Patent Publication Number: US-10774613-B2

Title: Tieback cementing plug system

Description:
CROSS-REFERENCE TO RELATED APPLICATIONS 
     This application is a continuation of co-pending U.S. patent application Ser. No. 15/790,517, filed Oct. 23, 2017, which is a continuation of U.S. patent application Ser. No. 14/639,309, filed Mar. 5, 2015, which claims benefit of U.S. Provisional Patent Application Ser. No. 61/948,930, filed Mar. 6, 2014. Each of the aforementioned patent applications is incorporated by reference. 
    
    
     BACKGROUND OF THE DISCLOSURE 
     Field of the Disclosure 
     The present disclosure generally relates to a plug system for cementing a tieback casing string. 
     Description of the Related Art 
     Tieback casing strings are utilized to extend a production liner to a wellhead. Installation of a liner/tieback combination offers several advantages over a continuous casing, including delaying of expenses for uncertain or high risk well exploration, testing of isolation between the liner annulus and the open hole section, and a reduction of load-bearing requirements for derricks. 
     Many tieback strings are installed and cemented just before installation of completion equipment. However, issues with the cementing operation may necessitate removal of the tieback string and cement to correct the issues, a process which can be both expensive and time consuming. 
     Therefore, there is a need for an improved process for cementing a tieback casing string. 
     SUMMARY OF THE DISCLOSURE 
     The present disclosure generally relates to a plug system for cementing a tieback casing string. In one embodiment, a method for casing a subsea wellbore includes running a tieback casing string into the subsea wellbore using a workstring. The workstring includes a first wiper plug, a second wiper plug, and a third wiper plug. The method further includes: launching a first release plug or tag into the workstring; pumping cement slurry into the workstring, thereby driving the first release plug or tag along the workstring; after pumping the cement slurry, launching a second release plug or tag into the workstring; and pumping chaser fluid into the workstring, thereby driving the release plugs or tags and cement slurry through the workstring. The release plugs or tags engage and release the respective wiper plugs from the workstring. The first wiper plug or release plug ruptures, thereby allowing the cement slurry to flow therethrough and into an annulus formed between the tieback casing string and an outer casing string. The method further includes stabbing the tieback casing string into a liner string; and retrieving the workstring, the workstring still including the third wiper plug. 
     A method for casing a subsea wellbore includes running a tieback casing string into the subsea wellbore using a workstring. The workstring includes a first wiper plug, a second wiper plug, and a third wiper plug. The method further includes: launching a first release plug or tag into the workstring; pumping cement slurry into the workstring, thereby driving the first release plug or tag along the workstring; after pumping the cement slurry, launching a second release plug or tag into the workstring; and pumping chaser fluid into the workstring, thereby driving the release plugs or tags and cement slurry through the workstring. The release plugs or tags engage and release the respective wiper plugs from the workstring. The first wiper plug or release plug ruptures, thereby allowing the cement slurry to flow therethrough and into an annulus formed between the tieback casing string and an outer casing string. The method further includes: pumping conditioner fluid into the workstring, thereby rupturing the second wiper plug or release plug and flushing the cement slurry from the annulus; pumping remedial cement slurry into the workstring; after pumping the remedial cement slurry, launching a third release plug or tag into the workstring; pumping the chaser fluid into workstring, thereby driving the third release plug or tag and remedial cement slurry through the workstring. The third engages and releases the third wiper plug. The third wiper plug drives the remedial cement slurry into the annulus. The method further includes stabbing the tieback casing string into a liner string; and retrieving the workstring. 
     A plug release system includes a first wiper plug including a burst tube, the first burst tube adapted to burst at a pressure between 900 psi and 1100 psi; a second wiper plug including a burst tube, the second burst tube adapted to burst at a pressure between 3500 psi and 5000 psi; and a third wiper plug; wherein: the first wiper plug is coupled to the second wiper plug by a shearable fastener, the shearable fastener adapted to shear at a pressure between 500 psi and 700 psi; and the second wiper plug is coupled to the third wiper plug by a shearable fastener, the shearable fastener adapted to shear at a pressure between 1300 psi and 1700 psi. 
    
    
     
       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 tieback casing deployment mode, according to one embodiment of this disclosure. 
         FIG. 2  illustrates a tieback deployment assembly, according to one embodiment of this disclosure. 
         FIGS. 3A-3C  illustrate darts for releasing wiper plugs of the tieback deployment assembly. 
         FIG. 4  illustrates a lower portion of the tieback casing string. 
         FIGS. 5A-5G, 6A-6G and 7  illustrate a primary tieback cementing operation using the tieback deployment assembly. 
         FIGS. 8A-8D and 9A-9D  illustrate a remedial tieback cementing operation using the tieback deployment assembly. 
     
    
    
     To facilitate understanding, identical reference numerals have been used, where possible, to designate identical elements that are common to the figures. It is contemplated that elements and features of one embodiment may be beneficially incorporated in other embodiments without further recitation. 
     DETAILED DESCRIPTION 
       FIGS. 1A-1C  illustrate a drilling system  1  in a tieback casing deployment 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. 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 , a top drive  5 , a cementing head  7 , and a hoist. The top drive  5  may include a motor for rotating 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 frame of the top drive  5  may be suspended from the derrick  3  by the traveling block  11   t . 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 drilling rig  1   r  may further include a drill string compensator (not shown) to account for heave of the MODU  1   m . The drill string compensator may be disposed between the traveling block  11   t  and the top drive  5  (aka hook mounted) or between the crown block  11   c  and the derrick  3  (aka top mounted). 
     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 tieback deployment assembly (TDA)  9   d  and a deployment string, such as joints of drill pipe  9   p  connected together, such as by threaded couplings. An upper end of the TDA  9   d  may be connected a lower end of the drill pipe  9   p , such as by threaded couplings. The TDA  9   d  may be connected to the tieback casing string  44 , such as by engagement of a bayonet lug  45   b  with a mating bayonet profile formed in an upper end of the tieback casing string. The tieback casing string  44  may include a packer  44   p , a casing hanger  44   h , a mandrel  44   m  for carrying the hanger and packer and having a seal bore formed therein, joints of casing  44   j , a float collar  44   c , a seal stem  44   s , and a guide shoe  44   g . The tieback casing components may be interconnected, such as by threaded couplings. 
     Once deployment of the tieback casing string 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 , and one or more plug launchers, such as a first dart launcher  7   a  and a second dart launcher  7   b . 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 plug launchers  7   a,b . The actuator swivel inlets may be in fluid communication with a hydraulic power unit (HPU, not shown). 
     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 dart, such as a first dart  43   a  or a second 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   a,b , the HPU 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). If one of the dart launchers  7   a,b  is selected, the respective canister and dart  43   a,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   a,b  from the canister bore into a lower bore of the body and onward through the workstring  9 . 
     The fluid transport system  1   t  may include an upper marine riser package (UMRP)  16   u , a marine riser  17 , a booster line  18   b , and a choke line  18   c . 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  21 , such as by a flanged connection. The diverter  21  may also be connected to the rig floor  4 , 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 . 
     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 pilot bit and underreamer (not shown). 
     The lower formation  27   b  may be lined by deployment, hanging, cementing of lower annulus  48   b , and sealing of a liner string  15 . The liner string  15  may include, a packer  15   p , a liner hanger  15   h , a body  15   v  for carrying the hanger and packer (HP body), joints of liner  15   j , a landing collar  15   c , and a reamer shoe  15   s . The HP body  15   v , liner joints  15   j , landing collar  15   c , and reamer shoe  15   s  may be interconnected, such as by threaded couplings. 
     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 rig controller (not shown) onboard the MODU  1   m  via an umbilical  33 . 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 . The umbilical  33  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 rig controller may operate the PCA  1   p  via the umbilical  33  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 (not shown). A lower end of the choke line  18   c  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. 
     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  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  and a mud pump  34 , a reservoir, such as a tank  35 , a solids separator, such as a shale shaker  36 , one or more pressure gauges  37   c,m , 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 , and a cement mixer  42 . In the drilling mode, the tank  35  may be filled with drilling fluid, such as mud (not shown). In the tieback deployment mode, the tank  35  may be filled with conditioner  70 . 
     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 . 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 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 shutoff valve  41  and the 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 . 
     During deployment of the tieback casing string  44 , the workstring  9  may be lowered  8   a  by the traveling block  11   t  and the conditioner  70  may be pumped into the workstring bore by the mud pump  34  via the mud line  39  and top drive  5 . The conditioner  70  may flow down the workstring bore and the liner string bore and be discharged by the guide shoe  44   g  into an upper annulus  48   u  formed between the tieback string  44  and the casing string  25 . The conditioner  70  may flow up the upper annulus  48   u  and exit the wellbore  24  and flow into an annulus formed between the riser  17  and the workstring  9 /tieback string  44  via an annulus of the LMRP  16   b , BOP stack, and wellhead  10 . The conditioner  70  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  70  may flow through the return line  40  and into the shale shaker inlet. The conditioner  70  may be processed by the shale shaker  36  to remove any particulates therefrom. 
       FIG. 2  illustrates the TDA  9   d .  FIGS. 3A-3C  illustrate darts  43   a - c  for releasing respective wiper plugs  50   a - c  of the TDA  9   d . The TDA  9   d  may include a running tool  45 , a plug release system  46 , and a packoff  47 . The packoff  47  may be disposed in a recess of a housing  45   h  of the running tool  45  and carry inner and outer seals for isolating an interface between the tieback casing string  44  and the TDA  9   d  by engagement with the seal bore of the mandrel  44   m . The running tool housing  45   h  may be connected to a housing  46   h  of the plug release system  46 , such as by threaded couplings. 
     The plug release system  46  may include an equalization valve  46   e , a first wiper plug  50   a , a second wiper plug  50   b , and third wiper plug  50   c . The equalization valve  46   e  may include a housing  46   h , an outer wall  46   w , a cap  46   c , a piston  46   p , a spring  46   s , a collet  46   f , and a seal insert  46   i . The housing  46   h , outer wall  46   w , and cap  46   c  may be interconnected, such as by threaded couplings. The piston  46   p  and spring  46   s  may be disposed in an annular chamber formed radially between the housing and the outer wall and longitudinally between a shoulder of the housing  46   h  and a shoulder of the cap  46   c . The piston  46   p  may divide the chamber into an upper portion and a lower portion and carry a seal for isolating the portions. The cap  46   c  and housing  46   h  may also carry seals for isolating the portions. The spring  46   s  may bias the piston  46   p  toward the cap  46   c . The cap  46   c  may have a port formed therethrough for providing fluid communication between the upper annulus  48   u  and the chamber lower portion and the housing  46   h  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  46   h  and a top of the cap  46   c . As pressure from the upper annulus  48   u  acts against a lower surface of the piston  46   p  through the cap passage, the piston  46   p  may move upward and open the outlet port to facilitate equalization of pressure between the annulus and a bore of the housing  46   h  to prevent surge pressure from prematurely releasing one or more of the plugs  50   a - c.    
     Each wiper plug  50   a - c  may be made from a drillable material and include a respective finned seal  51   a - c , a plug body  52   a - c , a latch sleeve  53   a - c , and a lock sleeve  54   a - c . Each latch sleeve  53   a - c  may have a collet formed in an upper end thereof and the second and third latch sleeves  53   b,c  may each have a respective collet profile formed in a lower portion thereof. Each lock sleeve  54   a - c  may have a respective seat  55   a - c  and seal bore  56   a - c  formed therein. Each lock sleeve  54   a - c  may be movable between an upper position and a lower position and be releasably restrained in the upper position by a respective shearable fastener  57   a - c . Each dart  43   a - c  may be made from a drillable material and include a respective finned seal  58   a - c  and dart body. Each dart body may have a respective landing shoulder  59   a - c  and carry a respective landing seal  60   a - c  for engagement with the respective seat  55   a - c  and seal bore  56   a - c . A major diameter of the first landing shoulder  59   a  may be less than a minor diameter of the second seat  55   b  and a major diameter of the second landing shoulder  59   b  may be less than a minor diameter of the third seat  55   c  such that the first dart  43   a  may pass through the second  50   b  and third  50   c  wiper plugs and the second dart  43   b  may pass through the third wiper plug. 
     The third shearable fastener  57   c  may releasably connect the third lock sleeve  54   c  to the valve housing  46   h  and the third lock sleeve  54   c  may be engaged with the valve collet  46   f  in the upper position, thereby locking the valve collet into engagement with the collet of the third latch sleeve  53   c . The second shearable fastener  57   b  may releasably connect the second lock sleeve  54   b  to the third lock sleeve  53   c  and the second lock sleeve  54   b  may be engaged with the collet of the second latch sleeve  53   b , thereby locking the collet into engagement with the collet profile of the third latch sleeve. The first shearable fastener  57   a  may releasably connect the first lock sleeve  54   a  to the second latch sleeve  53   b  and the second lock sleeve  54   b  may be engaged with the collet of the first latch sleeve  53   a , thereby locking the collet into engagement with the collet profile of the second latch sleeve  53   b . A release pressure necessary to fracture the first shearable fastener  57   a  may be substantially less than the release pressure necessary to fracture the second shearable fastener  57   b  which may be substantially less than the release pressure necessary to fracture the third shearable fastener  57   c.    
     The first  50   a  and second  50   b  wiper plugs may each include one or more (pair shown) bypass ports formed through a wall of the respective latch sleeves  53   a,b  initially sealed by respective burst tubes  61   a,b  to prevent fluid flow therethrough. The burst tubes  61   a,b  are adapted to rupture when a predetermined pressure is applied thereto and a rupture pressure of the first burst tube  61   a  may be substantially less than a rupture pressure of the second burst tube  61   b . The rupture pressure of the first burst tube  61   a  may also be substantially greater than the release pressure of the first wiper plug  50   a  and substantially less than the release pressure of the second wiper plug  50   b . The rupture pressure of the second burst tube  61   b  may also be substantially greater than the release pressure of the second wiper plug  50   b  and substantially greater than the release pressure of the third wiper plug  50   b.    
     The first wiper plug  50   a  may be released at a pressure ranging between 500 psi to 700 psi, the second wiper plug  50   b  may be released at a pressure ranging between 1300 psi to 1700 psi, and the third wiper plug  50   c  at a pressure ranging between 2000 psi to 2400 psi. The first burst tube  61   a  may rupture at a pressure ranging between 900 psi to 1100 psi and the second burst tube  61   b  may rupture at a pressure ranging between 3500 psi to 5000 psi. 
     Alternatively, the first dart  43   a  and the second dart  43   b  may include rupture disks or burst tubes rather than or in addition to the burst tubes  61   a,b  of the wiper plugs  50   a,b . Thus, rupturing the of the burst tube within the first dart  43   a  or the second dart  43   b  would allow fluid flow therethrough when seated within a respective wiper plug. 
     To facilitate subsequent drill-out, each plug body  50   a - c  may further have a portion of an auto-orienting torsional profile  62   m,f  formed at a longitudinal end thereof. The first and second plug bodies  50   a,b  may each have the female portion  62   f  and male portion  62   m  formed at respective upper and lower ends thereof (or vice versa). The third plug body  50   c  may have only the male portion formed at the lower end thereof. 
       FIG. 4  illustrates a lower portion of the tieback casing string  44 . The float collar  44   c  may include a housing  63   h , a check valve  63   v , and a body  63   b . The body  63   b  and check valve  63   v  may be made from drillable materials. The body  63   b  may have a bore formed therethrough and the torsional profile female portion  62   f  formed in an upper end thereof for receiving the first wiper plug  50   a . The check valve  63   v  may include a seat  64   s , a poppet  64   p  disposed within the seat, a seal  64   e  disposed around the poppet and adapted to contact an inner surface of the seat to close the body bore, and a rib  64   r . The poppet  64   p  may have a head portion and a stem portion. The rib  64   r  may support a stem portion of the poppet  64   p . A spring  64   g  may be disposed around the stem portion and may bias the poppet  64   p  against the seat  64   s  to facilitate sealing. The poppet  64   p  may have a bypass slot  64   b  formed therein to prohibit the occurrence of hydraulic lock when stabbing the seal stem  44   s  into the PBR  15   r  by allowing fluid to pass around the closed poppet. 
     During deployment of the tieback casing string  44 , the conditioner  70  may be pumped to prepare the upper annulus  48   u  for cementing. The conditioner  70  may be pumped down at a sufficient pressure to overcome the bias of the spring  64   g , actuating the poppet  62   s  downward to allow conditioner  70  to flow through the bore of the body  63   b.    
     The seal stem  44   s  may include a gland  65 , one or more (three shown) seals  66 , and a pair of wipers  67  straddling the seals. During stabbing of the seal stem  44   s , the seals  66  may engage an inner surface of the PBR  15   r  while the wipers  67  displace particulates therefrom to ensure proper sealing. The wipers  67  and seals  66  may be positioned in grooves formed within an outer surface of the gland  65  to fix the wipers and the seals in place. During stabbing, the seals  66  initially engage the PBR  15   r  and change configuration to occupy an interface between the gland  65  and the PBR. The seals  66  may each include a protrusion for contact with the PBR  15   r  and energization thereof in response to the contact. The gland  65  may have a guide shoulder that is adapted to facilitate guidance of the tieback casing  44  in to the PBR  15   r.    
     The guide shoe  44   g  may include a housing  68   h  and a nose  68   n  made from a drillable material. The nose  68   n  may have a rounded distal end to guide the tieback casing  44  down the casing  25  and into the PBR  15   r.    
       FIGS. 5A-5G, 6A-6G and 7  illustrate a primary tieback cementing operation using the TDA  9   d . As illustrated in  FIGS. 5A and 6A , the tie back casing string  44  is lowered  8   a  until the packer  44   p , hanger  44   h , and mandrel  44   m  thereof are positioned proximately above the subsea wellhead  10  and the guide shoe  44   g  is positioned proximately above the PBR  15   r  to form a gap  69  therebetween. The gap  69  provides a fluid path from the bore of the tieback casing string  44  to the upper annulus  48   u  for the tieback cementing operation. 
     As illustrated in  FIGS. 5B and 6B , the first dart  43   a  may be released from the first launcher  7   a  by operating the first plug launcher actuator. Cement slurry  71  may be pumped from the mixer  42  into the cementing swivel  7   c  via the valve  41  by the cement pump  13 . The cement slurry  71  may flow into the second launcher  7   b  and be diverted past the second dart  43   b  via the diverter and bypass passages. The cement slurry  71  may flow into the first launcher  7   a  and be forced behind the first dart  43   a  by closing of the bypass passages, thereby propelling the first dart into the workstring bore. 
     Once the desired quantity of cement slurry  71  has been pumped, the second dart  43   b  may be released from the second launcher  7   b  by operating the second plug launcher actuator. Chaser fluid  72  may be pumped into the cementing swivel  7   c  via the valve  41  by the cement pump  13 . The chaser fluid  72  may flow into the second launcher  7   b  and be forced behind the second dart  43   b  by closing of the bypass passages, thereby propelling the second dart into the workstring bore. Pumping of the chaser fluid  72  by the cement pump  13  may continue until residual cement in the cement line  14  has been purged. Pumping of the chaser fluid  72  may then be transferred to the mud pump  34  by closing the valve  41  and opening the valve  6 . The train of darts  43   a,b  and cement slurry  71  may be driven through the workstring bore by the chaser fluid  72 . The first dart  43   a  may reach the first wiper plug  50   a  and the landing shoulder  59   a  and seal  60   a  of the first dart may engage the seat  55   a  and seal bore  56   a  of the first wiper plug. 
     As shown in  FIGS. 5C and 6C , continued pumping of the chaser fluid  72  may increase pressure in the workstring bore against the seated first dart  43   a  until the first release pressure is achieved, thereby fracturing the first shearable fastener  57   a . The first dart  43   a  and lock sleeve  54   a  of the first wiper plug  50   a  may travel downward until reaching a stop of the first wiper plug, thereby freeing the collet of the first latch sleeve  53   a  and releasing the first wiper plug from the second wiper plug  50   b . The released first dart  43   a  and first wiper plug  50   a  may travel down the bore of the tieback casing string  44  wiping the inner surface thereof and forcing the conditioner  70  therethrough. The second dart  43   b  may then reach the second wiper plug  50   b  and the landing shoulder  59   b  and seal  60   b  of the second dart may engage the seat  55   b  and seal bore  56   b  of the second wiper plug. 
     As shown in  FIGS. 5D and 6D , continued pumping of the chaser fluid  72  may increase pressure in the workstring bore against the seated second dart  43   b  until the second release pressure is achieved, thereby fracturing the second shearable fastener  57   b . The second dart  43   b  and lock sleeve  54   b  of the second wiper plug  50   b  may travel downward until reaching a stop of the second wiper plug, thereby freeing the collet of the second latch sleeve  53   b  and releasing the second wiper plug from the third wiper plug  50   c . Continued pumping of the chaser fluid  72  may drive the train of darts  43   a,b , wiper plugs  50   a,b , and cement slurry  71  through the tieback casing bore until the first wiper plug  50   a  bumps the float collar  44   c.    
     As illustrated in  FIGS. 5E and 6E , continued pumping of the chaser fluid  72  may increase pressure in the tieback casing bore against the seated first dart  43   a  and first wiper plug  50   a  until the first rupture pressure is achieved, thereby rupturing the first burst tube  61   a  and opening the bypass ports of the first wiper plug. The cement slurry  71  may flow around the first dart  43   a  and through the first wiper plug, the seal stem  44   s , and the guide shoe  44   g , and upward into the upper annulus  48   u  via the gap  69 . The cement slurry  71  may be prohibited from flowing down the liner string  15  by the seated liner dart  15   d  and packer  15   p  and a column of incompressible chaser fluid (not shown) in the liner bore. 
     As shown in  FIGS. 5F and 6F , pumping of the chaser fluid  72  may continue to drive the cement slurry  71  into the upper annulus  46   u  until the second wiper plug  50   b  bumps the seated first wiper plug  50   a . Pumping of the chaser fluid  72  may be halted prior to reaching the second rupture pressure, thereby leaving the second burst tube  61   b  intact. The check valve  62   v  may close in response to halting of the pumping. Acceptability of the primary cementing operation may be determined. If acceptable, the workstring  9  may be lowered  74  until a shoulder of the tieback hanger  44   h  engages a seat of the wellhead  10 , thereby stabbing the seal stem  44   s  into the PBR  15   r . Pressure  75  may be relieved upward through the bypass slot of the poppet  64   p  and the first wiper plug  50   a , and around the directional fins of the second wiper plug  50   b , thereby avoiding hydraulic lock due to the incompressible cement slurry  71 . 
     As illustrated in  FIGS. 5G and 6G , the workstring  9  may continued to be lowered  74 , thereby releasing a shearable connection of the tieback hanger  44   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. Continued lowering  74  of the workstring may drive a wedge of the tieback packer  44   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. 
     As shown in  FIG. 7 , with the tieback casing string  44  secured in place, the bayonet connection between the TDA  9   d  and the tieback casing  44  may be released and the workstring  9  retrieved to the rig  1   r . Since the primary cementing operation was deemed successful, the third wiper plug  50   c  remains part of the TDA  9   d  and may be retrieved to the rig  1   r.    
       FIGS. 8A-8D and 9A-9D  illustrate a remedial tieback cementing operation using the tieback deployment assembly. If the cement slurry  71  does not meet one or more requirements, such as location, composition, or uniformity, the primary cementing operation may be deemed unsuccessful. If not for the presence of the third wiper plug  50   c , the tieback casing string  44  would need to be removed, the cement slurry  71  would need to be drilled or flushed, and the tieback casing string would then need to be reinserted to allow the cementing operation to be performed again. Such a process would be extremely time consuming and could take on the order of days to complete at considerable expense. 
     As illustrated in  FIGS. 8A and 9A , after recognition of a failed primary cementing operation, the third dart  43   c  may be loaded into one of the launchers  7   a,b  and conditioner  70  may be injected into the workstring  9  to increase pressure in the tieback casing bore against the seated second dart  43   b  and second wiper plug  50   b  until the second rupture pressure is achieved, thereby rupturing the second burst tube  61   b  and opening the bypass ports of the second wiper plug. The conditioner  70  may flow around the second dart  43   a  and through the second wiper plug  50   b , around the first dart  43   a , and through the first wiper plug  50   a , the seal stem  44   s , and the guide shoe  44   g , and upward into the upper annulus  48   u  via the gap  69 , thereby flushing the failed cement slurry  71  from the upper annulus  48   u.    
     As shown in  FIGS. 8B and 9B , after flushing the failed cementing slurry  71  from the upper annulus  48   u , remedial cement slurry  76  may be pumped from the mixer  42  into the cementing swivel  7   c  via the valve  41  by the cement pump  13 . Once the desired quantity of remedial cement slurry  76  has been pumped, the third dart  43   c  may be released from the loaded launcher  7   a,b  by operating the respective plug launcher actuator. Chaser fluid  72  may be pumped into the cementing swivel  7   c  via the valve  41  by the cement pump  13 . The chaser fluid  72  may flow into the loaded launcher  7   a,b,  thereby propelling the third dart into the workstring bore. Pumping of the chaser fluid  72  by the cement pump  13  may continue until residual cement in the cement line  14  has been purged. Pumping of the chaser fluid  72  may then be transferred to the mud pump  34  by closing the valve  41  and opening the valve  6 . The third dart  43   c  and remedial cement slurry  76  may be driven through the workstring bore by the chaser fluid  72 . The third dart  43   c  may reach the third wiper plug  50   c  and the landing shoulder  59   c  and seal  60   c  of the third dart may engage the seat  55   c  and seal bore  56   c  of the third wiper plug. 
     As shown in  FIGS. 8C and 9C , continued pumping of the chaser fluid  72  may increase pressure in the workstring bore against the seated third dart  43   c  until the third release pressure is achieved, thereby fracturing the third shearable fastener  57   c . The third dart  43   c  and lock sleeve  54   c  of the third wiper plug  50   c  may travel downward until reaching a stop of the third wiper plug, thereby freeing the collet  46   f  and releasing the third wiper plug  50   c  from the equalization valve  46   e . Continued pumping of the chaser fluid  72  may drive the third dart  43   c , third wiper plug  50   c , and remedial cement slurry  76  through the tieback casing bore. The remedial cement slurry  76  may flow around the second dart  43   a  and through the second wiper plug  50   b , around the first dart  43   a , and through the first wiper plug  50   a , the seal stem  44   s , and the guide shoe  44   g , and upward into the upper annulus  48   u  via the gap  69 . 
     As shown in  FIGS. 8D and 9D , pumping of the chaser fluid  72  may continue to drive the remedial cement slurry  76  into the upper annulus  46   u  until the third wiper plug  50   c  bumps the seated second wiper plug  50   b . Pumping of the chaser fluid  72  may then be halted. The workstring  9  may then be lowered  74 , thereby stabbing the seal stem  44   s  into the PBR  15   r  and setting the tieback hanger  44   h  and packer  44   p  against the wellhead  10 . The workstring  9  may then be retrieved to the rig  1   r.    
     Alternatively, the primary cementing job may be successful but a problem may occur during stabbing of the seal stem  44   s /landing of the tieback hanger  44   h . If such problem occurs, the workstring  9  may be raised to reform the gap  69  and then the remedial cementing operation may be performed. 
     In another embodiment (not shown), the cement head  7  may be omitted and the cement line  14  instead connected to the top drive  5 . Further, instead of darts, the release plugs may be balls. Alternatively, RFID tags may be used instead of the balls and gel plugs or foam plugs may be used to separate the fluids. In either instance, launchers may be assembled as part of the cement line  14  and the wiper plugs may each have a flapper valve biased toward a closed position and held in an open position by a single prop sleeve extending through the wiper plugs. The first and second flappers may each have a rupture disk therein to serve the purpose of the burst sleeves, discussed above. 
     For the tag alternative, a first tag launcher may be operated to release an RFID tag into the cement line  14  and a first foam or gel plug may be launched/injected into the cement line  14 . Alternatively, the first foam or gel plug may be omitted. Cement slurry  71  may then be pumped from the mixer  42 , through the cement line and top drive, and into the workstring  9  by the cement pump  13 . After a desired amount of cement slurry  71  has been pumped, a second RFID tag and a foam/gel plug may be launched/pumped into the cement line  14 , through the top drive, and propelled down the workstring  9  by chaser fluid  72 . As the first and second RFID tags travel down the workstring, the first RFID tag will travel near an RFID antenna of an electronics package located within mandrel of the plug launch assembly. The first RFID tag sends a signal to the RFID antenna as the tag passes thereby. An MCU may receive the first command signal from the first tag and may operate an actuator controller to energize an actuator to move the prop sleeve upward from engagement with the first wiper plug. Once the upward stroke has finished, the prop sleeve may also be clear of the first wiper plug collet. The flapper of the first wiper plug may then close and pressure may increase thereon until the first plug is released from the second plug. The released first wiper plug may then be propelled through the tieback casing, as described above. The second RFID tag similarly instructs actuation of the prop sleeve to move clear of the second flapper and collet, thereby releasing the second wiper plug. If necessary, a third RFID tag may be used to launch the third wiper plug. A more detailed discussion of plug launching using RFID tags can be found in U.S. patent application Ser. No. 14/083,021, filed Nov. 18, 2013, which is herein incorporated by reference. 
     For the ball alternative, the prop sleeve may have each ball seat disposed within and releasably connected thereto, such as by a shearable fastener. Each ball seat may close one or flow ports providing fluid communication between the prop sleeve bore and a respective flapper chamber of the respective wiper plug. The first wiper plug may also be releasably connected to the prop sleeve by a shearable fastener. A first ball launcher may be operated to release a first ball into the cement line  14  and cement slurry  71  may then be pumped from the mixer  42 , through the cement line and top drive and into the workstring  9  by the cement pump  13 . After a desired amount of cement slurry  71  has been pumped, a second ball may be launched into the cement line  14 , through the top drive, and propelled down the workstring  9  by chaser fluid  72 . The first ball may land in the first seat and release the first seat from the prop sleeve, thereby moving the first sleeve down the prop sleeve until a stop shoulder of the prop sleeve is engaged. The first ports may be opened by the movement of the first seat, thereby allowing the cement slurry to flow into the first flapper chamber and exert pressure on a first piston in the flapper chamber, thereby exerting a downward force on the first wiper plug until the shearable fastener fractures. The downward force may drive the first wiper plug off of the prop sleeve, thereby allowing the first flapper to close. The released first wiper plug may then be propelled through the tieback casing by pressure of the cement slurry acting on the closed flapper. The second ball may release the second wiper plug in a similar fashion and if necessary, a third ball may be launched to release the third wiper plug. 
     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.