CA2891577A1

CA2891577A1 - Surge immune stage system for wellbore tubular cementation

Info

Publication number: CA2891577A1
Application number: CA2891577A
Authority: CA
Inventors: Marcel Budde; Peter Edenburg; Ivan Andre Barannikow
Original assignee: Weatherford Lamb Inc
Current assignee: Weatherford Lamb Inc
Priority date: 2014-05-16
Filing date: 2015-05-13
Publication date: 2015-11-16
Anticipated expiration: 2035-05-13
Also published as: GB2526208A; GB201508333D0; US10246968B2; CA2891577C; US20150330181A1; NO20150593A1; GB2526208B

Abstract

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

Description

SURGE IMMUNE STAGE SYSTEM FOR WELLBORE TUBULAR CEMENTATION
BACKGROUND OF THE DISCLOSURE
Field of the Disclosure The present disclosure generally relates to a surge immune stage system for wellbore tubular cementation.
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 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 plafform or rig, and/or by a downhole motor mounted towards the lower end of the drill string. After drilling to a predetermined depth, the drill string and drill bit are removed and a casing string is lowered into the wellbore. An annulus is thus formed between the string of casing and the wellbore. The casing string is cemented into the wellbore by circulating cement slurry into the annulus. The combination of cement and casing strengthens the wellbore and facilitates the isolation of certain formations behind the casing for the production of hydrocarbons.
Currently, cement flows into the annulus from the bottom of the casing. Due to weak formations or long strings of casing, cementing from the top of the casing may be undesirable or ineffective. When circulating cement into the annulus from the bottom of the casing, problems may be encountered as the cement on the outside of the annulus rises. For example, if a weak earth formation exists, it will not support the cement. As a result, the cement will flow into the formation rather than up the casing annulus.
To alleviate these issues, stage collars have been employed for casing cementing operations. For subterranean vertical wellbores, a free fall cone is used to open the stage collar. However, the free fall cone is unsuitable for deviated and subsea wellbores. For subsea and deviated wellbores, the stage collar has a pressure operated piston for opening thereof. Such a hydraulically operated stage tool is susceptible to premature activation due to pressure spikes in the bore of the casing string which could have catastrophic consequences.
SUMMARY OF THE DISCLOSURE
The present disclosure generally relates to a surge immune stage system for wellbore tubular cementation. In one embodiment, a method for cementing a tubular string into a wellbore includes: running the tubular string into the wellbore using a workstring having a deployment assembly; delivering an opener activator through the workstring to the deployment assembly, thereby launching an opener plug from the deployment assembly; pumping the opener activator and plug to a stage valve of the tubular string, thereby opening the stage valve; pumping cement slurry into the workstring; pumping a closer activator through the workstring behind the cement slurry, thereby launching a closer plug from the deployment assembly; and pumping the closer activator and plug to the open stage valve, thereby driving the cement slurry into an annulus between the tubular string and the wellbore and closing the stage valve.
In another embodiment, a system for cementing a tubular string into a wellbore includes: a stage valve for assembly as part of the tubular string and having:
a housing, a stage port formed through the housing, a sleeve, a stage port formed through the sleeve, an opener seat connected to the sleeve, and a closer seat linked to the sleeve;
and a plug release system for operating the stage valve. The plug release system includes: a closer plug having: a body, a finned seal, a latch sleeve, a lock sleeve for releasing the latch sleeve, and a landing shoulder for engaging the closer seat; and an opener plug having: a body, a finned seal, a latch sleeve, a lock sleeve for releasing the latch sleeve, and a landing shoulder for engaging the opener seat. The system further includes: a closer activator for engaging the closer lock sleeve; and an opener activator for engaging the opener lock sleeve.
BRIEF DESCRIPTION OF THE DRAWINGS
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

2 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.
Figures 1A-1C illustrate a drilling system in a cementing mode, according to one embodiment of this disclosure.
Figure 2 illustrates a plug release system of a liner deployment assembly of the drilling system.
Figures 3A-3C illustrate darts for releasing plugs of the plug release system.
Figures 4A and 4B illustrate a packing stage collar of a liner string deployed by the drilling system.
Figures 5A-5J illustrate staged cementing of the liner string. Figure 5K
illustrates setting of a packer of the liner string.
DETAILED DESCRIPTION
Figures 1A-1C illustrate a drilling system 1 in a cementing mode, according to one embodiment of this disclosure. The drilling system 1 may include a mobile offshore drilling unit (MODU) 1m, such as a semi-submersible, a drilling rig 1r, a fluid handling system 1h, a fluid transport system It, a pressure control assembly (PCA) 1p, and a workstring 9.
The MODU 1m may carry the drilling rig 1r and the fluid handling system 1h aboard and may include a moon pool, through which drilling operations are conducted.
The semi-submersible MODU 1m may include a lower barge hull which floats below a surface (aka waterline) 2s 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 2s. The upper hull may have one or more decks for carrying the drilling rig 1r and fluid handling system 1h. The MODU
1m may further have a dynamic positioning system (DPS) (not shown) or be moored for

3 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 lr may include a derrick 3, a floor 4f, a rotary table 4t, a spider 4s, a top drive 5, a cementing head 7, and a hoist. The top drive 5 may include a motor for rotating 49 (Figure 5A) the workstring 9. The top drive motor may be electric or hydraulic. A frame of the top drive 5 may be linked to a rail (not shown) of the derrick 3 for preventing rotation thereof during rotation 49 of the workstring 9 and allowing for vertical movement of the top drive with a traveling block 11t of the hoist.
The top drive frame may be suspended from the traveling block lit 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 11t may be supported by wire rope 11r connected at its upper end to a crown block 11c. The wire rope 11r may be woven through sheaves of the blocks 11c,t and extend to drawworks 12 for reeling thereof, thereby raising or lowering the traveling block 11t 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, the drill string compensator 8 may be disposed between the crown block 11c and the derrick 3. Alternatively, a Kelly and rotary table may be used instead of the top drive 5.
When the drilling system 1 is in a deployment mode (not shown), an upper end of

4 the workstring 9 may be connected to the top drive quill, such as by threaded couplings.
The workstring 9 may include a liner deployment assembly (LDA) 9d and a work stem, such as such as joints of drill pipe 9p connected together, such as by threaded couplings. An upper end of the LDA 9d may be connected a lower end of the drill pipe 9p, such as by threaded couplings. The LDA 9d may also be connected to a liner string 15. The liner string 15 may include a polished bore receptacle (PBR) 15r, a packer 15p, a liner hanger 15h, a mandrel 15m for carrying the hanger and packer, joints 15j of liner, a packing stage collar 150, a landing collar 15c, a float collar 15f, and a reamer shoe 15s. The mandrel 15m, liner joints 15j, collars 15c,o,f and reamer shoe 15s may be interconnected, such as by threaded couplings.
The fluid transport system It may include an upper marine riser package (UMRP) 16u, a marine riser 17, a booster line 18b, and a choke line 18k. The riser 17 may extend from the PCA 1p to the MODU lm and may connect to the MODU via the UMRP

16u. The UMRP 16u 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 4f, such as by a bracket. The slip joint 21 may be operable to extend and retract in response to heave of the MODU 1m 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 1m 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 RCA 1p may be connected to the wellhead 10 located adjacent to a floor 2f of the sea 2. A conductor string 23 may be driven into the seafloor 2f. 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

5 wellbore 24 may be drilled into the seafloor 2f 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 27u. The wellbore 24 may then be extended into the lower formation 27b using a drill string (not shown).
The upper formation 27u may be non-productive and a lower formation 27b may be a hydrocarbon-bearing reservoir. Alternatively, the lower formation 27b may be non-productive (e.g., a depleted zone), environmentally sensitive, such as an aquifer, or unstable.
The RCA 1p may include a wellhead adapter 28b, one or more flow crosses 29u,m,b, one or more blow out preventers (BOPs) 30a,u,b, a lower marine riser package (LMRP) 16b, one or more accumulators, and a receiver 31. The LMRP 16b may include a control pod, a flex joint 32, and a connector 28u. The wellhead adapter 28b, flow crosses 29u,m,b, BOPs 30a,u,b, receiver 31, connector 28u, 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 1m relative to the riser 17 and the riser relative to the PCA 1p.
Each of the connector 28u and wellhead adapter 28b may include one or more fasteners, such as dogs, for fastening the LMRP 16b to the BOPs 30a,u,b and the RCA
1p to an external profile of the wellhead housing, respectively. Each of the connector 28u and wellhead adapter 28b may further include a seal sleeve for engaging an internal profile of the respective receiver 31 and wellhead housing. Each of the connector 28u and wellhead adapter 28b 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

6 shown) may operate the actuator for engaging the dogs with the external profile.
The LMRP 16b may receive a lower end of the riser 17 and connect the riser to the PCA 1p.
The control pod may be in electric, hydraulic, and/or optical communication with a control console 33c onboard the MODU 1m via an umbilical 33u.
The control pod may include one or more control valves (not shown) in communication with the BOPs 30a,u,b for operation thereof. Each control valve may include an electric or hydraulic actuator in communication with the umbilical 33u. The umbilical 33u 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 30a,u,b.
Additionally, the accumulators may be used for operating one or more of the other components of the PCA 1p. The control pod may further include control valves for operating the other functions of the PCA 1p. The control console 33c may operate the PCA 1p via the umbilical 33u and the control pod.
A lower end of the booster line 18b may be connected to a branch of the flow cross 29u 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 29m,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 29m,b instead of the booster manifold. An upper end of the booster line 18b may be connected to an outlet of a booster pump 44. A lower end of the choke line 18k may have prongs connected to respective second branches of the flow crosses 29m,b. Shutoff valves may be disposed in respective prongs of the choke line lower end. An upper end of the choke line 18k 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 29u. 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 18b,c and umbilical 33u may extend between the MODU 1m and the PCA 1p by being fastened to

7 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 33u may be extended between the MODU 1m and the PCA lp independently of the riser 17. Alternatively, the shutoff valve actuators may be electrical or pneumatic.
The fluid handling system 1h 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 37c,k,m,r, one or more stroke counters 38c,m, one or more flow lines, such as cement line 14, mud line 39, and return line 40, one or more shutoff valves 41c,k, a cement mixer 42, a well control (WC) choke 45, and the MGS 46. When the drilling system 1 is in a drilling mode (not shown) and the deployment mode, the tank 35 may be filled with drilling fluid (not shown). In the cementing mode, the tank 35 may be filled with chaser fluid 47. A
booster supply line may be connected to an outlet of the mud tank 35 and an inlet of the booster pump 44. The choke shutoff valve 41k, the choke pressure gauge 37k, and the WC choke 45 may be assembled as part of the upper portion of the choke line 18k.
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 37r may be assembled as part of the return line 40. A
lower end of the mud line 39 may be connected to an outlet of the mud pump 34 and an upper end of the mud line may be connected to the top drive inlet. The mud pressure gauge 37m may be assembled as part of the mud line 39. An upper end of the cement line 14 may be connected to a cementing swivel 7c and a lower end of the cement line may be connected to an outlet of the cement pump 13. The cement shutoff valve 41c and the cement pressure gauge 37c 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

8 cement pump 13.
During deployment of the liner string 15, the workstring 9 may be lowered by the traveling block 11t and the drilling fluid may be pumped into the workstring bore by the mud pump 34 via the mud line 39 and top drive 5. The drilling fluid may flow down the workstring bore and the liner string bore and be discharged by the reamer shoe 15s into an annulus 48 formed between the liner string 15 and the wellbore 24/casing string 25.
The drilling fluid may flow up the annulus 48 and exit the wellbore 24 and flow into an annulus formed between the riser 17 and the workstring 9 via an annulus of the LMRP
16b, BOP stack, and wellhead 10. The drilling fluid may exit the riser annulus and enter the return line 40 via an annulus of the UMRP 16u and the diverter 19. The drilling fluid may flow through the return line 40 and into the shale shaker inlet. The drilling fluid may be processed by the shale shaker 36 to remove any particulates therefrom.
The float collar 15c may include a housing, a check valve, and a body. The body and check valve may be made from drillable materials. The check valve may include a seat, a poppet disposed within the seat, a seal disposed around the poppet and adapted to contact an inner surface of the seat to close the body bore, and a rib. The poppet may have a head portion and a stem portion. The rib may support a stem portion of the poppet. A spring may be disposed around the stem portion and may bias the poppet against the seat to facilitate sealing. During deployment of the liner string 15, the drilling fluid may be pumped down at a sufficient pressure to overcome the bias of the spring, actuating the poppet downward to allow drilling fluid to flow through the bore of the body and into the annulus 48.
The workstring 9 may be lowered until the liner string 15 reaches a desired deployment depth, such as the liner hanger 15h being adjacent to a lower portion of the casing string 25. The workstring 9 may be disconnected from the top drive 5 and the cementing head 7 may be inserted and connected between the top drive 5 and the workstring 9. The cementing head 7 may include an isolation valve 6, an actuator swivel 7a, the cementing swivel 7c, a release plug launcher 7r, a control console 7e, and a setting plug launcher 7s. The isolation valve 6 may be connected to a quill of the

9 top drive 5 and an upper end of the actuator swivel 7a, such as by threaded couplings.
An upper end of the workstring 9 may be connected to the setting plug launcher 7s, such as by threaded couplings.
The cementing swivel 7c may include a housing torsionally connected to the derrick 3, such as by bars, wire rope, or a bracket (not shown). The torsional connection may accommodate longitudinal movement of the cementing swivel 7c relative to the derrick 3. The cementing swivel 7c 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 7a, such as by threaded couplings. The cementing swivel 7c may further include an inlet formed through a wall of the housing and in fluid communication with a port formed through the mandrel and a seal assembly for isolating the inlet-port communication. The mandrel port may provide fluid communication between a bore of the cementing head 7 and the housing inlet.
The actuator swivel 7a may be similar to the cementing swivel 7c except that the housing thereof may have an inlet in fluid communication with a passage formed through the mandrel thereof. The mandrel passage may extend to an outlet for connection to a hydraulic conduit for operating a hydraulic actuator of the release plug launcher 7r. The actuator swivel inlet may be in fluid communication with a hydraulic power unit (HPU, not shown) operated by the control console 7e.
The release plug launcher 7r may include a body, a deflector, a canister, a gate, and the actuator. The body may be tubular and may have a bore therethrough. An upper end of the body may be connected to a lower end of the cementing swivel 7c, such as by threaded couplings, and a lower end of the body may be connected to the setting plug launcher 7s, such as by threaded couplings. The canister and deflector may each be disposed in the body bore. The deflector may be connected to the cementing swivel mandrel, such as by threaded couplings. The canister may be longitudinally movable relative to the body. The canister may be tubular and have ribs formed along and around an outer surface thereof. Bypass passages (only one shown) may be formed between the ribs. Each canister may further have a landing shoulder formed in a lower end thereof for receipt by a landing shoulder of the setting plug launcher 7s. The deflector may be operable to divert fluid received from the cement line 14 away from a bore of the canister and toward the bypass passages. A release plug, such as a shutoff dart 66, may be disposed in the canister bore.
The gate may include a housing, a plunger, and a shaft. The housing may be connected to a respective lug formed in an outer surface of the body, such as by threaded couplings. The plunger may be longitudinally movable relative to the housing and radially movable relative to the body between a capture position and a release position. The plunger may be moved between the positions by a linkage, such as a jackscrew, with the shaft. Each shaft may be longitudinally connected to and rotatable relative to the housing. Each actuator may be a hydraulic motor operable to rotate the shaft relative to the housing. The actuator may include a reservoir (not shown) for receiving the spent hydraulic fluid or the cementing head 7 may include a second actuator swivel and hydraulic conduit (not shown) for returning the spent hydraulic fluid to the HPU.
In operation, when it is desired to launch the shutoff dart 66, the console 7e may be operated to supply hydraulic fluid to the launcher actuator via the actuator swivel 7a.
The launcher actuator may then move the plunger to the release position. The canister and dart may then move downward relative to the body until the landing shoulders engage. Engagement of the landing shoulders may close the canister bypass passages, thereby forcing chaser fluid 47 to flow into the canister bore. The chaser fluid 47 may then propel the dart 66 from the canister bore into a bore of the setting plug launcher 7s and onward through the workstring 9.
The setting plug launcher 7s may include a mandrel, a body, a plunger, an actuator. During deployment of the liner string 15, a setting plug, such as a ball 50 (Figure 1C), may be loaded therein. The launcher body may be connected to the mandrel, such as by threaded couplings. The ball 50 may be disposed in the plunger for selective release and pumping down hole through the drill pipe 9p to the LDA 9d. The plunger may be movable relative to the launcher body between a capture position and a release position. The plunger may be moved between the positions by the actuator. The actuator may be manual, such as a handwheel.
Alternatively, the actuator swivel 7a and release plug launcher actuator may be pneumatic or electric. Alternatively, the release plug launcher actuator may be linear, such as a piston and cylinder. Alternatively, the release plug launcher 7r may include a main body having a main bore and a parallel side bore, with both bores being machined integral to the main body. The dart may be loaded into the main bore, and a dart releaser valve may be provided below the dart to maintain it in the capture position. The dart releaser valve may be side-mounted externally and extend through the main body.
A port in the dart releaser valve may provide fluid communication between the main bore and the side bore. In a bypass position, the dart may be maintained in the main bore with the dart releaser valve closed. Fluid may flow through the side bore and into the main bore below the dart via the fluid communication port in the dart releaser valve.
To release the dart, the dart releaser valve may be turned, such as by ninety degrees, thereby closing the side bore and opening the main bore through the dart releaser valve. The chaser fluid 47 may then enter the main bore behind the dart, causing it to drop downhole.
The LDA 9d may include a setting tool 52, a running tool 53, a catcher 54, and a plug release system 55. The setting tool 52 may include a debris barrier 51, a packoff 56, a hanger actuator 58, a packer actuator 59, a mandrel 60, and a latch 61.
An upper end of the setting tool 52 may be connected to a lower end the drill pipe 9p, such as by threaded couplings. A lower end of the setting tool 52 may be fastened to an upper end of the running tool 53. The running tool 53 may also be fastened to the liner mandrel 15m. An upper end of the catcher 54 may be connected to a lower end of the running tool 53 and a lower end of the catcher may be connected to an upper end of the plug release system 55, such as by threaded couplings.
The debris barrier 51 may be engaged with and close an upper end of the PBR
15r, thereby forming an upper end of a buffer chamber. A lower end of the buffer chamber may be formed by a sealed interface between the packoff 56 and the PBR
15r.
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 9d.
The hanger actuator 58 may include a piston, one or more sleeves, and a cylinder. The latch 61 may releasably connect the piston to the debris barrier 51 and the debris barrier to the PBR 15r. The actuator sleeves and piston may interconnected, such as by threaded couplings and/or fasteners. The actuator sleeves and piston may be disposed around and extend along an outer surface of the mandrel 60. The actuator sleeves may also be torsionally connected to the mandrel 60, such as by a pin and slot linkage. An actuation chamber may be formed between mandrel 60 and the cylinder. A
foot of the piston may be disposed in the actuation chamber and may divide the chamber into an upper portion and a lower portion. The actuation chamber upper portion may be in fluid communication with the mandrel bore via an actuation port formed through a wall of the mandrel 60.
The piston and sleeves of the hanger actuator 58 may be longitudinally movable relative to the cylinder between an upper position (not shown) and a lower position (Figure 1C) in response to a pressure differential between an upper face of the foot and a lower face of the foot. The piston and sleeves may set the liner hanger 15h when moving from the upper position to the lower position. The chamber lower portion may be in fluid communication with a surge chamber via a bypass passage and a bypass port of the running tool 53. The surge chamber may be formed radially between a lower portion of the LDA 9d (below the packoff 56) and the liner string 15 and longitudinally between the packoff 56 and a closer plug 65 (Figure 2) of the plug release system 55.
The running tool 53 may include a body, a lock, a clutch, and a latch. The running tool latch may longitudinally and torsionally connect the liner mandrel 15m to an upper portion of the LDA 9d. The latch may include a thrust cap, a longitudinal fastener, such as a floating nut, and a biasing member, such as a lower compression spring. The running tool lock may include one or more actuation ports formed through a wall of the body, a piston, a plug, a fastener, such as a dog, and a sleeve.
The packer actuator 59 may be longitudinally connected to the mandrel by entrapment between a load shoulder of the mandrel 60 and a top of the running tool 53.
The packer actuator 59 may include the packoff 56, a plurality of fasteners, such as dogs, a cam, one or more retainers, a thrust bearing, one or more radial bearings, and one or more biasing members, such as compression springs. The dogs may be restrained in a retracted position against the compression springs by engagement with an inner surface of the liner mandrel 15m.
The catcher 54 may be a mechanical ball seat including a body and a seat fastened to the body, such as by one or more shearable fasteners. The seat may also be linked to the body by a cam and follower. Once the ball 50 is caught, the seat may be released from the body by a threshold pressure exerted on the ball. The threshold pressure may be greater than a pressure required to set the liner hanger 15h, unlock the running tool 53, and release the latch 61. Once the seated ball 50 has been released, the seat and ball may swing relative to the body into a capture chamber, thereby reopening the LDA bore.
As the liner string 15 is being advanced into the wellbore 24 by the workstring 9, resultant surge pressure of the drilling fluid may be communicated to the surge chamber via leakage through the directional seals of plugs 63-65. The surge pressure may then be communicated to the lower face of the actuator piston via the running tool bypass port and the bypass passage. The surge pressure may also be communicated to an upper face of the running tool piston exposed to the surge chamber. This communication of the surge pressure to the lower face of the actuator piston and the upper face of the running tool piston may negate tendency of the surge pressure communicated to an upper face of the actuator piston by the actuation port and to the lower face of the running tool piston by the running tool actuator ports from prematurely setting the liner hanger 15h and prematurely unlocking the running tool 53.
Once the liner string 15 has been advanced into the wellbore 24 by the workstring 9 to a desired deployment depth and the cementing head 7 has been installed, conditioner 43 (Figure 5A) may be circulated by the cement pump 13 through the valve 41 to prepare for pumping of first stage cement slurry 95a (Figure 5A). The setting plug launcher 7s may then be operated and the conditioner 43 may propel the ball 50 down the workstring 9 to the catcher 54. The ball 50 may land in the seat of the catcher 54.
Once the ball 50 has landed continued pumping of the conditioner 43 may increase pressure on the seated ball, thereby also pressurizing the actuation chamber of the actuator 58 and exerting pressure on the actuator piston thereof. The actuator piston may in turn exert a setting force on the PBR 15r via the actuator sleeves, a lock sleeve of the latch 61, and the debris barrier 51. The PBR 15r may in turn exert the setting force on an upper portion of the liner hanger 15h via the packer 15p.
The liner hanger upper portion may initially be restrained from setting the liner hanger 15h by a shearable fastener. Once a first threshold pressure on the actuator piston has been reached, the shearable fastener may fracture, thereby releasing the liner hanger upper portion. The actuator piston, actuator sleeves, lock sleeve, the debris barrier 51, PBR
15r, packer 15p, and liner hanger upper portion may travel downward until slips of the liner hanger 15h are set against the casing 25, thereby halting the movement.
Continued pumping of the conditioner 43 may further pressurize the actuation chamber until a second threshold pressure is reached, thereby fracturing a shearable fastener and releasing the debris barrier 51 from the actuator piston. The liner hanger 15h may be restrained from unsetting by a lower ratchet connection. Downward movement of the actuator piston and actuator sleeves may continue until the actuator piston reaches a lower end of the actuation chamber. Continued pumping of the conditioner 43 may further pressurize the LDA bore (above the seated ball 50).
An actuation chamber of the running tool 53 may be pressurized and exert pressure on the running tool piston. Once a third threshold pressure on the running tool piston has been reached, a shearable fastener may fracture, thereby releasing the running tool piston.
The running tool piston may travel upward, thereby unlocking the running tool 53.
Once the liner hanger 15h has been set against an inner surface of a lower portion, such as the bottom, of the casing string 25 and the running tool 53 unlocked, the workstring 9 may be rotated, thereby releasing the floating nut of the running tool from a threaded profile of the liner mandrel 15m. The workstring 9 may be raised to verify successful release and lowered to torsionally engage the running tool 53 with the liner string 15 for rotation during the first stage of the cementing operation.
Alternatively, the liner string 15 may be hung from another liner string cemented into the wellbore instead of the casing string 25.
Figure 2 illustrates the plug release system 55. The plug release system 55 may include a relief valve 62 and one or more plugs, such as a shutoff plug 63, an opener plug 64, and the closer plug 65. The relief valve 62 may include a housing 62h, an outer wall 62w, a cap 62c, a piston 62p, a spring 62s, a fastener, such as collet 62f, and a seal insert 62i. The housing 62h, outer wall 62w, and cap 62c may be interconnected, such as by threaded couplings.
The piston 62p and spring 62s may be disposed in an annular chamber formed radially between the housing 62h and the outer wall 62w and longitudinally between a shoulder of the housing and a shoulder of the cap 62c. The piston 62p may divide the chamber into an upper portion and a lower portion and carry a seal for isolating the portions. The cap 62c and housing 62h may also carry seals for isolating the portions.
The outer wall 62w may have one or more (pair shown) inlet ports 62n formed therethrough for providing fluid communication between the surge chamber and a lower face of the piston 62p. An outlet port may be formed by a gap between a bottom of the housing 62h and a top of the cap 62c. An equalization port 62e may be formed through a wall of the housing 62h for providing fluid communication between an upper face of the piston 62p and the valve bore.
The piston 62p may be longitudinally movable between an upper open position (not shown) and a lower closed position. The spring 62s may be disposed between an upper face of the piston 62p and an upper end of the chamber, thereby biasing the piston toward the lower closed position. The piston 62p may move to the upper open position in response to pressure in the surge chamber being greater than pressure in the valve bore by a pressure differential sufficient to overcome a biasing force of the spring 62s. The housing 62h and cap 62c may each carry a seal straddling the outlet port and the piston 62p may be aligned with the outlet port and engaged with the seals in the lower closed position, thereby isolating the outlet port from the inlet ports 62n.
The piston 62p may be clear of the outlet port in the upper open position, thereby allowing fluid communication between the inlet 62n and outlet ports.
Alternatively, the spring 62s may have a nominal stiffness or be omitted and the valve 62 may function as a check valve instead of a relief valve.
Each plug 63-65 may be made from a drillable material and include a respective finned seal 63f-65f, a plug body 63b-65b, a latch sleeve 63v-65v, a lock sleeve 63k-65k, and a landing shoulder 63r-65r. Each latch sleeve 63v-65v may have a collet formed in an upper end thereof and the closer 65r landing shoulder and opener body 64b may each have a respective collet profile formed in a lower portion thereof. Each lock sleeve 63k-65k may have a respective seat 63s-65s and seal bore 63e-65e formed therein.
Each lock sleeve 63k-65k may be movable between an upper position and a lower position and be releasably restrained in the upper position by a respective shearable fastener 63h-65h. The shutoff 63r and opener 64r landing shoulders may each carry a landing seal. The finned seals 63f-65f (except for glands) may be made from an elastomer or elastomeric copolymer and the sleeves 63k,v-65k,v, bodies 63b-65b, fin glands, and shoulders 63r-65r may be made from a nonferrous metal or alloy.
The closer shearable fastener 65h may releasably connect the closer lock sleeve 65k to the valve housing 62h and the closer lock sleeve 65k may be engaged with the valve collet 62f in the upper position, thereby locking the valve collet into engagement with the collet of the closer latch sleeve 65v. The opener shearable fastener 64h may releasably connect the opener lock sleeve 64k to the closer landing shoulder 65r and the opener lock sleeve may be engaged with the collet of the opener latch sleeve 64v, thereby locking the collet into engagement with the collet profile of the opener landing shoulder. The shutoff shearable fastener 63h may releasably connect the shutoff lock sleeve 63k to the opener body 64b and the shutoff lock sleeve may be engaged with the collet of the shutoff latch sleeve 63v, thereby locking the collet into engagement with the collet profile of the opener body.
The shutoff plug 63 may include one or more (pair shown) bypass ports formed through a wall of the shutoff body 63b and initially sealed by a burst tube 69 to prevent fluid flow therethrough. The burst tube 69 may be operable to rupture when a predetermined pressure is applied thereto. To facilitate subsequent drill-out, the shutoff landing shoulder 63r may have a portion of an auto-orienting torsional profile 70m,f formed at a bottom thereof.
Alternatively, the opener landing shoulder 64r and/or the closer landing shoulder 65r may also have a portion of the auto-orienting torsional profile 70m,f formed at a bottom and/or outer surface thereof. Alternatively, the opener plug 64 may also include a one or more (second) bypass ports formed through a wall of the opener body 64b and initially sealed by a (second) burst tube to prevent fluid flow therethrough.
The second burst tube may be operable to rupture when a predetermined (second) pressure is applied thereto. The second burst tube may be ruptured in the event of failure of the packing stage collar 15o.
The landing collar 15c may include a housing and a seat disposed therein and connected thereto, such as by threaded couplings. The seat may have longitudinal holes drilled in a wall thereof from a bottom thereof and extending along a length thereof. The holes may terminate adjacent a top of the seat to impart flexibility thereto for receiving the landing shoulder 63r of the shutoff plug 63. The seat may have a bore formed therethrough and the other portion 70f of the torsional profile 70m,f formed in an upper face thereof for engagement with the portion 70m of the shutoff plug 63.
The seat may also have a seal bore formed therein for receiving the landing seal of the landing shoulder 63r.
Figures 3A-3C illustrate activators, such as darts 66-68, for releasing the respective plugs 63-65. Each dart 66-68 may be made from a drillable material and include a respective finned seal 66f-68f, dart body 66b-68b, landing cap 66c-68c, and retainer head 66h-68h. Each landing cap 66c-68c may have a respective landing shoulder 66r-68r and carry a respective landing seal 66s-68s for engagement with the respective seat 63s-65s and seal bore 63e-65e. A major diameter of the shutoff shoulder 66r may be less than a minor diameter of the opener seat 64s and a major diameter of the opener shoulder 67r may be less than a minor diameter of the closer seat 65s such that the shutoff dart 66 may pass through the closer 65 and opener 64 plugs and the opener dart 67 may pass through the closer plug 64. The finned seals 66f-68f (except for glands) and retainer heads 66h-68h (except for glands) may be made from an elastomer or elastomeric copolymer and the caps 66c-68c, bodies 66b-68b, fin glands, and head glands may be made from a nonferrous metal or alloy.
Alternatively, one or more of the activators may be balls instead of the darts and the balls may be pumped or dropped to the respective plugs.
Figures 4A and 4B illustrate the packing stage collar 15o. The packing stage collar 71 may include a stage valve 71, an inflator 72, and a packer 73. The stage valve 71 may include a housing 74, a sleeve 75, an opener seat 76, and a closer seat 77.
The housing 74 may be a tubular member having threaded couplings formed at each longitudinal end thereof for connection to a liner joint 15j at an upper end thereof and for connection to the inflator 72 at a lower end thereof. The sleeve 75 may be disposed in the housing 74 and longitudinally movable relative thereto between a deployment (or upper closed) position (shown), an open position (Figure 5E), and a (lower) closed position (Figure 5J).
In the deployment position, the closer seat 77 and sleeve 75 may be releasably connected to the housing, such as by one or more (pair shown) shearable fasteners 78u. The shearable fasteners 78u may each be operable to fracture a first time at an outer interface between the housing 74 and the sleeve 75 in response to engagement of the landing shoulder 64r of the opener plug 64 with the opener seat 76, thereby releasing the sleeve 75 and closer seat 77 from the housing 74. The shearable fasteners 78u may each be operable to fracture a second time at an inner interface between the closer seat 77 and the sleeve 75 in response to engagement of the landing shoulder 65r of the closer plug 65 with the closer seat, thereby releasing the closer seat from the sleeve 75.
A major diameter of the shutoff shoulder 63r may be less than a minor diameter of the opener seat 76 and a major diameter of the opener shoulder 64r may be less than a minor diameter of the closer seat 77 such that the shutoff plug 63 may pass through the closer 77 and opener 76 seats and the opener plug 64 may pass through the closer seat. The seats 76, 77 may be made from a drillable material, such as a nonferrous metal or alloy.
The closer seat 77 may be longitudinally movable relative to the sleeve 75 between an upper lock position (shown) and a lower release position (Figure 5J). The closer seat 77 may engage a shoulder formed in an inner surface of the sleeve 75 in the release position. The sleeve 75 may also be linked to the housing 74 by a slip joint 79.
The slip joint 79 may include one or more (pair shown) slots 790 formed in an inner surface of the housing 74, one or more (pair shown) fasteners, such as dogs 79d, and a groove 79i formed in an outer surface of the closer seat 77. A (non-grooved) portion of the closer seat outer surface may serve as a locking sleeve of the slip joint 79 when aligned (shown) in the lock position. The dogs 79d may be carried in respective sockets formed through a wall of the sleeve 75 and may be radially movable thereto between an extended position (shown) and a retracted position (Figure 5J). The dogs 79d may extend into the respective slots 790 in the extended position, thereby torsionally connecting the sleeve 75 and the housing 74 while allowing relative longitudinal movement therebetween. The dogs 79d may be allowed to retract by alignment of the groove 79i therewith when the closer seat 77 is in the release position.
The sleeve 75 may have one or more (pair shown) stage ports 80m formed through a wall thereof and the housing 74 may have one or more (pair shown) corresponding stage ports 80h formed through a wall thereof. The sleeve 75 may carry a pair of seals 81a,b straddling the stage ports 80m thereof and also carry a lower seal 81c adjacent to a lower end thereof for isolating the housing stage ports 80h in the deployment position. An outer surface of the sleeve 75 may cover the housing stage ports 80h in the deployment and closed positions and the sleeve stage ports 80m may be aligned with the housing stage ports in the open position. The closer seat 76 may be connected to the sleeve 75, such as by threaded couplings.
The inflator 72 may include a stop 82, a switch valve 83, a body 84, a check valve 85, one or more (pair shown) biasing members, such as compression springs 86, and an upper portion of a mandrel 87. The stop 82 may be a ring fastened to the housing 74 and sealingly engaged with the switch valve 83, such as by a lap joint. The switch valve 83 may be disposed along an outer surface of the housing 74 and longitudinally movable relative thereto between an upper inflation position (shown) and a lower cementing position (Figure 5G). In the inflation position, the switch valve 83 may be releasably connected to the housing 74, such as by one or more (pair shown) shearable fasteners 78b. In the inflation position, the switch valve 83 may isolate the housing ports 80h from fluid communication with the annulus 48 and instead divert fluid flow therefrom down an upper annular gap 88u formed between the switch valve and the housing, one or more (pair shown) flow passages 88p formed in a wall of the body 84, and a lower annular gap 88b formed between the body and the mandrel 87.
The fluid may flow down the flow path 88u,p,b to the check valve 85. The switch valve 83 may move to the lower cementing position in response to sufficient fluid pressure exerted on a piston shoulder thereof to fracture the shearable fasteners 78b.
The switch valve 83 may then move downward until a bottom thereof engages a shoulder formed in an outer surface of the valve body 84.
The body 84 may be a tubular member having threaded couplings formed at each longitudinal end thereof for connection to the housing 74 at an upper end thereof and for connection to the mandrel 87 at a mid portion thereof. The mandrel 87 may be a tubular member having threaded couplings formed at each longitudinal end thereof for connection to the body 84 at an upper end thereof and for connection to a liner joint 15j at a lower end thereof. A bottom of the body 84 may be beveled for receiving the check valve 85. The check valve 85 may be longitudinally movable relative to the body 84 between a closed position (shown) and an open position (Figure 5F). The check valve 85 may have a beveled top carrying a seal for closing against the body 84. The springs 86 may be disposed between the check valve 85 and the packer 73 for biasing the check valve toward the closed position. Fluid pressure exerted on the beveled top of the check valve 85 may drive the check valve toward the open position against the springs 86.
The packer 73 may include a lower portion of the mandrel 87, an upper retainer 89u, a lower retainer 89b, an upper gland 90u, a lower gland 90b, a bladder 91, a seal keeper 92, and a sliding seal 93. The upper retainer 89u may be fastened to the valve body 84 and connected to the upper gland 90u, such as by threaded couplings.
The bladder 91 may include an outer packing element made from an elastomer or elastomeric copolymer and one or more (two shown) inner layers of reinforcement.
Each longitudinal end of the bladder 91 may be molded on or bonded to the respective gland 90u,b.
The bladder 91 may extend along an outer surface of the mandrel 87 and be radially displaceable between a deflated position (shown) and an inflated position (Figure 5F). The bladder 91 may be inflated by fluid flowing down the flow path 88u,p,b, through the open check valve 85, and down an upper annular gap 94u formed between the check valve 85 and the upper retainer 89u, a circumferential space (not shown) formed between the springs 86, and a lower annular gap 94b formed between the mandrel 87 and the upper retainer 89u. The fluid may flow to an inflation chamber formed between the bladder 91 and the mandrel 87 and exert inflation pressure against the sliding seal 93 isolating an interface formed between the lower retainer 89b and the mandrel 87.
Figures 5A-5J illustrate staged cementing of the liner string 15. Referring specifically to Figure 5A, the workstring 9 and liner string 15 (except for the set hanger 15h) may be rotated 49 from surface by the top drive 5 and rotation may continue during the cementing operation. Rotation of the rest of the liner string 15 relative to the set hanger 15h may be facilitated by a thrust bearing. The first stage cement slurry 95a may be pumped from the mixer 42 into the cementing swivel 7c via the valve 41c by the cement pump 13. The first stage cement slurry 95a may flow into the launcher 7r and be diverted past the shutoff dart 66 via the diverter and bypass passages.

Once the desired quantity of the first stage cement slurry 95a has been pumped, the shutoff dart 66 may be released from the launcher 7r by operating the launcher actuator. The desired quantity of the first stage cement slurry 95a may correspond to a volume of the annulus 48 between the packing stage collar 15o and the reamer shoe 15s. Chaser fluid 47 may be pumped into the cementing swivel 7c via the valve 41c by the cement pump 13. The chaser fluid 47 may flow into the launcher 7r and be forced behind the shutoff dart 66 by closing of the bypass passages, thereby propelling the shutoff dart into the workstring bore. Pumping of the chaser fluid 47 by the cement pump 13 may continue until residual cement in the cement line 14 has been purged.
Pumping of the chaser fluid 47 may then be transferred to the mud pump 34 by closing the valve 41c and opening the valve 6. The shutoff dart 66 and first stage cement slurry 95a may be driven through the workstring bore by the chaser fluid 47.
Once a slug 47s of chaser fluid 47 has been pumped, a second release plug launcher (not shown) of the cementing head 7 may be operated to launch the opener dart 67. A volume of the slug 47s may correspond to, such as being slightly greater than, a volume of the liner string bore between the landing collar 15c and the opener seat 76. A train of the opener dart 67, slug 47s, shutoff dart 66, and first stage cement slurry 95a, may be driven through the workstring bore by the chaser fluid 47.
Referring specifically to Figure 5B, the shutoff dart 66 may reach the shutoff plug 63 and the landing shoulder 66r and seal 66s of the dart may engage the seat 63s and seal bore 63e of the plug. Continued pumping of the chaser fluid 47 may increase pressure in the workstring bore against the seated shutoff dart 66 until a release pressure is achieved, thereby fracturing the shearable fastener 63h. The shutoff dart 66 and lock sleeve 63k may travel downward until reaching a stop of the shutoff plug 63, thereby freeing the collet of the latch sleeve 63v and releasing the plug from the rest of the plug release system 55.
Referring specifically to Figure 5C, continued pumping of the chaser fluid 47 may drive the first stage cement slurry 95a and engaged shutoff dart 66 and plug 63 through the liner bore. The first stage cement slurry 95a may be driven downward through the float collar 15f and the reamer shoe 15s and upward into the annulus 48 until the landing shoulder 63r engages the seat of the landing collar 15c.
Referring specifically to Figure 5D, continued pumping of the chaser fluid 47 may increase pressure in the workstring and liner bore against the seated shutoff dart 66 and plug 63 until the rupture pressure is achieved, thereby rupturing the burst tube 69 and opening the bypass ports of the shutoff plug. A portion of the slug 47s may flow around the shutoff dart 66 and through the shutoff plug 63, thereby allowing the opener dart 67 to reach the opener plug 64. The landing shoulder 67r and seal 67s of the opener dart 67 may engage the seat 64s and seal bore 64e of the opener plug 64. Continued pumping of the chaser fluid 47 may increase pressure in the workstring bore against the seated opener dart 67 until a release pressure is achieved, thereby fracturing the shearable fastener 64h. The opener dart 67 and lock sleeve 64k may travel downward until reaching a stop of the opener plug 64, thereby freeing the collet of the latch sleeve 64v and releasing the plug from the rest of the plug release system 55.
Referring specifically to Figure 5E, continued pumping of the chaser fluid 47 may drive the engaged opener dart 67 and plug 64 through the liner bore to the packing stage collar 150. The landing shoulder 64r and seal thereof may engage the opener seat 76 (and a seal bore thereof) of the packing stage collar 15o. Continued pumping of the chaser fluid 47 may increase pressure in the workstring and liner bore against the seated opener plug 64 until a release pressure is achieved, thereby fracturing the shearable fasteners 78u at the outer interface. The opener dart 67, plug 64, and seat 76, the sleeve 75, and the closer seat 77 may travel downward until the dogs 79d engage a bottom of the slots 79o, thereby aligning the sleeve ports 80m with the housing ports 80h. Rotation 49 of the liner string 15 may then be halted by torsionally disengaging the running tool 53 from the liner string 15 (workstring 9 may then continue to be rotated) or by halting rotation by the top drive 5.
Referring specifically to Figure 5F, continued pumping of the chaser fluid 47 may open the check valve 85 and inflate the bladder 91 against an exposed wall of the wellbore 24, thereby isolating the first stage cement slurry 95a in a lower portion of the annulus 48 from an upper portion of the annulus. The closer dart 68 may be loaded into the launcher 7r or the cementing head 7 may have a third launcher.
Referring specifically to Figure 5G, conditioner 43 may again be circulated by the cement pump 13 through the valve 41 to prepare for pumping of second stage cement slurry 95b. As the conditioner is being pumped into the workstring bore, pressure may increase until a release pressure is achieved, thereby fracturing the shearable fasteners 78b. The switch valve 83 may travel downward until reaching the stop of the body 84, thereby exposing the housing ports to the upper portion of the annulus 48 and allowing circulation of the conditioner 43 through the annulus upper portion.
Referring specifically to Figure 51-1, the second stage cement slurry 95b may be pumped from the mixer 42 into the cementing swivel 7c via the valve 41c by the cement pump 13. Once the desired quantity of the second stage cement slurry 95b has been pumped, the closer dart 68 may be released from the launcher 7r by operating the launcher actuator. The closer dart 68 and second stage cement slurry 95b may be driven through the workstring bore by the chaser fluid 47. The closer dart 68 may reach the closer plug 65 and the landing shoulder 68r and seal 68s of the dart may engage the seat 65s and seal bore 65e of the plug. Continued pumping of the chaser fluid 47 may increase pressure in the workstring bore against the seated closer dart 68 until a release pressure is achieved, thereby fracturing the shearable fastener 65h.
The closer dart 68 and lock sleeve 65k may travel downward until reaching a stop of the closer plug 65, thereby freeing the collet of the latch sleeve 65v and releasing the plug from the relief valve 62.
Referring specifically to Figure 51, continued pumping of the chaser fluid 47 may drive the engaged closer dart 68 and plug 65 through the liner bore to the packing stage collar 150. The second stage cement slurry 95b may be driven through the aligned sleeve 80m and housing 80p ports into the upper annulus portion and upward through the annulus 48 to the liner hanger 15h.
Referring specifically to Figure 5J, the landing shoulder 65r may engage the closer seat 77 and continued pumping of the chaser fluid 47 may increase pressure in the workstring and liner bore against the seated closer plug 65 until a release pressure is achieved, thereby fracturing the shearable fasteners 78u at the inner interface. The closer dart 68, plug 65, and seat 77, may travel downward until a bottom of the closer seat 77 engages the sleeve shoulder, thereby freeing the dogs 79d. The opener and closer darts 67, 68, plugs 64, 65, and seats 76, 77 and the sleeve 75 may travel downward until a bottom of the sleeve engages a top of the body 84, thereby closing the stage valve 71.
Figure 5K illustrates setting of the packer 15p. The workstring 9 (except for the lock sleeve and debris barrier 51) may be raised until the actuator cylinder top engages the lock sleeve bottom. Continued raising may exert a threshold force to fracture shearable fasteners, thereby releasing the lock sleeve from the debris barrier 51.
Continued raising may move the lock sleeve from engagement with dogs of the latch 61 and release the debris barrier 51 from the PBR 15r. The raising may continue and torsional profiles of the cylinder and debris barrier may engage. The raising may continue until the packer actuator 59 exits the PBR 15r, thereby allowing the dogs thereof to extend and engage the PBR top.
The workstring 9 may be rotated and lowered, thereby exerting weight on the PBR 15r via the engaged dogs. The PBR 15r may in turn exert the weight on the packer upper portion. A shearable fastener may fracture, thereby releasing the packer upper portion from the liner mandrel 15m and expanding the packer 15p into engagement with the casing 25. The packer 15p may be restrained from unsetting by a ratchet connection. The workstring 9 may then be raised, thereby rotating the debris barrier 51 via the engaged cylinder torsional profile and chaser fluid circulated to ream and wash away any excess second stage cement slurry 95b. The workstring 9 may then be retrieved to the MODU lm.
Alternatively, the shutoff dart 66 and plug 63 may be omitted and the lower portion of the annulus 48 not be cemented. This alternative may be especially useful for a lower portion of the liner string 15 being slotted, sand screen, or expandable sand screen instead of solid liner joints 15j.

Alternatively, the stage valve 71 may be assembled as part of the liner string without the inflator 72 and packer 73. In this alternative, the first stage cement slurry 95a would be allowed to cure before pumping the second stage cement slurry.
Alternatively, the stage valve 71 and a separate packer may be assembled as part of the liner string 15 and the shutoff plug 63 used to inflate the separate packer.
Alternatively, the plug release system 55, darts 66-68, and packing stage collar 150 (or any alternatives discussed above) may be used to cement a subsea casing string into the wellbore 24 instead of the liner string 15. The subsea casing string may extend to and be hung from the subsea wellhead 10.
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.

Claims

Claims:

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

2. The method of claim 1, wherein:
each of the activators is a dart, and the opener dart is delivered to the deployment assembly by pumping.

3. The method of claim 2, wherein:
the cement slurry is second stage and is pumped into an upper portion of the annulus, and the method further comprises:
pumping first stage cement slurry into the workstring;
pumping a shutoff dart through the workstring behind the first stage cement slurry, thereby launching a shutoff plug from the deployment assembly;
and pumping the shutoff dart and plug to a landing collar of the tubular string, thereby driving the first stage cement slurry into a lower portion of the annulus.

4. The method of claim 3, further comprising pumping a slug of chaser fluid between the shutoff dart and the opener dart, wherein the opener dart, slug, shutoff dart, and first stage cement slurry are pumped down the workstring in a train.

5. The method of claim 4, wherein a portion of the shutoff plug ruptures while pumping the opener dart and plug to the stage valve, thereby opening a bypass passage therethrough.

6. The method of claim 3, further comprising inflating a bladder against a wall of the wellbore after driving the first stage cement slurry into the annulus lower portion and before pumping the second stage cement slurry into the workstring.

7. The method of claim 3, further comprising rotating the tubular string while driving the first stage cement slurry into the annulus.

8. The method of claim 1, wherein:
the stage valve is part of a packing stage collar, and the method further comprises inflating a bladder of the stage collar against a wall of the wellbore after opening the stage valve and before pumping the cement slurry.

9. The method of claim 8, wherein:
the bladder is inflated by fluid flow through stage ports of the packing stage collar, and the stage ports open to the annulus after inflating the bladder and before pumping the cement slurry.

10. The method of claim 1, wherein:
the tubular string is a liner string, and the method further comprises setting a hanger of the liner string against a lower portion of an outer tubular string previously cemented into the wellbore.

11. The method of claim 10, wherein:
the deployment assembly comprises a seat and a setting tool having:
a debris barrier closing an upper end of the liner string, a packoff sealing an interface between the setting tool and the liner string, a piston having an upper face in communication with a bore of the setting tool and a lower face in communication with the interface below the packoff, and a latch releasably connecting the piston to the debris barrier and releasably connecting the debris barrier to the liner string, and the hanger is set by pumping a setting plug to the seat, thereby operating the piston to set the hanger and releasing the debris barrier from the piston.

12. The method of claim 11, wherein:
the setting tool further has a packer actuator, and the method further comprises:
after closing the stage valve, raising the setting tool from the liner string, thereby operating the latch to release the debris barrier from the liner string and extending the packer actuator against the upper end; and after raising the setting tool, setting weight on the packer actuator and upper end, thereby setting a packer of the liner string.

13. A system for cementing a tubular string into a wellbore, comprising:
a stage valve for assembly as part of the tubular string and having: a housing, a stage port formed through the housing, a sleeve, a stage port formed through the sleeve, an opener seat connected to the sleeve, and a closer seat linked to the sleeve;
a plug release system for operating the stage valve, comprising:
a closer plug having: a body, a finned seal, a latch sleeve, a lock sleeve for releasing the latch sleeve, and a landing shoulder for engaging the closer seat; and an opener plug having: a body, a finned seal, a latch sleeve, a lock sleeve for releasing the latch sleeve, and a landing shoulder for engaging the opener seat; and a closer activator for engaging the closer lock sleeve; and an opener activator for engaging the opener lock sleeve.

14. The system of claim 13, wherein each of the activators is a dart.

15. The system of claim 14, wherein:
the system further comprises a landing collar for assembly as part of the tubular string and having a seat, the plug release system further comprises a shutoff plug having a body, a finned seal, a latch sleeve, a lock sleeve for releasing the latch sleeve, a bypass port formed through the body, a burst tube initially closing the bypass port, and a landing shoulder for engaging the landing collar seat, and the system further comprises a shutoff dart for engaging the shutoff lock sleeve.

16. The system of claim 13, wherein the stage valve is part of a packing stage collar further comprising:
a mandrel connected to the housing;
an inflatable bladder disposed along the mandrel; and an inflator, comprising:
an inflation path in fluid communication with an inflation chamber formed between the mandrel and the bladder;
a check valve disposed along the inflation path; and a switch valve operable between an inflation position and a cementing position, the switch valve diverting flow from the stage ports to the inflation path in the inflation position.

17. The system of claim 13, wherein the plug release system further comprises a valve for providing fluid communication between a bore of the tubular string and a bore of the plug release system in response to pressure in the tubular string bore being greater than pressure in the plug release system bore.

18. The system of claim 13, further comprising a polished bore receptacle (PBR) for assembly as part of the tubular string, a packer coupled to the PBR, a liner hanger coupled to the packer, and a mandrel carrying the hanger and packer.

19. The system of claim 18, further comprising a deployment assembly having the plug release system, a seat for receiving a setting plug, and a setting tool having:
a debris barrier for engagement with the PBR, a packoff for sealing an interface between the setting tool and the tubular string, a piston operable to set the liner hanger and having an upper face in communication with a bore of the setting tool and a lower face in communication with the interface below the packoff, and a latch releasably connecting the piston to the debris barrier and releasably connecting the debris barrier to the PBR.

20. The system of claim 19, wherein the setting tool further has a packer actuator:
operable between an extended position and a retracted position, for being restrained in the retracted position by being disposed in the tubular string, and extendable by being removed from the tubular string.