Patent Grant
9428998
1. Field of the Disclosure
The present disclosure generally relates to a telemetry operated setting tool.
2. Description of the Related Art
A wellbore is formed to access hydrocarbon bearing formations, e.g. crude oil and/or natural gas, by the use of drilling. Drilling is accomplished by utilizing a drill bit that is mounted on the end of a tubular string, such as a drill string. To drill within the wellbore to a predetermined depth, the drill string is often rotated by a top drive or rotary table on a surface platform or rig, and/or by a downhole motor mounted towards the lower end of the drill string. After drilling to a predetermined depth, the drill string and drill bit are removed and a section of casing is lowered into the wellbore. An annulus is thus formed between the string of casing and the formation. The casing string is cemented into the wellbore by circulating cement into the annulus defined between the outer wall of the casing and the borehole. The combination of cement and casing strengthens the wellbore and facilitates the isolation of certain areas of the formation behind the casing for the production of hydrocarbons.
It is common to employ more than one string of casing or liner in a wellbore. In this respect, the well is drilled to a first designated depth with a drill bit on a drill string. The drill string is removed. A first string of casing is then run into the wellbore and set in the drilled out portion of the wellbore, and cement is circulated into the annulus behind the casing string. Next, the well is drilled to a second designated depth, and a second string of casing or liner, is run into the drilled out portion of the wellbore. If the second string is a liner string, the liner is set at a depth such that the upper portion of the second string of casing overlaps the lower portion of the first string of casing. The liner string may then be hung off of the existing casing. The second casing or liner string is then cemented. This process is typically repeated with additional casing or liner strings until the well has been drilled to total depth. In this manner, wells are typically formed with two or more strings of casing/liner of an ever-decreasing diameter.
The liner string is typically deployed to a desired depth in the wellbore using a workstring. A setting tool of the liner string is then operated to set the liner hanger against a previously installed casing string. The setting tool is typically operated by pumping a ball through the workstring to a seat located below the setting tool. Pressure is exerted on the seated ball to operate the setting tool. Such a setting tool may limit operational flexibility in deploying the liner string as a pressure surge could unintentionally operate the setting tool before the liner string has reached the desired depth.
The present disclosure generally relates to a telemetry operated setting tool. In one embodiment, a setting tool for hanging a tubular string from a liner string, casing string, or wellhead includes: a mandrel having an upper portion and a lower portion for extending into the tubular string; a housing connected to the mandrel upper portion; and a bonnet. The bonnet is: for receiving an upper end of the tubular string, disposed along the mandrel, and linked to the housing. The setting tool further includes: an actuator for stroking the bonnet relative to the mandrel and the housing, thereby setting a hanger of the tubular string; an electronics package in communication with the actuator for operating the actuator in response to receiving a command signal; and a latch. The latch is: connected to the mandrel lower portion, 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.
In another embodiment, a method of hanging a tubular string from a liner string, casing string, or wellhead, includes running the tubular string into a wellbore using a deployment string and a deployment assembly. The deployment assembly includes a setting tool closing an upper end of the tubular string. The method further includes: sending a first command signal to the setting tool, thereby setting a hanger of the tubular string; after hanging the tubular string, raising the setting tool from the tubular string, thereby extending a latch of the setting tool against the upper end; and after raising the setting tool, setting weight on the latch and upper end, thereby setting a packer of the tubular string.
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.
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. 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 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 1r 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 8 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 11t of the hoist. The frame of the top drive 5 may be suspended from the derrick 3 by the traveling block 11t. The quill may be torsionally driven by the top drive motor and supported from the frame by bearings. The top drive 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 drilling rig 1r may further include a drill string compensator (not shown) to account for heave of the MODU 1m. The drill string compensator may be disposed between the traveling block 11t and the top drive 5 (aka hook mounted) or between the crown block 11c 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 liner deployment assembly (LDA) 9d and a deployment string, 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 setting sleeve 15v, a polished bore receptacle (PBR) 15r, a packer 15p, a liner hanger 15h, joints of liner 15j, a landing collar 15c, and a reamer shoe 15s. The PBR 15r, liner joints 15j, landing collar 15c, and reamer shoe 15s may be interconnected, such as by threaded couplings. The reamer shoe 15s may be rotated 8 by the top drive 5 via the workstring 9.
Alternatively, drilling fluid may be injected into the liner string 15 during deployment thereof. Alternatively, drilling fluid may be injected into the liner string 15 and the liner string may include a drillable drill bit (not shown) instead of the reamer shoe 15s and the liner string may be drilled into the lower formation 27b, thereby extending the wellbore 24 while deploying the liner string.
Once liner deployment has concluded, the workstring 9 may be disconnected from the top drive 5 and the cementing head 7 may be inserted and connected therebetween. The cementing head 7 may include an isolation valve 6, an actuator swivel 7h, a cementing swivel 7c, and a plug launcher, such as a dart launcher 7d. The isolation valve 6 may be connected to a quill of the top drive 5 and an upper end of the actuator swivel 7h, 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 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 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 8 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 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 cementing mandrel port may provide fluid communication between a bore of the cementing head and the housing inlet. The seal assembly may include one or more stacks of V-shaped seal rings, such as opposing stacks, disposed between the mandrel and the housing and straddling the inlet-port interface. The actuator swivel 7h may be similar to the cementing swivel 7c except that the housing may have two 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 launcher 7d. The actuator swivel inlets may be in fluid communication with a hydraulic power unit (HPU, not shown).
Alternatively, the seal assembly may include rotary seals, such as mechanical face seals.
The dart launcher 7d may include a body, a diverter, a canister, a latch, and the actuator. The body may be tubular and may have a bore therethrough. To facilitate assembly, the body may include two or more sections connected together, such as by threaded couplings. An upper end of the body may be connected to a lower end of the actuator swivel, such as by threaded couplings and a lower end of the body may be connected to the workstring 9. The body may further have a landing shoulder formed in an inner surface thereof. The canister and diverter may each be disposed in the body bore. The diverter may be connected to the body, 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 may be formed between the ribs. The canister may further have a landing shoulder formed in a lower end thereof corresponding to the body landing shoulder. The diverter may be operable to deflect fluid received from a cement line 14 away from a bore of the canister and toward the bypass passages. A release plug, such as a dart 43, may be disposed in the canister bore.
The launcher latch may include a body, a plunger, and a shaft. The latch body may be connected to a lug formed in an outer surface of the launcher body, such as by threaded couplings. The plunger may be longitudinally movable relative to the latch body and radially movable relative to the launcher body between a capture position and a release position. The plunger may be moved between the positions by interaction, such as a jackscrew, with the shaft. The shaft may be longitudinally connected to and rotatable relative to the latch body. The actuator may be a hydraulic motor operable to rotate the shaft relative to the latch body.
Alternatively, the actuator swivel and launcher actuator may be pneumatic or electric. Alternatively, the launcher actuator may be linear, such a piston and cylinder.
In operation, when it is desired to launch the dart 43, the HPU may be operated to supply hydraulic fluid to the launcher actuator via the actuator swivel 7h. The launcher actuator may then move the plunger to the release position (not shown). The canister and dart 43 may then move downward relative to the housing until the landing shoulders engage. Engagement of the landing shoulders may close the canister bypass passages, thereby forcing fluid to flow into the canister bore. The fluid may then propel the dart 43 from the canister bore into a lower bore of the housing and onward through the workstring 9.
The fluid transport system 1t may include an upper marine riser package (UMRP) 16u, a marine riser 17, a booster line 18b, and a choke line 18c. The riser 17 may extend from the PCA 1p to the MODU 1m 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 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 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 PCA 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 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 pilot bit and underreamer (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 PCA 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 PCA 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 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 rig controller (not shown) onboard the MODU 1m via an umbilical 33. 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 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 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 rig controller may operate the PCA 1p via the umbilical 33 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 (not shown). A lower end of the choke line 18c 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.
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 33 may extend between the MODU 1m and the PCA 1p 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 1h may include one or more pumps, such as a cement pump 13 and a mud pump 34, a reservoir for drilling fluid 47m, such as a tank 35, a solids separator, such as a shale shaker 36, one or more pressure gauges 37c,m, one or more stroke counters 38c,m, one or more flow lines, such as cement line 14, mud line 39, and return line 40, a cement mixer 42, and one or more tag launchers 44a,b. The drilling fluid 47m may include a base liquid. The base liquid may be refined or synthetic oil, water, brine, or a water/oil emulsion. The drilling fluid 47m may further include solids dissolved or suspended in the base liquid, such as organophilic clay, lignite, and/or asphalt, thereby forming a mud.
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 37m 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 tag launcher 44, a shutoff valve 41, and the 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 cement pump 13.
Each tag launcher 44a,b may include a housing, a plunger, an actuator, and a magazine (not shown) having a plurality of respective wireless identification tags, such as radio frequency identification (RFID) tags, loaded therein. A chambered RFID tag 45a,b may be disposed in the respective plunger for selective release and pumping downhole to communicate with the LDA 9d. Each plunger may be movable relative to the respective launcher housing between a captured position and a release position. Each plunger may be moved between the positions by the respective actuator. The actuator may be hydraulic, such as a piston and cylinder assembly.
Alternatively, each actuator may be electric or pneumatic. Alternatively, each actuator may be manual, such as a handwheel. Alternatively, each tag 45a,b may be manually launched by breaking a connection in the respective line. Alternatively, each tag launcher may be part of the cementing head.
The workstring 9 may be rotated 8 by the top drive 5 and lowered by the traveling block 11t, thereby reaming the liner string 15 into the lower formation 27b. Drilling fluid in the wellbore 24 may be displaced through courses 15e of the reamer shoe 15s, where the fluid may circulate cuttings away from the shoe and return the cuttings into a bore of the liner string 15. The returns 47r (drilling fluid plus cuttings) may flow up the liner bore and into a bore of the LDA 9d. The returns 47r may flow up the LDA bore and to a diverter valve 50 thereof. The returns 47r may be diverted into an annulus 48 formed between the workstring 9/liner string 15 and the casing string 25/wellbore 24 by the diverter valve 50. The returns 47r may exit the wellbore 24 and flow into an annulus formed between the riser 17 and the drill pipe 9p via an annulus of the LMRP 16b, BOP stack, and wellhead 10. The returns 47r may exit the riser annulus and enter the return line 40 via an annulus of the UMRP 16u and the diverter 19. The returns 47r may flow through the return line 40 and into the shale shaker inlet. The returns 47r may be processed by the shale shaker 36 to remove the cuttings.
A lower end of the liner hanger 15h may be fastened to the PBR 15r, such as by an emergency release connection 15o to longitudinally and torsionally connect the hanger lower portion to the PBR 15r unless an emergency release maneuver is performed. The emergency release connection 15o may include a pair of bayonet couplings connected together by a shearable fastener. An upper portion of the packer 15p may be linked to the PBR 15r by an upper ratchet connection 15k and a lower portion of the packer 15p may be linked to the PBR 15r by a lower ratchet connection 15m. Each ratchet connection 15k,m may include a ratchet and a profile of complementing teeth to allow downward movement of the respective packer portion relative to the PBR 15r while preventing upward movement of the respective packer portion relative to the PBR.
The hanger upper portion may initially be fastened to the PBR 15r by a shearable fastener 15y to prevent premature setting of the liner hanger 15h. The packer upper portion may also be linked to the PBR 15r by a releasable slip joint 15w,x. The slip joint 15w,x may allow downward movement of the packer upper portion relative to the PBR 15r until a stroke of the joint is reached at which the joint connects the packer upper portion to the PBR in the downward direction, thereby preventing premature setting of the packer 15p. The slip joint 15w,x may include a sleeve 15w disposed in an annular space formed between the packer upper portion and the PBR 15r and fastened to the packer upper portion by one or more (two shown) shearable fasteners 15x. The space may be longitudinally formed between upper and lower shoulders of the PBR 15r. A bottom of the sleeve 15w may be spaced from the PBR lower shoulder by the stroke length of the connection 15w,x. The slip joint 15w,x is stroked when the sleeve bottom engages the PBR lower shoulder and the joint may be released by a threshold force on the packer upper portion to fracture the shearable fasteners 15x. The slip joint stroke length may correspond to a setting length of the liner hanger 15h, such as being slightly greater than.
The LDA 9d may include the diverter valve 50 (shown only in
The diverter valve 50 may include a housing, a bore valve, and a port valve. The diverter housing may include two or more tubular sections (three shown) connected to each other, such as by threaded couplings. The diverter housing may have threaded couplings formed at each longitudinal end thereof for connection to the drill pipe 9p at an upper end thereof and the junk bonnet 51 at a lower end thereof. The bore valve may be disposed in the housing. The bore valve may include a body and a valve member, such as a flapper, pivotally connected to the body and biased toward a closed position, such as by a torsion spring. The flapper may be oriented to allow downward fluid flow from the drill pipe 9p through the rest of the LDA 9d and prevent reverse upward flow from the LDA to the drill pipe 9p. Closure of the flapper may isolate an upper portion of a bore of the diverter valve from a lower portion thereof. Although not shown, the body may have a fill orifice formed through a wall thereof and bypassing the flapper.
The diverter port valve may include a sleeve and a biasing member, such as a compression spring. The sleeve may include two or more sections connected to each other, such as by threaded couplings and/or fasteners. An upper section of the sleeve may be connected to a lower end of the bore valve body, such as by threaded couplings. Various interfaces between the sleeve and the housing and between the housing sections may be isolated by seals. The sleeve may be disposed in the housing and longitudinally movable relative thereto between an upper position and a lower position. The sleeve may be stopped in the lower position against an upper end of the lower housing section and in the upper position by the bore valve body engaging a lower end of the upper housing section. The mid housing section may have one or more flow ports and one or more equalization ports formed through a wall thereof. One of the sleeve sections may have one or more equalization slots formed therethrough providing fluid communication between a spring chamber formed in an inner surface of the mid housing section and the lower bore portion of the diverter valve 50.
One of the diverter sleeve sections may cover the housing flow ports when the sleeve is in the lower position, thereby closing the housing flow ports and the sleeve section may be clear of the flow ports when the sleeve is in the upper position, thereby opening the flow ports. In operation, surge pressure of the returns 47r generated by deployment of the LDA 9d and liner string 15 into the wellbore may be exerted on a lower face of the closed flapper. The surge pressure may push the flapper upward, thereby also pulling the sleeve upward against the compression spring and opening the housing flow ports. The surging returns 47r may then be diverted through the open flow ports by the closed flapper. Once the liner string 15 has been deployed, dissipation of the surge pressure may allow the spring to return the sleeve to the lower position.
The junk bonnet 51 may be engaged with and close an upper end of the setting sleeve 15v, thereby forming an upper end of a buffer chamber 59. A lower end of the buffer chamber 59 may be formed by a sealed interface between the plug release system 58 and the PBR 15r. The buffer chamber 59 may be filled with a hydraulic fluid (not shown), such as fresh water or refined/synthetic oil. The buffer chamber 59 may prevent infiltration of debris from the wellbore 24 from obstructing operation of the LDA 9d.
Alternatively, the power source may be a capacitor or inductor instead of the battery 67.
Each of an adapter housing section 65a and an upper portion of the mandrel main section 60b may have one or more (two shown) corresponding keyways. The housing adapter section 65a may have a flange formed in a wall thereof adjacent to the respective keyway for receiving a respective complementary key 63a,b. Each flange may have one or more (two shown) threaded sockets formed therein. Each key 63a,b may have a flange portion and a shank portion. The key flange portion may engage the respective flange of the housing adapter section 65a and have sockets corresponding to the threaded sockets thereof. A threaded fastener 64 may be inserted through each flange portion and screwed into the respective threaded socket of the housing adapter section 65a, thereby fastening the keys 63a,b thereto. Each key shank portion may extend through the respective keyway of the housing adapter section 65a and into the respective keyway of the main mandrel section, thereby longitudinally and torsionally connecting the housing 65 and the mandrel 60. The main mandrel section 60b may have one or more (two shown) keyways formed adjacent to a lower end thereof for connection to an upper end of the running tool 53 using keys (
The adapter housing section 65a may also have inner and outer shoulders formed at a lower end thereof. An upper end of a second housing section 65b may be received by the outer shoulder and the second housing section may be connected to the adapter housing section 65a, such as by one or more (two shown) fasteners 71f. An interface formed between the adapter 65a and second 65b housing sections may be isolated by a seal. An upper end of a cylinder 72 may be received by the inner shoulder and an interface formed between the adapter housing section 65a and the cylinder may be isolated by a seal.
A third housing section 65c may have inner and outer shoulders formed at an upper end thereof. A lower end of the second housing section 65b may be received by the outer shoulder and the second housing section may be connected to the third housing section 65c, such as by a fastener 71f. An interface formed between the second and third housing sections 65b,c may be isolated by a seal. A lower end of the cylinder 72 may be received by the inner shoulder and an interface formed between the third housing section 65c and the cylinder may be isolated by a seal. The third housing section 65c may also have inner and outer shoulders formed at a lower end thereof. An upper end of an outer wall of a fourth housing section 65d may be received by the outer shoulder and the fourth housing section may be connected to the adapter housing section 65a, such as by a fastener 71f. An outer interface formed between the third and fourth housing sections 65c,d may be isolated by a seal. An upper end of an inner wall of a fourth housing section 65d may be received by the inner shoulder and an inner interface formed between the third and fourth housing sections 65c,d may be isolated by a seal.
The fourth housing section 65d may have a threaded coupling formed at a lower end thereof and an upper end of a fifth housing section 65e may have a complementary threaded coupling engaged therewith, thereby connecting the fourth and fifth housing sections 65d,e. The fourth housing section 65d may also have a seal shoulder formed adjacent to the coupling thereof and the fifth housing section 65e may have a stinger formed adjacent to the coupling thereof. The stinger and seal shoulder may engage upon screwing the fourth and fifth housing sections 65d,e together and the interface therebetween may be isolated by inner and outer seals. An interface between the fourth housing section 65d and the main mandrel section 60m may be isolated by a seal.
The fifth housing section 65e may have a threaded coupling formed at a lower end thereof and an outer surface of a sixth housing section 65f may have a complementary threaded coupling engaged therewith, thereby connecting the fifth and sixth housing sections 65e,f. An interface between the fifth and sixth housing sections 65e,f and an interface between the sixth housing section 65f and a catch sleeve 51c of the junk bonnet 51 may each be isolated by a seal. The sixth housing section 65f may also carry a slide bearing 71b for facilitating longitudinal movement relative to the catch sleeve 51c.
The hydraulics 70 may include one or more chambers, such as a reservoir chamber 70c, an actuation chamber 70h, and a balance chamber 70b, a reservoir piston 70p, hydraulic fluid 73, and one or more hydraulic passages, such as a reservoir passage 70f, a return passage 70r, and an actuation passage 70a. The hydraulic fluid 73 may be water, refined oil, or synthetic oil. The reservoir chamber 70c may be formed radially between the second housing section 65b and the cylinder 72 and longitudinally between a lower face of the adapter housing section 65a and an upper face of the third housing section 65c. The reservoir piston 76p may be disposed in the reservoir chamber may divide the chamber into an upper portion and a lower portion. The reservoir chamber upper portion may have a gas pocket for accommodating actuation of the setting tool 52. The hydraulic fluid 73 may be disposed in the reservoir chamber lower portion. The reservoir piston 70p may carry inner and outer seals for isolating the hydraulic fluid 73 in the lower portion from the reservoir chamber upper portion.
The reservoir passage 70f may be formed through a wall of the third housing section 65c and may provide fluid communication between the reservoir chamber lower portion and an inlet of the actuator 69. The return passage 70r may be formed through walls of the fourth and fifth housing sections 65d,e and may provide fluid communication between the actuator inlet and the balance chamber 70b. The bypass passage 70p may be formed in a wall of the fourth housing section 65d and may have a shutoff valve for providing selective fluid communication between the return passage 70r and the actuation passage 70a. The actuation passage 70a may be formed in a wall of the fourth housing section 65d and may provide fluid communication between an outlet of the actuator 69 and the actuation chamber 70h.
The actuation chamber 70h may be variable volume and may be formed radially between the main mandrel section 60m and the fifth housing section 65e and longitudinally between a lower face of the fourth housing section 65d and an upper face of the barrel 75. The balance chamber 70b may be variable volume and may be formed radially between the main mandrel section 60m and the fifth housing section 65e and longitudinally between a lower face of the barrel 75 and an upper face of the sixth housing section 65f.
The actuator 69 may include the electric motor 69m, a pump 69p, a control valve, such as spool valve 69v, and a pressure sensor (not shown). The electric motor 69m may include a stator in electrical communication with a motor controller 66m and a head in electromagnetic communication with the stator for being driven thereby. The motor head may be longitudinally or torsionally driven. The pump 69p may have a stator connected to the motor stator and a cylinder connected to the motor head (directly or via lead screw) for being reciprocated thereby. The pump 69p may have the inlet in fluid communication with the reservoir passage 70f and the outlet in fluid communication with the actuation passage 70a. The spool valve 69v may selectively provide fluid communication between the pump piston and the inlet or outlet depending on the stroke. The spool valve 69v may be mechanically, electrically, or hydraulically operated. The pressure sensor may be in fluid communication with the pump outlet and a microcontroller (MCU) of a control circuit 66c may be in electrical communication with the pressure sensor to determine when the liner hanger 15h has been set by detecting a corresponding pressure increase at the outlet of the pump 69p.
The fourth housing section 65d may have electrical conduits formed through a wall thereof for receiving lead wires connecting the actuator 69 to the electronics package 66 and connecting the shutoff valve of the bypass passage 70p to the electronics package. The fourth housing section 65d may also have a cavity formed in the wall thereof for receiving the actuator 69. The actuator 69 may be connected to the housing 65, such as by interference fit or fastening. Lead wires may also extend from the electronics package 66 to the antenna 68 through a gap formed between the housing 65 and the mandrel 60 (shown extending through a wall of the main mandrel section 60m for clarity).
The antenna 68 may be tubular and extend along an inner surface of the main mandrel section 60m. The antenna 68 may include an inner liner, a coil, and a jacket. The antenna liner may be made from a non-magnetic and non-conductive material, such as a polymer or composite, have a bore formed longitudinally therethrough, and have a helical groove formed in an outer surface thereof. The antenna coil may be wound in the helical groove and made from an electrically conductive material, such as copper or alloy thereof. The antenna jacket may be made from the non-magnetic and non-conductive material and may insulate the coil. The antenna lead wires may be connected to ends of the antenna coil. The antenna 68 may be received in a recess formed in an inner surface of the main mandrel section 60m and the main mandrel section may have a thread formed in an inner surface thereof adjacent to the recess. A nut may be screwed into the mandrel thread against the antenna 68, thereby connecting the antenna to the mandrel 60.
The fourth housing section 65d may have one or more (only one shown) pockets formed in the wall thereof. Although shown in the same pocket, the electronics package 66 and battery 67 may be disposed in respective pockets of the fourth housing section 65d. The electronics package 66 may include the control circuit 66c, a transmitter 66t, a receiver 66r, and the motor controller 66m integrated on a printed circuit board 66b. The control circuit 66c may include the MCU, a memory unit (MEM), a clock, and an analog-digital converter. The transmitter 66t may include an amplifier (AMP), a modulator (MOD), and an oscillator (OSC). The receiver 66r may include an amplifier (AMP), a demodulator (MOD), and a filter (FIL). The motor controller 66m may include a power converter for converting a DC power signal supplied by the battery 67 into a suitable power signal for driving the electric motor 69m. The electronics package 66 may be housed in an encapsulation.
Returning to
The actuation piston 75a may have a threaded coupling formed in an outer surface thereof and an upper end of the barrel sleeve 75s may have a complementary threaded coupling engaged therewith, thereby connecting the two barrel members. An interface between the actuation piston 75a and the barrel sleeve 75s and an interface between the actuation piston 75a and the main mandrel section 60m may each be isolated by a seal. The actuation piston 75a may also carry a slide bearing 71b for facilitating longitudinal movement relative to the mandrel 60. An interface between the fifth housing section 65e and the barrel sleeve 75s may be isolated by one or more (two shown) seals. The barrel sleeve 75s may also carry one or more (two shown) slide bearings 71b for facilitating longitudinal movement relative to the housing 65. The balance piston 75b may have a threaded coupling formed in an outer surface thereof and a lower end of the barrel sleeve 75s may have a complementary threaded coupling engaged therewith, thereby connecting the two barrel members. An interface between the balance piston 75b and the barrel sleeve 75s and an interface between the balance piston 75b and the main mandrel section 60m may each be isolated by a seal. The balance piston 75b may also carry a slide bearing 71b for facilitating longitudinal movement relative to the mandrel 60.
The junk bonnet 51 may include an outer ring 51o, an inner ring 51i, and the catch sleeve 51c. Subject to engagement with the balance piston 75b and the sixth housing section 65f, the junk bonnet 51 may be longitudinally movable relative to the mandrel 60, the housing 65, and the barrel 75. The inner ring 51i may have a threaded coupling formed in an inner surface thereof and a lower end of the catch sleeve 51c may have a complementary threaded coupling engaged therewith, thereby connecting the two junk bonnet members. The inner ring 51i may have a threaded coupling formed in an outer surface thereof and the outer ring 510 may have a complementary threaded coupling formed in an inner surface thereof and engaged therewith, thereby connecting the two junk bonnet members.
The catch sleeve 51c may have an upper enlarged portion, a lower reduced portion, and a shoulder formed between the two portions. The catch sleeve lower portion may slide along an interface formed between the sixth housing section 65f and the main mandrel section 60m and the shoulder may be sized to engage an upper face of the sixth housing section. The catch sleeve enlarged upper portion may engage a lower face of the balance piston 75b for being extended in response to downward movement of the barrel 75. The outer ring 510 may have a shoulder formed in an outer surface thereof for receiving the upper end of the setting sleeve 15v.
The latch 62 may include a body 62y, a plurality of fasteners, such as dogs 62a,b, a cam 62c, and a retainer 62u,t. The latch 62 may be disposed against a shoulder formed in an outer surface of the main mandrel section 60m and fastened to the main mandrel section by a snap ring. The latch 62 may carry one or more (two shown) radial bearings for facilitating rotation of the latch 62 relative to the mandrel 60. The body 62y may have a threaded coupling formed in an outer surface thereof and an upper member 62u of the retainer 62u,t may have a complementary threaded coupling formed in an inner surface thereof and engaged therewith, thereby connecting the retainer to the body. A lower member 62t of the retainer 62u,t may be fastened to the body 62y.
A pocket may be formed between the latch body 62y and the retainer 62u,t. The dogs 62a,b may be disposed in the pocket and spaced around the pocket. Each dog 62a,b may be movable relative to the body 62y and retainer 62u,t between a retracted position (shown) and an extended position (
Returning to
The running tool controller may include a housing, an electronics package similar to the electronics package 66, a power source, such as a battery, an antenna similar to the antenna 68, an actuator similar to the actuator 69, and hydraulics. The housing may have a bore formed therethrough and include two or more tubular sections. A lower housing section may be connected to the inner body section, such as by a threaded fastener. The lower housing section may receive a lower end of the outer body section, thereby connecting the outer body section to the inner body section. The nut may also receive an upper end of an upper housing section and a second housing section may receive a lower end of the upper housing section. The second housing section may also receive an upper end of a third housing section. The lower housing section may receive a lower end of the third housing section, thereby connecting the housing to the inner body section.
The running tool hydraulics may include a reservoir chamber, a balance piston, hydraulic fluid similar to hydraulic fluid 73, and a hydraulic passage. The balance piston may be disposed in the reservoir chamber formed between the upper housing section and the inner body section and may divide the chamber into an upper portion and a lower portion. A port may be formed through a wall of the nut and may provide fluid communication between the reservoir chamber upper portion and the buffer chamber 59. The hydraulic fluid may be disposed in the reservoir chamber lower portion. The balance piston may carry inner and outer seals for isolating the hydraulic fluid from the reservoir chamber upper portion.
The running tool second housing section may have an electrical conduit formed through a wall thereof for receiving lead wires connecting the antenna to the electronics package and connecting the actuator to the electronics package. The second housing section may also have a cavity formed in an upper end thereof for receiving the actuator. The actuator may be connected to the housing, such as by interference fit or fastening. The hydraulic passage may provide fluid communication between the actuator and the lock. An upper portion of the hydraulic passage may be formed through a wall of the third housing section and a lower portion of the hydraulic passage may be formed through a wall of the lower housing section. The running tool third housing section may have one or more (only one shown) pockets formed in an outer surface thereof. Although shown in the same pocket, the electronics package and battery may be disposed in respective pockets of the third housing section. The actuator pump may have an inlet in fluid communication with the lower reservoir chamber portion and an outlet in fluid communication with the hydraulic passage.
The running tool latch may longitudinally and torsionally connect the PBR 15r 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 thrust cap may have an upper shoulder formed in an outer surface thereof and adjacent to an upper end thereof, an enlarged mid portion, a lower shoulder formed in an outer surface thereof, a torsional fastener, such as a key, formed in an outer surface thereof, a lead screw formed in an inner surface thereof, and a spring shoulder formed in an inner surface thereof. The key may mate with a torsional profile, such as a castellation, formed in an upper end of the PBR 15r and the floating nut may be screwed into a thread 15t of the PBR 15r. The lock may be disposed on the inner body section to prevent premature release of the latch from the PBR 15r. The clutch may selectively torsionally connect the thrust cap to the running tool body.
The running tool lock may include a piston, a plug, a fastener, such as a dog, and a sleeve. The plug may be connected to an outer surface of the inner body section, such as by threaded couplings. The plug may carry an inner seal and an outer seal. The inner seal may isolate an interface formed between the plug and the body and the outer seal may isolate an interface formed between the plug and the piston. The piston may be longitudinally movable relative to the body between an upper position (
The running tool lock sleeve may have an upper portion disposed along an outer surface of the inner body section and an enlarged lower portion. The lock sleeve may have an opening formed through a wall thereof to receive the dog therein. The dog may be radially movable between the retracted position (shown) and an extended position (
The running tool clutch may include a biasing member, such as upper compression spring, a thrust bearing, a gear, a lead nut, and a torsional coupling, such as key. The thrust bearing may be disposed in the lock sleeve lower portion and against a shoulder formed in an outer surface of the inner body section. A spring washer may be disposed adjacent to a bottom of the thrust bearing and may receive an upper end of the clutch spring, thereby biasing the thrust bearing against the running tool body shoulder. The inner body section may have a torsional profile, such a keyway formed in an outer surface thereof adjacent to a lower end thereof. The key may be disposed the keyway. The key may be kept in the keyway by entrapment between a shoulder formed in an outer surface of the lower body section and a shoulder formed in an upper end of the lower body section.
The running tool gear may be connected to the thrust cap, such as by a threaded fastener, and have teeth formed in an inner surface thereof. Subject to the lock, the gear and thrust cap may be movable between an upper position (
The running tool spring shoulder of the thrust cap may receive an upper end of the latch spring. A lower end of the latch spring may be received by a shoulder formed in an upper end of the float nut. A thrust ring may be disposed between the float nut and an upper end of the lower body section. The float nut may be urged against the thrust ring by the latch spring. The float nut may have a thread formed in an outer surface thereof. The thread may be opposite-handed, such as left handed, relative to the rest of the threads of the workstring 9. The float nut may be torsionally connected to the body by having a keyway formed along an inner surface thereof and receiving the key, thereby providing upward freedom of the float nut relative to the body while maintaining torsional connection thereto. Threads of the lead nut and lead screw may have a finer pitch, opposite hand, and greater number than threads of the float nut and packer dogs to facilitate lesser (and opposite) longitudinal displacement per rotation of the lead nut relative to the float nut.
The plug release system 58 may include a launcher and the cementing plug, such as a wiper plug. Each of the launcher and wiper plug may be a tubular member having a bore formed therethrough. The launcher may include a housing, an electronics package similar to the package 66, a power source, such as a battery, an antenna similar to the antenna 68, a mandrel, and a latch. The housing may include two or more tubular sections connected to each other, such as by threaded couplings. The housing may have a coupling, such as a threaded coupling, formed at an upper end thereof for connection to the stinger 54. The mid housing section may have an enlarged inner diameter to form an electronics chamber for receiving the antenna and the mandrel.
The plug release system lower housing section may have a groove formed in an upper end and inner surface thereof and the antenna flange may be disposed in the groove and trapped therein by a lower end of the mandrel, thereby connecting the antenna to the housing. The mandrel may be a tubular member having one or more (only one shown) pockets formed in an outer surface thereof. The mandrel may be connected to the housing by entrapment between a lower end of the upper housing section and an upper end of the lower housing section. The mandrel, housing, and/or latch may have electrical conduits formed in a wall thereof for receiving wires connecting the antenna to the electronics package, connecting the battery to the electronics package, and connecting the latch to the electronics package. The actuator controller may include a power converter for converting a DC power signal supplied by the battery into a suitable power signal for driving an actuator of the latch.
The plug release system latch may include a retainer sleeve, a receiver chamber, the actuator, a lock sleeve, and a fastener, such as a collet. An upper end of the retainer sleeve may be connected to a lower end of the lower housing section, such as by threaded couplings. The receiver chamber may be formed in an inner surface of the lower housing section and occupy a mid and lower portion thereof. The actuator may be linear and include a solenoid, a guide, and a hub. Each of the solenoid and guide may include a shaft and a cylinder. The hub may have a threaded socket formed therethrough for each actuator shaft. An upper end of each actuator shaft may be threaded and received in the respective socket, thereby connecting the solenoid and guide to the hub.
The plug release system lock sleeve may have a threaded coupling formed at an upper end thereof for receiving a threaded coupling formed in an outer surface of the hub, thereby connecting the lock sleeve and the hub. The lock sleeve may be longitudinally movable by the actuator and relative to the housing between a lower position (shown) and an upper position (
The plug release system collet may be radially movable between an engaged position (shown) and a disengaged position (
The plug release system wiper plug may include a body, a mandrel, a stinger, a wiper seal, an anchor. The body may have the groove formed in an inner surface thereof adjacent to an upper end thereof, the stop shoulder formed in the inner surface thereof adjacent to the groove, one or more threaded sockets formed through a wall thereof, and a threaded coupling formed at a lower end thereof. Each of the body, mandrel, stinger, anchor, and seat may be made from a drillable material, such as cast iron, nonferrous metal or alloy, fiber reinforced composite, or engineering polymer. The mandrel may be disposed in a bore of the body, have a groove formed in an outer surface thereof, a landing profile formed in the inner surface thereof adjacent to a lower end thereof, and an upper seal groove and a lower seal groove, each formed in an outer surface thereof and each carrying a seal. The landing profile may have a landing shoulder, a latch profile, and a seal bore for receiving the dart 43 (
The plug release system stinger may have an upper threaded coupling formed in an inner surface thereof engaged with the body threaded coupling, thereby connecting the stinger and the body. The body may have a reduced outer diameter mid and lower portion to form recess for receiving the wiper seal. The wiper seal may be connected to the body by entrapment between a shoulder formed in an outer surface of the body and an upper end of the stinger. The wiper seal may include a fin stack, a backup stack, and a lower end adapter. Each stack may include one or more (three shown) units, each unit having a backup ring and a seal ring molded onto the respective backup ring. Each seal ring may be directional and made from an elastomer or elastomeric copolymer. An outer diameter of each seal ring may correspond to an inner diameter of the liner joints 15j, such as being slightly greater than. Each seal ring may oriented to sealingly engage the liner joints 15j in response to pressure above the seal ring being greater than pressure below the seal ring. Each backup ring and the adapter may be made from one of the drillable materials. The stinger upper end may have a groove for mating with a lower lip of the end adapter.
The plug release system anchor may include a mandrel, a longitudinal coupling, a torsional coupling, and an external seal. The stinger may have a lower threaded coupling formed in the inner surface thereof and an outer groove formed in a lower end thereof. The anchor mandrel may have a threaded coupling formed in an outer surface thereof engaged with the stinger threaded coupling, thereby connecting the stinger and the anchor. The anchor mandrel may have a groove formed in an inner surface thereof for carrying a seal, thereby isolating an interface formed between the anchor mandrel and the stinger. The external seal may be disposed in the stinger outer groove. A retainer may have an outer portion extending into the stinger outer groove and an inner portion trapped between the stinger lower end and an upper end of the torsional coupling, thereby trapping the external seal in the stinger outer groove. The torsional coupling may be a nut having a threaded inner surface engaged with the anchor mandrel threaded coupling and having one or more helical vanes formed on an outer surface thereof. The anchor mandrel may have a conical taper formed in an outer surface thereof and the longitudinal coupling may be disposed between the torsion nut and the conical taper. The longitudinal coupling may be a split ring having teeth formed along an outer surface thereof and a conical taper formed in an inner surface thereof complementary to the mandrel taper.
Referring specifically to
Referring specifically to
Referring specifically to
Referring specifically to
Referring specifically to
Referring specifically to
Referring specifically to
Referring specifically to
Referring specifically to
Referring specifically to
Referring specifically to
Referring specifically to
The override piston 81 may be longitudinally movable relative to the housing 65 and the mandrel 62 between an upper position (
Should the electronics package 66 and/or the actuator 69 fail to set the liner hanger 15s, an override plug, such as ball 87, may be pumped to the setting tool 52 and received by the seat 84. The seat 84 may be disposed in the main mandrel section 60m between the upper 82u and lower 82b ports. The seat 84 may be a collet having an upper base portion and fingers extending from the base portion to a lower end thereof. A lug may be formed at a lower end of each finger. Collectively, the lugs may protrude into the mandrel bore for receiving the ball 87. The fingers may operate as cantilever springs movable between a retracted position (shown) and an extended position (not shown). The fingers may be naturally biased toward the extended position.
The seat base portion may be releasably connected to the main mandrel section 60m, such as by a shearable fastener 85. A threshold pressure necessary to fracture the fastener 85 may correspond to the threshold pressure required to set the liner hanger 15h, such as being slightly greater than. Once the seat 84 has been released from the mandrel 60, the seat may slide downward relative to the mandrel until the collet fingers reach the release 86. The release 86 may be a groove formed in an inner surface of the main mandrel section 60m. Upon reaching the release 86, the collet fingers may snap to the extended position, thereby releasing the ball 87.
The ball 87 may be pumped to the seat 84 using the conditioner 100. Once the ball 87 seats, continued pumping of the conditioner 100 into the LDA bore may increase pressure 88 in the chamber upper portion 83h relative to the lower portion 83w and push the override piston 81 into engagement with the balance piston 75b. Pumping may continue until the shearable fastener 15y fractures and the liner hanger 15h is set against the casing 25. The ball 87 may then be released and operation of the LDA 9d may continue.
Alternatively, the setting tool 52 may be used to drive an expander through an expandable liner hanger. Alternatively, the setting tool 52 may be used to hang a casing string from a subsea wellhead. Alternatively, the liner string 15 may be hung from another liner string instead of the casing string 25.
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.
| Number | Name | Date | Kind |
|---|---|---|---|
| 2693859 | Wright | Nov 1954 | A |
| 4405017 | Allen et al. | Sep 1983 | A |
| 4583593 | Zunkel et al. | Apr 1986 | A |
| 4893678 | Stokley et al. | Jan 1990 | A |
| 5086843 | Mims et al. | Feb 1992 | A |
| 5086844 | Mims et al. | Feb 1992 | A |
| 5146992 | Baugh | Sep 1992 | A |
| 5170847 | Mims et al. | Dec 1992 | A |
| 5174375 | Mims et al. | Dec 1992 | A |
| 5360069 | Schmuck et al. | Nov 1994 | A |
| 5435390 | Baugh et al. | Jul 1995 | A |
| 5553667 | Budde et al. | Sep 1996 | A |
| 5560426 | Trahan et al. | Oct 1996 | A |
| 5590713 | Baugh et al. | Jan 1997 | A |
| 5787979 | Giroux et al. | Aug 1998 | A |
| 5813457 | Giroux et al. | Sep 1998 | A |
| 5833002 | Holcombe | Nov 1998 | A |
| 5856790 | Baugh et al. | Jan 1999 | A |
| 5954133 | Ross | Sep 1999 | A |
| 6009944 | Gudmestad | Jan 2000 | A |
| 6053244 | Dybevik et al. | Apr 2000 | A |
| 6056053 | Giroux et al. | May 2000 | A |
| 6065536 | Gudmestad et al. | May 2000 | A |
| 6241018 | Eriksen | Jun 2001 | B1 |
| 6241023 | Krauss et al. | Jun 2001 | B1 |
| 6244350 | Gudmestad et al. | Jun 2001 | B1 |
| 6311771 | Gudmestad et al. | Nov 2001 | B1 |
| 6318472 | Rogers et al. | Nov 2001 | B1 |
| 6419015 | Budde et al. | Jul 2002 | B1 |
| 6527057 | Fraser, III et al. | Mar 2003 | B2 |
| 6561270 | Budde | May 2003 | B1 |
| 6597175 | Brisco | Jul 2003 | B1 |
| 6634428 | Krauss et al. | Oct 2003 | B2 |
| 6789619 | Carlson et al. | Sep 2004 | B2 |
| 6799638 | Butterfield, Jr. | Oct 2004 | B2 |
| 6848511 | Jones et al. | Feb 2005 | B1 |
| 6866100 | Gudmestad et al. | Mar 2005 | B2 |
| 6966368 | Farquhar | Nov 2005 | B2 |
| 7063148 | Jabusch | Jun 2006 | B2 |
| 7066256 | Dillenbeck et al. | Jun 2006 | B2 |
| 7114573 | Hirth et al. | Oct 2006 | B2 |
| 7128154 | Giroux et al. | Oct 2006 | B2 |
| 7165622 | Hirth et al. | Jan 2007 | B2 |
| 7182135 | Szarka | Feb 2007 | B2 |
| 7219730 | Tilton et al. | May 2007 | B2 |
| 7252152 | LoGiudice et al. | Aug 2007 | B2 |
| 7426964 | Lynde et al. | Sep 2008 | B2 |
| 7537060 | Fay et al. | May 2009 | B2 |
| 7581595 | Fay et al. | Sep 2009 | B2 |
| 7584792 | Szarka | Sep 2009 | B2 |
| 7686092 | Szarka | Mar 2010 | B2 |
| 7766088 | Saucier et al. | Aug 2010 | B2 |
| 7845400 | Smith, Jr. et al. | Dec 2010 | B2 |
| 8276665 | Webb et al. | Oct 2012 | B2 |
| 8286717 | Giroux et al. | Oct 2012 | B2 |
| 8347964 | Fisher et al. | Jan 2013 | B2 |
| 8479808 | Gouthaman | Jul 2013 | B2 |
| 8651174 | Barbee et al. | Feb 2014 | B2 |
| 8668003 | Osmundsen et al. | Mar 2014 | B2 |
| 8881824 | Stautzenberger | Nov 2014 | B2 |
| 8997850 | Barbee et al. | Apr 2015 | B2 |
| 9004179 | Chauffe | Apr 2015 | B2 |
| 9068413 | Doane | Jun 2015 | B2 |
| 9068414 | Doane | Jun 2015 | B2 |
| 9080404 | Kalb et al. | Jul 2015 | B2 |
| 9121232 | Abraham et al. | Sep 2015 | B2 |
| 9212531 | Robichaux et al. | Dec 2015 | B2 |
| 20030230405 | Allamon et al. | Dec 2003 | A1 |
| 20050006106 | Hirth et al. | Jan 2005 | A1 |
| 20070272413 | Rytlewski et al. | Nov 2007 | A1 |
| 20090266544 | Redlinger et al. | Oct 2009 | A1 |
| 20090272544 | Giroux et al. | Nov 2009 | A1 |
| 20100051264 | Willauer | Mar 2010 | A1 |
| 20100181079 | Johnson et al. | Jul 2010 | A1 |
| 20110000663 | Brandsdal | Jan 2011 | A1 |
| 20120061100 | Bræker | Mar 2012 | A1 |
| 20120067594 | Noske et al. | Mar 2012 | A1 |
| 20130299196 | Kolle | Nov 2013 | A1 |
| 20130327532 | Ring et al. | Dec 2013 | A1 |
| 20140008083 | Ring et al. | Jan 2014 | A1 |
| 20140138101 | Arabsky et al. | May 2014 | A1 |
| 20140196912 | Turley et al. | Jul 2014 | A1 |
| 20140262234 | Walton et al. | Sep 2014 | A1 |
| 20150136394 | Turley et al. | May 2015 | A1 |
| 20150136395 | Turley et al. | May 2015 | A1 |
| 20150136396 | Turley et al. | May 2015 | A1 |
| Number | Date | Country |
|---|---|---|
| 2350141 | Nov 2000 | GB |
| 2012065126 | May 2012 | WO |
| Entry |
|---|
| EPO Extended European Search Report dated Aug. 21, 2015 for European Patent Application No. 14191711.2. |
| Australian Patent Examination Report dated Aug. 28, 2015, for Australian Application No. 2014259561. |
| Weatherford—WellMaster All-in-One Deepwater System brochure, date unknown, 1 page. |
| Weatherford—Liner Hanger Selection brochure, May 2006, 24 pages. |
| Weatherford—HNG Hydraulic-Release Running Tool brochure, 2006, 1 page. |
| Weatherford—Weatherford's Linear Systems—Hang Tough brochure, 2008-2012, 16 pages. |
| Weatherford—SwageSet Series Liner-Top Packer brochure, 2011-2013, 6 pages. |
| EPO Partial European Search Report dated Apr. 8, 2015, for European Application No. 14191711.2. |
| Canadian Patent Examination Report dated Oct. 27, 2015 for Canadian Application No. 2, 869, 261. |
| Number | Date | Country | |
|---|---|---|---|
| 20150136393 A1 | May 2015 | US |
