion straddled by the second and third seals and a lower portion straddled by the third and fourth seals. In the upper position, the z-passage may be aligned with the inlet and second outlet while the straight passage is closed and in the lower position, the straight passage may be aligned with the inlet and first outlet while the z-passage is closed. 
     The MP choke  72  may be employed during drilling of the lower formation  27   b . The PLC  70  may periodically increase the bottomhole pressure (BHP) to a test pressure including the hydrostatic pressure of the cement slurry and the desired pulse pressure to verify integrity of the lower formation  27   b . The PLC  70  may increase the BHP to the test pressure by tightening the MP choke  72 . Should the lower formation  27   b  withstand the expected pressure, then the cementing operation may proceed as planned. Should drilling returns leak into the lower formation  27   b  (detected by monitoring the returns flow meter  69   r ) during the test, then the cementing operation may have to be modified, such as by decreasing a magnitude  75   m  of the planned pulses  75  and/or modifying properties of the planned cement slurry  56 . 
     During injection of the cement slurry  56 , the MP choke  72  may be bypassed. The PLC  70  may perform a mass balance using the flow meters  69   m  and  69   r  to ensure that no fluid has been lost to the lower formation  27   b  or fluid from the lower formation has entered the annulus  48 . The PLC  70  may also determine the cement level in the annulus  48 . 
     Once injection of the cement slurry  56  has finished, a shutoff valve of the booster manifold may be opened and the booster pump  44  operated to pump conditioner  55  down the booster line  18   b  and into the PCA  1   p . The conditioner  55  may flow up the LMRP annulus and riser annulus to the RCD  66 . The conditioner  55  may be diverted by the RCD stripper seals into the return line  68 . The conditioner  55  may flow through the toggle valve  71 , the bypass splice line  68   f , the returns flow meter  69   r , the gas detector  73 , the open first shutoff valve  74   a , the crossover spool and open third shutoff valve  74   c , and the shaker spool and open fourth shutoff valve  74   d  into the shale shaker inlet. 
     As the conditioner  55  is circulated through the closed loop, the PLC  70  may periodically reciprocate the toggle valve  71  to the upper position for diverting flow through the MP choke  72  and then back to the lower position to restore flow to the bypass splice line  68   f , thereby generating the choke pulse  75 . The choke pulses  75  may be generated at a relatively low frequency  75   f , such as one pulse every fifteen seconds, thirty seconds, forty-five seconds, sixty seconds, seventy-five seconds, or ninety seconds (or any frequency therebetween). The pulse magnitude  75   m  may be any of the magnitudes discussed above for the heave pulse  62 . The PLC  70  may control the pulse magnitude  75   m  by adjusting a position of the MP choke  75   m  and monitoring the returns pressure sensor  67   r  for feedback. 
     Circulation of the conditioner  55  and pulse generation may be maintained until the entire column of the cement slurry  56  has thickened sufficiently to prevent gas migration. As the conditioner  55  is being circulated, the PLC  70  may perform a mass balance between entry and exit of the conditioner into/from the wellhead  10  to monitor for formation fluid entering the annulus  48  or cement slurry  56  entering the lower formation  27   b  using the flow meters  69   b,r . An injection rate of the booster pump  44  may be increased in response to detection of formation fluid entering the annulus  48  and the PLC  70  may relax the MP choke  72  in response to cement slurry  56  entering the lower formation  27   b . The CDA  9   d  may remain engaged to the casing packer  15   p  and the drill string compensator  8  may remain operational during pulsation. Once the cement slurry  56  has cured to the thickened state, casing packer  15   h  may be set and the workstring  9  retrieved to the rig  1   r.    
     Alternatively, the conditioner may be circulated by an auxiliary pump connected to an inlet of the RCD instead of the booster pump. Alternatively, the RCD may be omitted, the annular BOP  30   a  closed against an outer surface of the drill pipe, and one of the choke line prongs opened as part of the closed circulation loop of the conditioner. Further in this alternative, the bypass splice line, choke splice line and toggle valve may be installed as part of the choke line  18   k  and the WC choke  45  used to generate the choke pulses. 
     The PLC  70  may keep a cumulative record during the cementing and pulsing operation of any fluid ingress/egress events and the PLC may make an evaluation as to the acceptability of the cured cement. The PLC  70  may also include a comparison of the actual cement level to the planned cement level in the evaluation. Should the PLC  70  determine that the cured cement is unacceptable, the PLC may make recommendations for remedial action, such as a cement bond/evaluation log and/or a secondary cementing operation. 
       FIGS. 7A-7C  illustrate operation of a third alternative drilling system in a cement pulsation mode during curing of the cement slurry  56 , according to another embodiment of this disclosure. The third alternative drilling system may be similar to the second alternative drilling system  65  except that a fast acting choke  76  has replaced the toggle valve  71  and the MP choke  72 . 
     The fast acting choke  76  may include an electric actuator, such as a servomotor  76   a , and the valve  72   v . The valve  72   v  may include a body, a bonnet fastened to the body, such as by threaded fasteners, a stem linked to the bonnet, such as by a lead screw, a packing sealing an interface between the stem and the bonnet, a gasket, and a seal. The body may have an inlet and outlet formed at respective longitudinal ends thereof, a chamber formed at a mid portion thereof for receiving the bonnet, and a passage connecting the inlet, outlet, and chamber. The bonnet may have a Venturi formed in an inner surface of a lower end thereof, a seal shoulder formed in an outer surface thereof adjacent to the lower end, and a discharge port formed through a wall thereof. The body may have a landing shoulder formed in an inner surface thereof adjacent to the chamber. The stem may have a flow bean formed at a lower end thereof for selectively throttling the Venturi. The stem and Venturi may be made from an erosion resistant material. The stem may have a torsional coupling formed at an upper end thereof for rotary driving by the servomotor. 
     The servomotor  76   a  may include a driver  78  and a motor  79 . The motor  79  may include a rotor, a stator, and a pair of bearings supporting the rotor for rotation relative to the stator. The rotor may include a hub made from a magnetically permeable material, a plurality of permanent magnets torsionally connected to the hub, and a shaft. The rotor may include one or more pairs of permanent magnets having opposite polarities. The magnets may also be fastened to the hub, such as by retainers. The hub may be torsionally connected to the shaft and fastened thereto. The stator may include a housing, a core, and a plurality of windings, such as three (only two shown). The core may include a stack of laminations made from an electrically permeable material. The stack may have lobes formed therein, each lobe for receiving a respective winding. The core may be longitudinally and torsionally connected to the housing, such as by an interference fit. 
     Alternatively, the motor  79  may be a switched reluctance motor instead of a brushless permanent magnet motor. 
     The motor driver  78  may include a rectifier  78   r , a motor controller  78   c , and a rotor position sensor (not shown). The motor driver  78  may receive a three phase alternating current (AC) power signal from a generator  40  of the MODU  1   m . The rectifier  78   r  may convert the three phase AC power signal to a direct current (DC) power signal and supply the converted DC power signal to the motor controller  78   c . The motor controller  78   c  may have an output for each phase (i.e., three) of the motor  10  and may monitor may modulate the DC power signal to drive each phase winding of the stator based on signals received from the rotor position sensor. 
     The fast acting choke  76  may impart the capability to the third alternative drilling system to exert back pressure during injection and pulsing of the cement slurry  56  such that a density of the cement slurry  56  may correspond to a minimum allowable pressure gradient, such as pore pressure gradient, of the lower formation  27   b . As the conditioner  55  is circulated, the PLC  70  may periodically reciprocate the choke  76  from a looser position, where only back pressure is exerted on the conditioner  55  to a tighter position and then back to the looser position, thereby generating the choke pulse  75  in addition to the back pressure. The PLC  70  may also perform the mass balance during injection of the cement slurry  56  and during circulation of the conditioner  55  for pulsing to evaluate acceptability, as discussed above. The PLC  70  may relax the fast acting choke  76  if fluid loss is detected during injection of the cement slurry  56  and relax the tighter position if fluid loss is detected during pulsing. The PLC  70  may tighten the fast acting choke  76  if formation fluid is detected during injection of the cement slurry  56  and tighten the looser position if formation fluid is detected during pulsing. 
     Alternatively, a second MP choke may be added to the bypass splice line  68   f  of the second alternative drilling system  65  to achieve back pressure capability by setting the first MP choke to generate the back pressure plus the choke pulse and the second MP choke to generate only the back pressure. 
       FIGS. 8A-8G  illustrate operation of a fourth alternative drilling system  80  in a cement pulsation mode during curing of the cement slurry  56 , according to another embodiment of this disclosure. The drilling system  80  may include the MODU  1   m , the drilling rig  1   r , a fluid handling system  80   h , a fluid transport system  80   t , the PCA  1   p , and the workstring  9 . The fluid transport system  80   t  may include an UMRP  80   u , the marine riser  17 , the booster line  18   b , and the choke line  18   k . The UMRP  80   u  may include the diverter  19 , the flex joint  20 , the slip joint  21 , the tensioner  22 , an RCD  66 , a heave sensor  82 , and a heave relief system  81 . 
     The heave sensor  82  may be installed in the slip joint  21  and be in data communication with the PLC  70 . The heave sensor  82  may be a linear variable differential transformer (LVDT) having an outer portion mounted in the outer barrel and a ferromagnetic target ring mounted on a shoulder of the inner barrel. The outer portion may include a central primary coil and a pair of secondary coils straddling the primary coil. The primary coil may be driven by an AC signal and the secondary coils monitored for response signals which may vary in response to a position of the target ring relative to the outer portion. 
     The heave relief system  81  may include a relief vessel  81   a  and a flow line connecting the relief vessel to an outlet of the RCD  66 . A pressure sensor  81   p  and a shutoff valve  81   v  may be assembled as part of the relief line. The shutoff valve  81   v  and pressure sensor  81   p  may be in communication with the PLC  70 . The shutoff valve  81   v  may be normally closed unless the PLC  70  detects the occurrence of a rogue wave. In such an event, the PLC  70  may open the shutoff valve  81   v  to allow the fluid displaced by the drill pipe  9   p  to be relieved to the vessel  81   a  to avoid overpressuring the lower formation  27   b.    
     The fluid handling system  80   h  may include the cement pump (not shown), the mud pump  34 , the fluid tank  35 , the shale shaker  36 , the pressure gauge  37   k , the cement line (not shown), the mud line  39 , the cement mixer (not shown), the booster pump  44 , the WC choke  45 , the MGS  46 , the pressure sensors  67   m,r , a return line  83 , the flow meters  69   b,m,r , the fast acting choke  76 , the gas detector  73 , the shutoff valves  74   a - e , and a hydraulic circuit  84 . A lower end of the return line  83  may be connected to an outlet of the RCD  66  and an upper end of the return line may be connected to the first flow tee. The returns pressure sensor  67   r , the fast acting choke  76 , the returns flow meter  69   r , the gas detector  73 , the first shutoff valve  74   a , and fourth and fifth flow tees may be assembled as part of the return line  83 . 
     The hydraulic circuit  84  may include the check valve  59 , a compensator toggle valve  71 , an intensifier choke  72 , a compensation spool  84   c , a discharge line  84   d , a pulse spool  84   p , a loop spool  84   r , a supply line  84   s , an input spool  84   t , a fluid tank  85  filled with conditioner  55 , an auxiliary pump  86 , a fast acting pulse shutoff valve  87 , a pulse flow meter  88   p , and a compensator flow meter  88   c . The supply line  84   s  may connect an outlet of the tank  85  with an inlet of the auxiliary pump  86 . The discharge line  84   d  may connect an outlet of the auxiliary pump  86  and a sixth flow tee. 
     The input spool  84   t  may connect the sixth flow tee to an inlet of the compensator valve  71  and have the intensifier choke  72  may be assembled as part thereof. The compensator spool  84   c  may connect a first outlet of the compensator valve  71  to the fifth tee and have the check valve  59  and compensator flow meter  88   c  assembled as part thereof. The check valve  59  may be oriented to allow flow from the compensator valve  71  to the return line  83  and prevent reverse flow from the return line  83  to the compensator valve  71 . The loop spool  84   r  may connect a second outlet of the compensator valve  71  to an inlet of the fluid tank  85 . The pulse spool  84   p  may connect the sixth tee to the fourth tee of the return line  83  and have the pulse valve  87  and the pulse flow meter  88   p  assembled as part thereof. 
     Referring specifically to  FIG. 8C , once injection of the cement slurry  56  has finished, the bayonet connection between the CDA  9   d  and the inner casing string  15  may be released. The cementing head  7  (minus the isolation valve  6 ) may be removed and the workstring  9  connected to the isolation valve  6  and raised to create sufficient clearance between the equalization valve  52  and the casing hanger  15   h  to accommodate the heave  60  of the workstring  9 . The spider  4   s  may then be operated to engage the drill pipe  9   p , thereby longitudinally supporting the workstring  9  from the rig floor  4   f.    
     Referring specifically to  FIGS. 8D and 8E , the auxiliary pump  86  may be activated to circulate conditioner  55  through the input spool  84   t  and loop spool  84   r . The booster pump  44  may be left idle (depicted in phantom). The PLC  70  may utilize the heave sensor  82  to operate the fast acting choke  76  to dampen the heave pulse  62   d  by tightening the fast acting choke during a swab stroke of the heave  60  and relaxing the fast acting choke during a surge stroke of the heave. Even using the fast acting choke  76 , there may be some latency (slight lag shown in  FIG. 8D ) between the fast acting choke position and the heave  60 . To maintain the ability of the fast acting choke  76  to exert back pressure during a swab stroke of the heave  60 , the PLC  70  may switch the compensator valve  71  to inject conditioner  55  into the return line  83  during the swab stroke. Once the swab stroke has finished, the PLC  70  may switch the compensator valve  71  back to discharging the conditioner  55  to the fluid tank  85 . 
     Alternatively, the PLC  70  may monitor heaving  60  during injection of the cement slurry  56  to construct a predicted heave model and use the predicted heave model to control the fast acting choke and the compensator valve  71 . 
     Referring specifically to  FIGS. 8F and 8G , as the conditioner  55  is circulated, the intensifier valve  72  may be set to maintain a substantially higher pressure in the pulse spool  84   p  than the compensation  84   c  and return  84   r  spools. The PLC  70  may periodically reciprocate the pulse valve  87  to open and then close, thereby diverting the higher pressure flow of conditioner  55  into the return line  83  against the fast acting choke  76  and generating the choke pulse  75 . The choke pulses  75  may be generated at any of the frequencies and magnitudes discussed above. The pulse frequency may be independent of the heave frequency and may even occasionally coincide with opening of the compensator valve  71  to the return line  83 . The PLC  70  may control the pulse magnitude by adjusting a position of the intensifier choke  72  and/or time that the pulse valve  87  is kept open and monitoring the returns pressure sensor  67   r  for feedback. The PLC  70  may control pulse frequency by adjusting the reciprocation period of the pulse valve  87 . 
     The actual pressure exerted on the cement slurry  56  may be a cumulative effect of the dampened heave pulse  62   d , the hydrostatic pressure of the conditioner  55  in the annulus  48 , the PCA annulus, and the riser annulus, and the choke pulses  75 . The dampened heave pulse  62   d  may cause variation in the effective pulse magnitude exerted on the cement slurry  56 ; however, the PLC  70  may ensure that the effective magnitude during the swab stroke is still greater than or equal to the required pulse magnitude while also ensuring the actual pressure does not exceed the maximum allowable pressure of the lower formation  27   b.    
     Circulation of the conditioner  55  and pulse generation may be maintained until the entire column of the cement slurry  56  has thickened sufficiently to prevent gas migration. As the conditioner  55  is being circulated, the PLC  70  may perform the mass balance using the heave sensor  82  to account for displaced volume by the heave  60  and the flow meters  69   r ,  88   c ,  88   p  to monitor for formation fluid entering the annulus  48  or cement slurry  56  entering the lower formation  27   b  to evaluate acceptability, as discussed above. Once the cement slurry  56  has cured to the thickened state, the CDA  9   d  may be reengaged with the casing packer  15   h , the casing packer may be set, and the workstring  9  retrieved to the rig  1   r.    
     Alternatively, an accumulator may be used to supply the conditioner to the return line for generation of the pulses instead of the pulse spool. Alternatively, the RCD may be omitted and the diverter closed against the workstring instead. 
       FIG. 9  illustrates cement pulsation during curing of a temporary abandonment cement plug  93 , according to another embodiment of this disclosure. The CDA  9   d  may removed from the workstring  9  and replaced by a stinger  92 . The workstring  9   p ,  92  may be redeployed until the stinger  92  is located adjacent to the casing hanger  15   h . Spacer fluid  94  may be pumped into the workstring  9   p ,  92  followed by the cement slurry  93 . Chaser fluid (not shown) may be pumped into the workstring  9   p ,  92  to propel the cement slurry  93  and spacer fluid  94  through the stinger  92  until a level of the cement slurry in the inner casing string  15  is equal to a level of the cement slurry in the stinger (aka balanced plug). The drill pipe  9   p  may be raised to remove the stinger  92  from the cement slurry  93  and the cement slurry choke pulsed  75  until it has thickened sufficiently to prevent gas migration. The choke pulses  75  may be generated using any of the second, third, or fourth alternative drilling systems. Once the slurry  93  has thickened, the workstring  9   p ,  92  may be retrieved to the rig. The PCA  1   p  and riser string  17  may be retrieved to the rig and the MODU  1   m  dispatched from the wellsite. An intervention vessel (not shown) may then to be sent to the wellsite for completion of the wellbore  24 . 
     Alternatively, the curing cement slurry  93  may be pulsed using heave pulses generated by the drilling system  1  or the first alternative drilling system. 
       FIG. 10  illustrates cement pulsation of curing cement slurry  56  in an annulus  95  of a liner string  90 , according to another embodiment of this disclosure. A liner deployment assembly (LDA)  89  may be used to deploy the liner string  90  instead of the CDA  9   d . The liner string  90  may include a polished bore receptacle (PBR)  90   r , a packer  90   p , a liner hanger  90   h , a mandrel  90   m  for carrying the hanger and packer, joints of liner  90   j , a landing collar  90   c , and a reamer shoe  90   s . The mandrel  90   m , liner joints  90   j , landing collar  90   c , and reamer shoe  90   s  may be interconnected, such as by threaded couplings. 
     The LDA  89  may include a setting tool  89   b,o,p,s , a running tool  89   r , a catcher  89   t , and a plug release system  89   e,g . An upper end of the setting tool  89   b,o,p,s  may be connected to a lower end the drill pipe  9   p , such as by threaded couplings. A lower end of the setting tool  89   b,o,p,s  may be fastened to an upper end of the running tool  89   r . The running tool  89   r  may also be releasably connected to the mandrel  90   m . An upper end of the catcher  89   t  may be connected to a lower end of the running tool  89   r  and a lower end of the catcher may be connected to an upper end of the plug release system  89   e,g , such as by threaded couplings. 
     For deployment of the liner string  90 , a junk bonnet  89   b  of the setting tool  89   b,o,p,s  may be engaged with and close an upper end of the PBR  90   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 a packoff  89   o  of the setting tool  89   b,o,p,s  and the PBR  90   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.    
     The setting tool  89   b,o,p,s  may include a hydraulic actuator  89   p  for setting the liner hanger  90   h  and a mechanical actuator  89   s  for setting the liner packer  90   p . The cementing head  7  may be modified for use with the LDA  89  by replacing one of the release plug launchers with a setting plug launcher. The setting plug may be a ball  91   b  pumped down the workstring  9   p ,  89  to the catcher  89   t . The catcher  89   t  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  91   b  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  90   h , unlock the running tool  53 , and release the junk bonnet  89   b . Once the seated ball has been released, the seat and ball  91   b  may swing relative to the body into a capture chamber, thereby reopening the LDA bore. 
     Once the liner hanger  90   h  has been set against an inner surface of a lower portion, such as the bottom, of the outer casing string  25  and the running tool  89   r  unlocked, the workstring  9   p ,  89  may be rotated, thereby releasing a floating nut of the running tool from a threaded profile of the mandrel  90   m . The workstring  9   p ,  89  may be raised to verify successful release and lowered to torsionally engage the LDA  9   d  with the liner string  90  for rotation during pumping of the cement slurry  56 . The cement slurry  56  may be pumped followed by a dart  91   d  to release the wiper plug  89   g  from the plug release system  89   e,g . Once pumping of the cement slurry  56  has finished, the cementing head (minus the isolation valve) may be removed and the workstring  9   p ,  89  connected to the isolation valve and raised to create sufficient clearance between the equalization valve  89   e  and the liner hanger  90   h  to accommodate the heave  60  of the workstring  9 . The spider  4   s  may then be operated to engage the drill pipe  9   p , thereby longitudinally supporting the workstring  9  from the rig floor  4   f . The cement slurry  56  may be pulsed  75  and pulse generation may be maintained until the entire column of the cement slurry  56  has thickened sufficiently to prevent gas migration. The LDA  89  may then be lowered until the mechanical actuator  89   s  engages the liner packer  90   p  and lowering may continue to set the liner packer. 
     The pulsation  75  of the cement slurry  56  in the liner annulus  95  may be performed using the second, third, or fourth alternative drilling systems. Alternatively, the curing cement slurry  56  in the liner annulus  95  may be pulsed using heave pulses generated by the drilling system  1  or the first alternative drilling system. 
     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.