Plug release system, liner installation set and method for suspending an inner tubular column from a

专利摘要:
BUFFER RELEASE SYSTEM, COATING INSTALLATION ASSEMBLY AND METHOD FOR SUSPENDING AN INNER TUBULAR COLUMN FROM AN EXTERNAL TUBULAR COLUMN. The present invention relates to a plug release system for cementing a tubular column in a wellbore and includes a shoulder plug, a tubular housing, a locking member for loosely connecting the shoulder plug to the housing. the locking member includes: a fastener engaged with one of the shoulder plugs and housing; a lock movable between a locked position and an unlocked position, the lock holding the catch engaged in the locked position; and an actuator connected to the lock and operable to at least move the lock from the locked position to the unlocked position. the plug release system additionally includes an electronic assembly disposed in the housing and in communication with the actuator to operate the actuator in response to receipt of a command signal.
公开号:BR102014028648B1
申请号:R102014028648-9
申请日:2014-11-17
公开日:2021-08-31
发明作者:Rocky A. Turley；Robin L. Campbell；Richard Lee Giroux
申请人:Weatherford Technology Holdings, Llc；
IPC主号:

专利说明:

Background of the Invention Field of Invention
[0001] The present invention relates, in general, to a plug release system for cementation, operated by telemetry. Description of the Related Technique
[0002] A wellbore is formed to access formations that contain hydrocarbons, eg crude oil and/or natural gas, by means of drilling. Drilling is carried out by using a drill bit which is mounted to the end of a tubular string, such as a drill string. To drill inside the wellbore to a predetermined depth, the drill string is typically rotated by top drive or rotary table on a platform or surface equipment and/or by an in-well motor mounted near the lower end of the drill string. After drilling to a predetermined depth, the drill string and drill bit are removed and a casing section is installed inside the wellbore. In this way an annular crown is formed between the casing column and the formation. The casing string is cemented into the wellbore by cement circulation within the annular crown defined between the outer casing wall and the wellbore. The combination of cement and casing strengthens the wellbore and facilitates the isolation of certain areas of the formation behind the casing for hydrocarbon production.
[0003] It is common to use more than one casing or housing column in a well hole. In this sense, the well is drilled to a first designated depth using a drill end in a drill string. The drill string is removed. A first casing string is then installed inside the wellbore and fitted into the perforated portion of the wellbore and cement is circulated inside the annular crown behind the casing string. Thereafter, the well is drilled to a second designated depth, and a second casing or housing column is installed within the drilled portion of the wellbore. If the second column is a casing column, the casing is fitted to a depth such that the upper portion of the second casing column overlies the lower portion of the first casing column. The casing column can then be hung from the existing housing. The second casing or housing column is then cemented. This process is typically repeated with additional casing or housing columns until the well has been drilled to its full depth. In this way, wells are typically formed with two or more casing columns with an ever-decreasing diameter.
[0004] During the cementing operation of a casing or submerged housing column, casing is installed in the well hole at the end of an operating column. The operating column includes a contact plug at a lower end of the operating column. The process of releasing the contact plug at the bottom of the well is typically carried out by pumping a dart through the operating column. The dart is pumped in a downward direction by injecting a cement slurry or other desired circulating fluid under pressure into the wellbore. The fluid forces the dart in a downward direction into the well hole until it contacts a seat in the contact plug. The dart anchors tightly against the contact plug. Hydraulic pressure from the injected fluid finally causes the opening of a releasable connection between the contact plug and the operating column, thus allowing the dart and contact plug to be pumped in a downward direction into the well as a Simple and unique cap. This consolidated contact plug separates the fluid above the plug from the fluid below the plug.
[0005] A variety of mechanisms have been employed to retain and subsequently release rebound buffers. Many of these mechanisms use a sliding sleeve that is held in place by a shear device. When the dart docks in the sliding sleeve, the shear device shears and the sleeve moves downward allowing the plug to be released. Certain disadvantages occur with the use of these release mechanisms. For example, during well completion operations, the release mechanism is subjected to various stresses which can cause premature release of the contact plug. In some situations the sliding sleeve is subjected to an impact load by a ball or other device as it passes through the inside of the plug. In other situations, a pressure wave can impact the release mechanism. In either of these situations, it is possible for the sliding sleeve to shear and thereby inadvertently or prematurely release the contact plug. Invention Summary
[0006] The present invention generally refers to a plug release system for cementation operated by telemetry. In one embodiment, a plug release system for cementing a tubular column in a wellbore includes: a contact plug; a tubular housing; a hook for loosely connecting the contact plug to the housing. The hitch includes: a fastener engaged with one of the shoulder plugs and housing; a lock movable between a locked position and an unlocked position, the lock holding the catch engaged in the locked position; and an actuator connected to the lock and operable to at least move the lock from the locked position to the unlocked position. The plug release system additionally includes an electronic assembly disposed in the housing and in communication with the actuator to operate the actuator in response to receipt of a command signal.
[0007] In another embodiment, a method for suspending a tubular column from an outer tubular column cemented in a wellbore includes: traversing the inner tubular column and an installation assembly in a wellbore using an installation column; pumping cement slurry into the installation column; and directing the cement slurry through the installation column and the installation set while sending a command signal to a plug release system of the installation set, in which the plug release system releases a contact plug at response to a command signal. Brief Description of Drawings
[0008] In order to enable the above mentioned features of the present invention to be better understood in its details, a more particular description of the invention briefly summarized above will be presented here with reference to its embodiments, some of which are illustrated in the attached drawings. However, it is to be noted that the accompanying drawings illustrate only typical embodiments of the present invention and should therefore not be considered as limiting its scope, as the invention may admit any other equally efficient embodiments.
[0009] Figures 1A-1C illustrate a drilling system in a casing installation mode according to an embodiment of the present invention. Figure 1D illustrates a radio frequency identification (RFID) tag for the drilling system. Figure 1E illustrates an alternative radio frequency identification (RFID) tag.
[0010] Figures 2A-2D illustrate a liner deployment assembly (LDA) assembly for the drilling system.
[0011] Figures 3A-3C illustrate a liner installation assembly (LDA) adjustment tool.
[0012] Figures 3A and 3B illustrate a liner installation assembly (LDA) plug release system.
[0013] Figures 4A-4F illustrate the operation of the tampon release system.
[0014] Figure 5 illustrates an alternative perforation system, according to another embodiment of this invention.
[0015] Figures 6A-6C illustrate an alternative drilling system plug release system.
[0016] Figures 7A-7D illustrate the operation of an upper portion of the alternate tampon release system.
[0017] Figures 8A-8D illustrate the operation of a lower portion of the alternate plug release system. Detailed Description of Preferred Achievement
[0018] Figures 1A-1C illustrate a drilling system 1 in a casing installation mode according to an embodiment of the present invention. Drilling system 1 may include a mobile offshore drilling unit (MODU) 1m, such as a semi-submersible drilling rig unit 1r, a fluid handling system 1h, a fluid transport system 1t, a pressure control assembly (Pressure Control Assembly = PCA) 1p and an operating column 9.
[0019] The 1m mobile offshore drilling unit (MODU) can carry the drilling rig 1r and the fluid handling system 1h on board and can include an opening in its hull through which drilling operations are conducted. The 1m semi-submersible marine mobile drilling unit (MODU) may include a lower barge hull which floats below a surface (also known as a waterline) 2s from the sea 2 and is therefore less subject to the action of waves on the surface. Stabilizing columns (only one shown) can be mounted on the lower hull of the barge to support an upper hull above the waterline. The upper hull may have one or more decks to support the 1r drilling rig and the 1h fluid handling system. The 1m Mobile Offshore Drilling Unit (MODU) may additionally have a Dynamic Positioning System (DPS) (not shown) or may be anchored to hold the operating opening in position over a submerged wellhead 10.
[0020] Alternatively, the drilling unit Alternatively, a fixed marine drilling unit or a non-mobile marine drilling unit can be used instead of the mobile marine drilling unit (MODU). Alternatively, the wellbore can be submerged having a wellhead located adjacent to the waterline and the drilling rig can be located on a platform adjacent to the wellhead. Alternatively, the wellbore can be underground and the drilling rig located on a ground base.
[0021] The drilling equipment 1r may include an oil well derrick 3, a floor 4, a top drive 5, a cementing head 7 and a winch. The top drive motor 5 can include a motor 8 to rotate the operating column 9. The top drive motor can be either electric or hydraulic. A frame of the upper drive motor 5 can be connected to a rail (not shown) of the oil well derrick 3 to prevent rotation thereof during rotation of the operating column 9 and to allow vertical movement of the upper drive motor with an 11t crane displacement block. The upper drive motor frame 5 can be suspended from the oil well tower 3 by means of the displacement block 11t. The hollow shaft can be torsional operated via the top drive motor and supported from the frame by bearings. Additionally, the top drive may have an inlet connected to the frame and in fluid communication with the hollow shaft. The displacement block 11t can be supported by a string column 11r connected at its upper end to a crown block 11c. The string string 11r can be passed through the pulleys of the blocks 11c, and extend to traction operators 12 for their retrieval, thereby raising or lowering the displacement block 11t in relation to the oil well tower 3. In addition to the equipment rig 1r may include a drill string compensator (not shown) to offset the displacement of the mobile offshore drilling unit (MODU) 1m. The drill string compensator can be arranged between the displacement block 11t and the top drive 5 (also known as a hook mount) or between the crown block 11c and the oil well derrick (also known as the top mount).
[0022] Alternatively, a Kelly and rotary table can be used instead of the top drive.
[0023] In installation mode, an upper end of the operating column 9 can be connected to the hollow shaft of the upper drive, such as by means of threaded couplings. The operating column 9 may include a casing installation assembly (LDA) 9d and an installation column such as drill pipe joints 9p connected together, such as by means of threaded couplings. A top end of liner installation assembly (LDA) 9d can be connected to a bottom end of drill pipe 9p, such as by means of threaded couplings. The casing installation assembly (LDA) 9d can also be connected to a casing column 15. The casing column 15 can include a 15v adjustment sleeve, a polished bore receptacle (Polished Bore Receptacle = PBR) 15r, a packer 15p, a casing suspension element 15h, casing joints 15j, a mooring collar 15c, and a spreader shoe 15s. The polished well receptacle (PBR) 15r, casing joints 15j, mooring collar 15c and reamer shoe 15s can be rotated 8 by means of top drive motor 5 through operating column 9.
[0024] Alternatively, drilling fluid can be injected into casing string 15 during installation thereof. Alternatively, drilling fluid can be injected into casing string 15 and casing string can include a drill bit end (not shown) in place of reamer shoe 15s and casing string can be drilled into bottom formation 27b of this way extending the well hole 24 while installing the casing string.
[0025] After the casing installation has been completed, the operating column 9 can be disconnected from the upper drive motor 5 and the cementing head 7 can be inserted and connected between them. The cementing head 7 may include an isolation valve 6, an actuator rotatable support 7h, a cementing rotatable support 7c and a plug launcher, such as a dart launcher 7d. Isolation valve 6 can be connected to a hollow shaft of the upper drive motor 5 and to an upper end of the rotary support of the actuator 7h, such as by means of threaded couplings. An upper end of the operating column 9 can be connected to a lower end of the cementing head 7, such as by means of threaded couplings.
[0026] The rotary cementation support 7c may include a housing torsionally connected to the oil well tower 3, such as by means of bars, string of columns or a support (not shown). The torsional connection can accommodate longitudinal movement of the rotating support 7c relative to the oil well tower 3. The rotating cementing support 7c may additionally include a mandrel and bearings to support the housing from the mandrel while accommodating the 8 rotation of the chuck. An upper end of the mandrel can be connected to a lower end of the actuator rotary bracket, such as through threaded couplings. The rotating grouting bracket 7c may additionally 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 to isolate communication from the inlet port. The cement mandrel port can provide fluid communication between a cement head bore 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 housing straddling the inlet port interface. Actuator rotary bracket 7h may be similar to cement rotary bracket 7c except that the housing may have two inlets in fluid communication with respective passages formed through the mandrel. The mandrel passages can extend to respective mandrel outlets for connection to the respective hydraulic conduits (only one is shown) for operation of the respective 7d launcher hydraulic actuators. Actuator rotary bracket inputs may be in fluid communication with a hydraulic power unit (Hydraulic Power Unit = HPU) (not shown).
[0027] Alternatively, the seal assembly may include rotating seals such as mechanical seals.
[0028] The dart launcher 7d may include a body, a derailleur, a canister, a joint and an actuator. The body may be tubular and may have a hole through it. To facilitate assembly, the body can include two or more connected sections joined together such as by means of threaded couplings. An upper end of the body can be connected to a lower end of the actuator rotary bracket, such as by means of threaded couplings, and a lower end of the body can be connected to the operating column 9. Additionally, the body may have a shoulder of mooring formed on an inner surface of the same. The canister and the diverter can each be placed in the body orifice. The derailleur can be connected to the body, such as through threaded couplings. The vessel can be longitudinally movable in relation to the body. The vessel may be tubular and may have ribs formed along and around an outer surface of the vessel. Bypass passages can be formed between the ribs. Additionally, the vessel may have a mooring shoulder formed at a lower end of the vessel corresponding to the body's mooring shoulder. The diverter may be operable to deflect fluid received from a cement line 14 away from the vessel orifice and towards the diverter passages. A release plug, such as a dart 43, can be disposed in the hole in the canister.
[0029] The locking member of the launcher may include a body, a plunger and an axle. The locking member body can be connected to a fin formed on the outer surface of the launcher body such as by means of threaded couplings. The plunger may be longitudinally movable with respect to the locking member body and radially movable with respect to the launcher body between a captured/triggered position and a released position. The plunger can be moved between positions through interaction, such as by a screw jack, with the shaft. The shaft can be longitudinally connected to and rotatable with respect to the locking member body. The actuator may be a hydraulic motor operated to rotate the shaft relative to the locking member body.
[0030] The ball launcher 7b may include a body, a piston, an actuator and an adjustment cap, such as a ball 43b, loaded therein. The ball launcher body may be connected to another fin formed on an outer surface of the dart launcher body, such as through threaded couplings. Ball 43b can be disposed on the plunger for selective release and for pumping downhole through drill pipe 9p to casing installation assembly (LDA) 9d. The plunger can be movable relative to the respective body of the dart launcher between a captured position and a release position. The piston can be movable between positions via the actuator. The actuator can be hydraulic, such as a piston and cylinder assembly.
[0031] Alternatively, the actuator tie-down ring and the launcher actuator can be pneumatic or electrical. Alternatively the launcher actuator can be linear such as a piston and cylinders.
[0032] In operation, when it is desired to launch one of the plugs 43b,d, the hydraulic power unit (HPU) can be operated to supply hydraulic fluid to the launcher actuator through the rotary actuator support 7h. The launcher actuator can then move the plunger to the released position (not shown). If the javelin thrower is selected then the canister and javelin 43 can then move in a downward direction relative to the housing until the mooring shoulders are engaged. Engaging the mooring shoulders can close the canister bypass passages, thereby forcing fluid to flow into the canister orifice. The fluid can then drive dart 43 from the canister orifice to a lower housing canister and in one direction through operating column 9.
[0033] The fluid transport system 1t may include an upper marine lift assembly (UMRP) 16u, a marine lift 17, a booster line 18b and an obstruction line 18c. The elevator 17 can extend from the pressure control assembly (PCA) 1p to the mobile marine drilling unit (MODU) 1m and can connect the mobile marine drilling unit (MODU) through the upper marine elevator assembly (UMRP ) 16u. The upper marine lift assembly (UMRP) 16u may include a diverter 19, a flexible joint 20, a slip joint (also known as telescopic) 21, and a turnbuckle 22. The slip joint 21 can include an outer barrel connected to an upper end of the elevator 17, such as by means of a flange connection. The outer barrel can also be connected to the turnbuckle 22, such as by means of a turnbuckle ring.
[0034] The flexible joint 20 can also connect the derailleur 21, such as by means of a flange connection. The derailleur 21 can also be connected to the ground of the apparatus 4, such as by means of a clamp. The slip joint 21 may be operable to extend and to retract in response to displacement of the marine mobile drilling unit (MODU) 1m relative to elevator 17 while tensioner 22 may wind the column rope in response to displacement in this way. supporting elevator 17 from mobile offshore drilling unit (MODU) 1, while accommodating displacement. Elevator 17 may have one or more float modules (not shown) disposed therealong to reduce the load on tensioner 22.
[0035] The pressure control assembly (PCA) 1p can be connected to the wellhead 10 located adjacent to a 2f sea floor. A conductive column 23 can be driven to penetrate the soil 2f of the sea. The conductive column 23 may include a housing and conductive pipe joints connected together, such as by means of threaded couplings. After the conductive column 23 has been installed, a submerged well hole 24 can be drilled into the sea floor 2f and a casing column 25 can be installed in the well hole. The casing string 25 may include a wellhead housing and connected casing joints joined together, such as by means of threaded couplings. The wellhead housing can dock with the conductor housing during installation of casing string 25. casing string 25 can be cemented 26 into wellbore hole 24. casing string 25 can extend to a depth adjacent to a lower part of the upper 27u formation. Well hole 24 can then be extended to a lower formation 27b using a pilot drill and lower reamer (not shown).
[0036] The upper formation 27u may be non-productive and a lower formation 27b may a reservoir containing hydrocarbons. Alternatively, lower formation 27b may be non-productive (e.g., a depleted zone), environmentally sensitive, such as an aquifer, or unstable.
[0037] The pressure control assembly (PCA) 1p may include a 28b wellhead adapter, one or more 29u,m,b flow crosses, one or more explosion prevention devices (Blow Out Preventers = BOPs) 30a,u,b, a lower marine riser package (LMRP) 16b, one or more accumulators, and a receiver 31. The lower marine riser assembly (LMRP) 16b may include a control element, a flexible joint 32 and a 28u connector. The wellhead adapter 28b, flow crosses 29u,m,b, explosion prevention devices (BOPs) 30a,u,b, receiver 31, connector 28u and flexible gasket 32 can, each of which includes a housing having a longitudinal hole therethrough and may each be connected, such as by means of flanges, in such a way that a continuous hole is maintained therethrough. Flexible joints 21, 32 can accommodate respective horizontal and/or rotational (also known as offset and roll) movements of the marine mobile drilling unit (MODU) 1m relative to elevator 17 and elevator 17 relative to the control assembly pressure (PCA) 1p.
[0038] Each of the connector 28u and the wellhead adapter 28b may include one or more fasteners, such as dogs, to secure the lower marine lift assembly (LMRP) 16b to the explosion prevention devices (BOPs) 30a,u,b and Pressure Control Assembly (PCA) 1p to the outer profile of the wellhead housing, respectively. Each of the connector 28u and the wellhead adapter 28b may additionally include a sealing sleeve for engaging an internal profile of the respective receiver 31 and the wellhead housing. Each of the connector 28u and wellhead adapter 28b may be in electrical or hydraulic communication with the control element and/or additionally include an electrical or hydraulic actuator and an interface, such as a heat stabilizer, such that a Remotely Operated Subsea Vehicle = ROV (not shown) can operate the actuator to engage the dog with the external profile.
[0039] The lower marine elevator assembly (LMRP) 16b can receive a lower end of the elevator 17 and connect the elevator to pressure control assembly (PCA) 1p. The control element may be in electrical, hydraulic and/or optical communication with an apparatus controller (not shown) on board the marine mobile drilling unit (MODU) 1m via an umbilical cord 33. The control element may include one or more control valves (not shown) in communication with the explosion prevention devices (BOPs) 30a,u,b for the operation thereof. Each of the control valves may include an electrical or hydraulic actuator in communication with the umbilical cord 33. The umbilical cord 33 may include one or more electrical and/or hydraulic control cables/conducts to the actuator. The accumulators can store pressurized hydraulic fluid to operate Explosion Prevention Devices (BOPs) 30a,u,b. Additionally, the accumulators can be used to operate one or more of the other components of the 1p Pressure Control Assembly (PCA). The control element may additionally include control valves to operate the other functions of the pressure control assembly (PCA) 1p. The apparatus controller can operate the pressure control assembly (PCA) 1p through the umbilical cord 33 and the control element.
[0040] A lower end of the booster line 18b can be connected to a branch of the flow cross 29u by means of a shut-off valve. A multiple booster manifold can also be connected to the lower end of the booster line and have a nozzle connected to a respective branch of each of the 29 m flow crosses, b. The shut-off valves can be arranged in the respective nozzles of the manifold manifold of the booster. Alternatively, a separate stop line (not shown) can be connected to the branches of the flow crosses 29 m,b instead of the booster manifold. A top end of the Booster 18b line can be connected to an outlet of a Booster pump (not shown). A lower end of the line of obstruction 18c may have nozzles connected to respective second branches of the flow crosses 29m,b. The shut-off valves can be arranged in their respective projections at the lower end of the obstruction line.
[0041] A pressure sensor can be connected to a second branch of the top flow cross 29u. Pressure sensors can also be connected to the nozzles of the obstruction line between the respective shut-off valves and the respective second branches of the flow cross. Each of the pressure sensors can be in data communication with the control element. Lines 18b,c and umbilical cord 33 can extend between the mobile marine drilling unit (MODU) 1m and the pressure control assembly (PCA) 1p by being attached to supports arranged along the elevator 17. Each of the shutoff valves can be automated and have a hydraulic actuator (not shown) operated by the aerodynamic suspension element.
[0042] Alternatively, the umbilical cord can be extended between the mobile offshore drilling unit (MODU) and the pressure control assembly (PCA) independently of the elevator. Alternatively, the shut-off valve actuators can be electrical or pneumatic.
[0043] The 1h fluid handling system 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 agitator 36, one or more pressure gauges 37c,m, one or more stroke counters 38c,m, one or more flow lines, such as a cement line 14, a slurry line 39, a return line 40, a cement mixer 42, and one or more tag launchers 44a,b. Drilling fluid 47m may include a base fluid. The base liquid can be refined or synthetic oil, water, brine, or a water/oil emulsion. Drilling fluid 47m may additionally include solids dissolved or suspended in the base liquid, such as organophilic clay, lignite and/or asphalt, thereby forming a slurry.
[0044] A first end of the return line 40 can be connected to the output of the diverter and a second end of the return line can be connected to an inlet of the agitator 36. A lower end of the slurry line 39 can be connected to an outlet of the slurry pump 34 and an upper end of the slurry line can be connected to the upper operating inlet. The pressure gauge 37m can be mounted as a part of the slurry line 39. An upper end of the cement line 14 can be connected to the inlet of the cementing mooring ring and a lower end of the cement line can be connected to an outlet of the cement pump 13. The tag launcher 44, a shut-off valve 41 and the pressure gauge 37c can be mounted as part of the cement line 14. A lower end of a slurry feed line can be connected to an outlet of the slurry tank 35 and an upper end of the slurry feed line can be connected to an inlet of the slurry pump 34. An upper end of a cement feed line can be connected to an outlet of the cement mixer 42 and a lower end of the cement feed line can be connected to a cement pump inlet 13.
[0045] The tag launcher 44 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 therein. loaded. A radio frequency identification (RFID) tag on the cell 45 may be disposed on the respective plunger for a selective release closure and for pumping into and down the well to communicate with the liner installation assembly (LDA) 9d. The plunger can be movable relative to its launcher housing between a captured position and a release position. The plunger can be moved between positions by the respective actuator. The actuator can be hydraulic, such as a piston and cylinder assembly.
[0046] Alternatively, the actuator can be electric or pneumatic. Alternatively, each of the actuators can be manual, such as a handwheel. Alternatively, each of the tags 45a,b can be released manually by breaking a connection on the respective line. Alternatively, each of the label launchers can be part of the cement head.
[0047] The operating column 9 can be rotated 8 by means of the upper motor 5 and can be lowered by a displacement block 11t, thus thereby widening the casing column 15 in the lower formation 27b. Drilling fluid in wellbore 24 can be diverted through courses 15e of reamer shoe 15s, where fluid can circulate waste away from the shoe and return waste into a bore of casing string 15. Returns 47r (drilling fluid plus debris) may flow up into casing hole and into a casing installation assembly (LDA) hole 9d. Returns 47r can flow into the liner installation assembly (LDA) orifice and into a bypass valve 50 (Figure 2A) thereof. The returns 47r can be bypassed in the annular ring 48 formed between the operating column 9/casing column 15 and the casing column 25/well hole 24 via the bypass valve 50. The returns 47r can exit the well hole 24 and, flow in an annular crown formed between the elevator 17 and the drill pipe 9p through an annular crown of the lower marine elevator assembly (LMRP) 16b, explosion prevention device assembly (BOPs) and wellhead 10 Returns 47r can exit the elevator ring sprocket and enter return line 40 through an upper marine elevator assembly (UMRP) ring sprocket 16u and diverter 19. Returns 47r can flow through return line 40 and enter the entrance of the shale shaker. Returns 47r can be processed by the shale agitator 36 to remove debris.
[0048] Figures 2A-2D illustrate the liner installation assembly (LDA) 9d. The liner installation assembly (LDA) may include a bypass valve 50, a waste cap 51, an adjustment tool 52, an operating tool 53, an upper compaction assembly 55, a spacer 56, a clearance 57, a lower compaction assembly 58, a detent 59 and a plug release system 60.
[0049] An upper end of the diverter valve 50 may be connected to a lower end of the drill pipe 9p and a lower end of the diverter valve 50 may be connected to an upper end of the waste cap 51, such as by means of threaded couplings. A lower end of the waste cap 51 can be connected to an upper end of the setting tool 52 and a lower end of the setting tool can be connected to an upper end of the operating tool 53, such as by threaded couplings. The operating tool 53 can also be attached to packer 15p. An upper end of the spike 54 can be connected to a lower end of the operating tool 53 and a lower end of the spike can be connected to the release 57, such as through threaded couplings. The spike 54 can extend through the upper compaction assembly 55. The upper compaction assembly 55 can be secured to the packer 15p. An upper end of spacer 56 may be connected to a lower end of upper condensing assembly 55, such as via threaded couplings. An upper end of the lower compaction assembly 58 may be connected to a lower end of the spacer 56, such as via threaded couplings. An upper end of detent 59 may be connected to a lower end of lower condensing assembly 58, such as via threaded couplings. An upper end of plug release system 60 may be connected to a lower end of detent 59 such as via threaded couplings.
Bypass valve 50 may include a housing, a perforation valve and a gate valve. The derailleur housing may include two or more tubular sections (three are shown), one connected to the other, such as through threaded couplings. The diverter housing may have threaded couplings formed at each of the longitudinal ends thereof formed at each of the longitudinal ends thereof for connection with the drill pipe 9p at an upper end thereof and the waste cap 51 at the lower end of the same. The perforation valve can be arranged in the housing. The piercing valve may include a body and a valve member, such as a flap valve member, pivotally connected to the body and biased in a closed position direction, such as by means of a torsion spring. The flap valve member can be oriented to allow fluid flow in a downward direction from the drill pipe 9p through the remainder of the liner installation assembly (LDA) 9d and prevent reverse flow in an upward direction from casing installation assembly (LDA) 9d to drill pipe 9p. Closing the flap valve member can isolate an upper portion of a bypass valve orifice from a lower portion thereof. Although not shown, this body may have a filling hole formed through a wall thereof and bypassing the flap valve member.
[0051] The bypass port valve may include a sleeve and a tensioning member, such as a compression spring. The sleeve may include two or more sections (four are shown), connected to each other, such as via couplings and/or threaded fasteners. An upper section of the sleeve may be connected to a lower end of the bore valve body, such as through threaded couplings. Various interfaces between the sleeve and the housing and between the housing sections can be insulated by means of seals. The sleeve can be disposed in the housing and can be longitudinally movable with respect thereto between an upper position (not shown) and a lower position (Figure 4A). The sleeve can be stopped in the lower position against an upper end of the lower housing section and in the upper position by means of the piercing valve engaging a lower end of the upper housing section. The middle section of the housing may have one or more flow gates and one or more equalizing gates formed through a wall thereof. One of the sleeve sections may have one or more equalizing slits formed therethrough providing fluid communication between a spring chamber on an inner surface of the intermediate housing section and the lower piercing portion of the bypass valve 50.
[0052] One of the sleeve sections can cover the housing flow ports when the sleeve is in the lower position, thus closing the housing flow ports and the sleeve section can be free of the flow ports when the sleeve is in the top position, thus opening the flow portals. In operation, a peak pressure from the returns 47r generated by the installation of the liner installation assembly (LDA) 9d and the liner column 15 in the well bore may be exerted on a lower face of the closed flap valve member. The pressure spike can push the flap valve member in an upward direction, thereby also pulling the sleeve in an upward direction against the compression spring and opening the housing flow ports. The returns 47r experiencing the overpressure can then be bypassed through the open flow ports by the closed flap valve member. Once the casing column 15 has been made available, dissipation of the overpressure may allow the spring to return the sleeve to the lower position.
[0053] The waste cap 51 may include a piston, a mandrel and a release valve. Although shown as one piece, the mandrel may include two or more sections, one connected to the other, such as through threaded couplings and/or fastener. The mandrel may have threaded couplings formed at each of the longitudinal ends thereof for connection to the bypass valve 50 at an upper end thereof and the adjustment tool 52 at a lower end thereof.
[0054] The piston may be an annular member having an orifice formed therethrough. The mandrel may extend through the piston bore and the piston may be longitudinally movable with respect to it subject to a hold between an upper shoulder of the mandrel and the release valve. The piston may carry one or more (not shown) outer seals and one or more (two shown) inner seals. Although not shown, the scrap bonnet 51 may additionally include a split seal gasket carrying each of the piston seals and a retainer for connecting each of the seal gaskets to the piston, such as through a connection. threaded. Internal seals can isolate an interface between the piston and the mandrel.
[0055] The piston may also be disposed in a bore of the well-polished receptacle (PBR) 15r adjacent to an upper end thereof and may be longitudinally movable with respect thereto. The outer seals may insulate an interface between the piston and the well-polished receptacle (PBR) 15r, thereby forming an upper end of a buffer chamber 58. A lower end of the buffer chamber 58 may be formed by a sealed interface between the compaction set 55 and the packer 15p. Compensator chamber 58 can be filled with a hydraulic fluid (not shown), such as fresh water or oil, in such a way that the piston can be hydraulically locked in place. The buffer chamber 58 can prevent debris infiltration from the well hole 24 from obstructing the operation of the casing installation assembly (LDA) 9d. The piston may include a filling passage extending longitudinally therethrough, closed by a plug. The mandrel may include a deflection groove formed in and along an outer surface thereof. The bypass groove can create a leak path through the inner piston seals when removing the Liner Installation Assembly (LDA) 9d from the Liner Post 15 to release the hydraulic lock.
[0056] The release valve may include a shoulder formed on an outer surface of the mandrel, a closure member such as a sleeve and one or more deflection members such as compression springs. Each of the springs can be loaded onto a rod and can be clamped between a stationary washer connected to the rod and a sliding washer along the rod. Each of the rods can be disposed in a pocket formed on an outer surface of the mandrel. The sleeve may have an attached internal drill edge formed at a lower end of the sleeve and extending into the pockets. The lower end can also be arranged against the sliding washer. The valve shoulder may have one or more radial postcards formed therethrough. The valve shoulder may carry a pair of seals straddling the radial ports and engaging the valve sleeve, thereby isolating the mandrel bore from the compensating chamber 58.
[0057] The piston may have a torsion profile formed at a lower end thereof and the valve seat may have a complementary torsion profile formed at an upper end thereof. The piston may additionally have flare blades formed on an outer surface thereof. The torsion profiles can be mated during removal of the liner installation assembly (LDA) 9d from the liner column 15, thereby torsionally connecting the piston to the mandrel. The piston may then be rotated during removal to return the accumulated flare debris adjacent to the upper end of the well-polished receptacle (PBR) 15r. The lower end of the piston may also rest on the valve sleeve during removal. If the bypass groove becomes clogged, pulling the drill pipe 9p can cause the valve sleeve to be pushed in a downward direction relative to the mandrel and against the springs to open the radial ports, thereby releasing the hydraulic lock .
[0058] Alternatively, the piston may include two semi-annular elongated segments connected together by means of fasteners and having gaskets stapled between mated faces of the segments to inhibit leakage of fluid from one end to the other end. Alternatively, the piston may have a radial bypass port therein and formed therein at a location between the upper and lower inner seals, and the bypass groove can create a leak path through the lower inner seal to the bypass port. Alternatively, the valve sleeve can be secured to the mandrel via one or more shear fasteners.
[0059] The adjustment tool 52 may include a body, a plurality of fasteners such as dogs, and a rotor. Although shown as one piece, the body may include two or more sections connected to one another, such as via couplers and/or fasteners. The body may have threaded couplings formed at each of the longitudinal ends thereof for connecting to scrap hood 51 at an upper end thereof and an operating tool 53 at a lower end thereof. The body may have a recess formed in an outer surface thereof to receive the rotor. The rotor may include a pressure/thrust ring, a thrust bracket, and a guide ring. The guide ring and thrust support can be arranged in the recess. The thrust support may have an inner raceway torsionally connected to the body, such as via a snap fit, an outer runner torsionally connected to the thrust ring, such as via a snap fit, and a scroll element arranged between the rails. The thrust ring can be connected to the guide ring, such as through one or more threaded fasteners. An upper portion of a pocket may be formed between the push ring and the guide ring. The adjustment tool 52 may additionally include a retainer ring connected to the body adjacent the recess, such as via one or more threaded fasteners. A lower portion of the pocket can be formed between the body and the retaining ring. Dogs can be placed in the pocket and spaced around the pocket.
[0060] Each of the dogs may be mobile relative to the rotor and body between a retracted position (shown) and an extended position. Each dog can be propelled in one direction to the extended position by means of a deflection member, such as a compression spring. Each of the dogs can have an upper drill edge, a lower drill edge, and an opening. An inner end of each of the springs may be disposed against an outer surface of the guide ring and an outer portion of each of the springs may be received in the respective opening of the hammer. The upper bit edge of each dog can be clamped between the thrust ring and guide ring and the lower bit edge of each dog can be clamped between the retaining ring and the body. Each of the dogs can also be trapped between a lower end of the push ring and an upper end of the retaining ring. Each of the dogs may also be torsionally connected to the rotor, such as via a pivoting fastener (not shown) received by the respective hammer and guide ring.
[0061] The operating tool 53 may include a body, a lock, a clutch, and a hitch. The body may include two or more tubular sections (two are shown) connected to one another such as through threaded couplings. The body may have threaded couplings formed at each of the longitudinal ends thereof for connecting the adjustment tool 52 at an upper end thereof and the needle 54 at a lower end thereof. The hitch may longitudinally or torsionally connect the casing string 15 to an upper portion of the casing installation assembly (LDA) 9d. The hitch may include a push cap having one or more twist fasteners, such as wrenches, and a longitudinal fastener, such as a floating nut. The wrenches can mate with the torsion profile formed on a top end of the 15p packer and the floating nut can be screwed onto the threaded dogs of the packer. The latch can be disposed over the body to prevent premature release of the hitch from the casing string 15. The clutch can selectively and torsionally connect the thrust cap to the body.
[0062] The lock may include a piston, a plug, one or more fasteners such as dogs, and a sleeve. The plug can be connected to an outer surface of the body, such as through threaded couplings. The plug can have an inner seal and an outer seal. The inner seal can insulate an interface formed between the plug and the body and the outer seal can insulate an interface formed between the plug and the piston. The piston may have an upper portion disposed along an outer surface of the body and an enlarged lower portion disposed along an outer surface of the plug. The piston may carry an internal seal at the top to isolate an interface formed between the body and the piston. The piston can be secured to the body, such as by means of one or more shear fasteners. An actuation chamber can be formed between the piston, the plug and the body. The body may have one or more portals formed through a wall thereof providing fluid communication between the chamber and an orifice in the body.
[0063] The lock sleeve may have an upper portion disposed along an outer surface of the body and extending into the lower portion of the piston and into an enlarged lower portion. The lock sleeve may have one or more openings formed therein and spaced around the sleeve to receive a respective dog therein. Each of the dogs can extend into a groove formed on an outer surface of the body, thereby securing the lock sleeve to the body. A thrust support may be disposed in the lower portion of the lock sleeve and against a shoulder formed on an outer surface of the body. The thrust support can be biased against the body by means of a compression spring.
[0064] The body may have a torsion profile, such as one or more keyways formed in an outer surface thereof adjacent to a lower end of the upper section of the body. A key can be disposed in each of the keyways. A lower end of the compression spring can be supported against the keyways.
[0065] The thrust cap can be connected to the lock sleeve, such as by means of a lap joint. The hitch keys can be connected to the thrust cap, such as via one or more threaded couplings. A shoulder may be formed on an inner surface of the thrust cap by dividing an enlarged upper portion from an enlarged lower portion of the thrust cap. The shoulder and the enlarged lower portion may receive an upper portion of a deflection member, such as a compression spring. A lower end of the compression spring can be received by a shoulder formed in an upper end of the floating nut.
[0066] The floating nut can be driven against a shoulder formed by an upper end of the lower section of the housing by means of the compression spring. The floating nut may have a thread formed on an outer surface of the floating nut. Threading can be counter-clockwise, such as counterclockwise (left-handed), in relation to the rest of the operating column 9 threads. The floating nut can be twist-connected to the body by having one or more keyways formed along an inner surface thereof and receiving the keys, thereby providing a release latch in an upward direction of the floating nut relative to the body while maintaining a twisted connection.
[0067] The clutch may include a gear and a guide nut. The gear may be formed of one or more teeth connected to the thrust cap, such as through a threaded fastener. The teeth can mesh with the keys and in this way twist the thrust cap to the body. The guide nut may be disposed in a threaded passage formed on an inner surface of the enlarged upper portion of the thrust cap and have an outer threaded surface meshed with the threaded thrust cap, thereby longitudinally connecting the guide nut and the cap. of thrust while providing a twist release clasp between them. The guide nut may be twist-connected to the body having one or more keyways formed along an inner surface thereof and receiving the keys, thereby providing a longitudinal release latch of the guide nut relative to the body while maintaining the connection with twist. The threads on the guide nut and thrust cap may have a thinner spacing, be on the opposite hand, and have a greater number than the threads on the floating nut and packer dogs to facilitate a less longitudinal (and opposite) displacement by rotation of the guide nut relative to the floating nut.
[0068] When in operation, once the casing suspension element 15h has been adjusted, the lock can be released by feeding sufficient fluid pressure through the body portals. The weight can then be adjusted downward on the casing column, thereby pushing the thrust cap in an upward direction and disengaging the clutch gear. The operating column can then be rotated to cause the guide nut to travel in a downward direction through the thrust cap's traverse passage while the floating nut travels in an upward direction relative to the threaded dogs of the packer. The floating nut can disengage from two threaded dogs before the guide nut is removed under the threaded passage. Rotation can continue to remove the guide nut, thereby restoring the twisted connection between the thrust cap and the body.
[0069] Alternatively, the operating tool can be replaced by means of a hydraulically released operating tool. The hydraulically released operating tool may include a piston, a shear stop, a torque sleeve, a longitudinal fastener such as a collet, a cap, a housing, a spring, a body and a detent. The tweezers may have a plurality of fingers, each having a fin formed on a lower portion thereof. Finger fins may engage a complementary portion of packer 15p, thereby longitudinally connecting the operating tool to casing string 15. The twist sleeve may have keys to engage the twist profile formed in packer 15p. The gripper, the box and the lid can be longitudinally movable with respect to the body subject to limitation by the stop. The piston may be secured to the body via one or more shear fasteners and may be fluidly operable to release the fingers from the collet when actuated by limiting release pressure. When in operation, fluid pressure can be increased or increased to push the piston and fracture the shear fasteners, thereby releasing the piston. The piston can then move one way up in one direction the caliper until the piston is buttressed in the caliper and fractures the stop. The hitch piston can continue movement in an upward direction while carrying the collet, case, and cap in an upward direction until a lower part of the torque sleeve rests on the fingers, thereby pushing the fingers radially in a sense inward. The detent may be a split ring radially offset in an inward direction and disposed between the collet and the housing. The body may include a recess formed in an outer surface of the body. During one-way upward movement of the piston, the detent can align and enter the recess, thus preventing re-engagement of the fingers. The movement of the piston may continue until the cap rests against a stop shoulder to the body, thus ensuring complete disengagement of the fingers.
[0070] An upper end of an actuation chamber 59 may be formed via the sealed interface between the compaction assembly 55 and the packer 15p. A lower end of the actuation chamber 59 may be formed through the sealed interface between a cementitious plug of the plug release system 60 and the jacket suspension element 15h. The actuation chamber 59 may be in fluid communication with the liner installation assembly (LDA) orifice (above a ball seat of the plug release system 60) via one or more portals 56p formed through a wall of the spacer 56.
[0071] The consolidation assembly 55 may include a lid, a body, an internal sealing assembly, such as a sealing stack, an external sealing assembly, such as a cartridge, one or more fasteners such as dogs, a sleeve lock, an adapter and a stop. The condensing assembly 55 may be tubular and may have a hole formed therethrough. The spike 54 can be received through the hole of the compaction assembly and an upper end of the spacer 56 can be secured to a lower end of the compaction assembly 55. The compaction assembly 55 can be secured to the packer 15p via dog engagement with the inner surface of the packer.
[0072] The sealing stack may be arranged in a groove formed in an inner surface of the body. The seal stack may be connected to the body via a retainer between a shoulder of the groove and an underside of the lid. The seal stack may include an upper adapter, an upper set of one or more directional seals, a center adapter, a lower set of one or more directional seals, and a lower adapter. The cartridge can be disposed in a groove formed in an outer surface of the body. The cartridge can be attached to the body via a detent between a shoulder of the slot and a lower end of the cap. The cartridge can include a packing gland and one or more packing sets (two are shown). The gasket may have a groove formed in an outer surface thereof to receive each of the assemblies and seal. Each of the seal assemblies may include a seal, such as an S-shaped ring, and a pair of anti-extrusion elements, such as elastic springs.
[0073] The body may also carry a seal, such as an O-ring, to isolate an interface formed between the body and the gasket. The body may have one or more (two are shown) equalizing portals formed through a wall thereof located adjacently below the cartridge slot. The body may additionally have a stop shoulder formed on an inner surface thereof adjacent to the equalizing ports. The lock sleeve can be disposed in a hole in the body and movable longitudinally with respect to it between a lower position and an upper position. The lock sleeve can be stopped in the upper position by engaging an upper end of the lock sleeve with the stop shoulder and held in the lower position by means of a stop. The body may have one or more openings formed therethrough and spaced around the body to receive a respective dog therein.
[0074] Each of the dogs may extend into a groove formed in an inner surface of packer 15p, thereby securing a lower portion of liner installation assembly (LDA) 9d on packer 15p. Each of the dogs can be radially movable relative to the body between an extended position (shown) and a retracted position. Each of the dogs can be extended through an interaction with a cam profile formed on an outer surface of the lock sleeve. The lock sleeve may additionally have a tapered taper formed on a wall thereof and collet fingers extending from the tapered taper to a lower end thereof. The anvil may include the gripper fingers and a complementary groove formed in an inner surface of the body. The stop can resist movement of the lock sleeve from the lower position to the upper position.
[0075] Figures 3A and 3B illustrate the plug release system 60. The plug release system 60 may include a launcher 60a and the cementation plug, such as a contact plug 60b. Each of launchers 60a and cam caps 60b may be a tubular member having a hole formed therein. Launcher 60a may include a housing 61, an electronic assembly 62, a power source such as a battery 63, an antenna 64, a mandrel 65, and a hitch 66. Housing 61 may include two or more tubular sections 61a - c, one connected to the other, such as through threaded couplings. Housing 61 may have a coupling, such as a threaded coupling, formed at an upper end thereof for connection to spacer 56. Housing middle section 61b may have an enlarged/increased internal diameter to form an electronics chamber for receiving the antenna 64 and the mandrel 65.
[0076] Alternatively, the power source can be a capacitor or an inductor instead of the battery.
[0077] The antenna 64 may be tubular and may extend along an inner surface of the mandrel 65. The antenna 64 may include an inner jacket, a coil and a jacket (housing, sleeve). The antenna coating can be made from a non-magnetic, non-conductive material such as a polymer or a composite, can have a hole formed longitudinally therethrough, and can have a helical groove formed in an outer surface thereof. The antenna coil can be wound into the helical groove and can be made of an electrically conductive material such as copper or an alloy thereof. The antenna jacket can be made from a non-magnetic, non-conductive material and can insulate the coil. The antenna casing may have a flange formed on a lower end of the antenna. Wires can be connected to the ends of the antenna coil and extend into the flange. The lower housing section 61c may have a groove formed at an upper end and an inner surface thereof and the antenna flange may be disposed in the groove and retained there by a lower end of the mandrel, thereby connecting the antenna 64 to the accommodation 61.
[0078] The mandrel 65 may be a tubular member having one or more (only one is shown) pockets formed in an outer surface thereof. The mandrel 65 can be connected to the housing 61 via a retainer between a lower end of the upper housing section 61a and an upper end of the lower housing section 61c. Mandrel 65, housing 61, and/or coupling 66 may have electrical conduits formed in a wall thereof to receive wiring connecting antenna 64 to electronics assembly 62, connecting battery 63 to electronics assembly, and connecting coupling 66 to electronics assembly. electronic set. Although shown in the same pocket, the electronics assembly 62 and battery 63 can be disposed in respective pockets of the mandrel 65. The electronics assembly 62 can include a control circuit 62c, a transmitter 62t, a receiver 62r and an integrated actuator controller 62m on a printed circuit board 62b. The control circuit 62c may include a microcontroller (Microcontroller = MCU), a Memory Unit = MEM (Memory Unit), a clock, and an analog-to-digital converter. The control circuit 72c may include a microcontroller (Microcontroller = MCU), a memory unit (Memory Unit = MEM), a clock, and an analog-to-digital converter. The 72t transmitter can include an amplifier (Amplifier = AMP), a modulator (Modulator = MOD), and an oscillator (Oscillator = OSC). The 72r receiver can include an amplifier (Amplifier = AMP), a demodulator (Demodulator = MOD) and a filter (Filter = FIL). Actuator controller 72m may include a power converter for converting a DC power signal supplied by battery 73 to a power signal suitable for operating an electric motor 75m from actuator 75. Electronics assembly 72 may be housed in an enclosure 62e.
[0079] Figure 1D illustrates the radio frequency identification (RFID) tag 45. The radio frequency identification (RFID) tag 45 may be a passive tag and may include an electronic assembly and one or more antennas housed in an encapsulation. The electronics assembly may include a memory unit, a transmitter and a radio frequency power generator (Radio Frequency = RF) to operate the transmitter. Radio frequency identification (RFID) tag 45 may be programmed with a command signal addressed to buffer release system 60. Radio frequency identification (RFID) tag 45 may be operable to transmit a command signal wireless (Figure 4C) 49c, such as a digital and electromagnetic command signal to the antenna 64 in response to receiving an activation signal 49a therefrom. The MCU of control circuit 62c can receive the command signal 49c and operate the engagement actuator in response to receiving the command signal.
[0080] Figure 1E illustrates an alternative radio frequency identification (RFID) tag 46. Alternatively, the radio frequency identification (RFID) tag 45 may be a wireless identification and sensor platform (Wireless Identification and Sensing Platform = WISP) and not a radio frequency identification (RFID) 46. The wireless identification tag and sensor platform (WISP) 46 may additionally have a microcontroller MCU and a receiver for receiving, processing and storing data from the buffer release system 60. Alternatively, the radio frequency identification (RFID) tag may be an active tag having an onboard battery powering a transmitter rather than having an RF power generator or the wireless identification tag and sensor platform (WISP) can have an onboard battery to assist with data handling functions. The active tag may additionally include a safety, such as a pressure switch, such that the tag does not begin transmitting until the tag is in the well hole.
[0081] Returning to Figures 3A and 3B, the hitch 66 may include a retainer sleeve 67, a receiving chamber 68, an actuator 69, a lock sleeve 70, and a fastener such as a collet 71. An upper end of the retainer sleeve 67 can be connected to a lower end of the lower housing section 61c, such as through threaded couplings. The receiving chamber 68 may be formed on an inner surface of the lower housing section 61c and may occupy a middle and lower portion thereof. Actuator 69 can be linear and can include a 69s solenoid, a 69g guide, and a 69h lug. Each of the 69s solenoid and 69g guide can include a shaft and a cylinder. The 69h lug may have a threaded socket formed therethrough for each of the actuator shafts. A top end of each of the actuator shafts can be threaded and received in the respective socket, thus connecting the 69s solenoid and the 69g guide to the 69h lug.
[0082] The lock sleeve 70 may have a threaded coupling formed on an upper end thereof to receive a threaded coupling formed on an outer surface of the lug 69h, thereby connecting the latch sleeve and the lug. Lock sleeve 70 may be longitudinally movable by actuator 69 and be relative to housing 61 between a lower position (shown) and an upper position (Figure 4E). Lock sleeve 70 can be stopped in the down position by engaging a lower end thereof with a stop shoulder 72h of contact plug 60b.
[0083] The collet 71 may have an upper base portion and fingers extending from the base portion to a lower end thereof. The caliper base may have a threaded socket formed on the upper end of the caliper for each of the actuator cylinders. A lower end of each of the actuator cylinders is threadable and can be received in the respective socket, thereby connecting solenoid 69s and guide 69g to caliper 71. The caliper base may have a threaded inner surface to receive an outer surface The retainer sleeve 67 is threaded, thereby connecting the collet 71 and the housing 61. The retainer sleeve 67 may have a stop shoulder formed on an outer surface thereof to receive an upper end of the contact plug 60b.
[0084] The collet 71 may be radially movable between an engaged position (shown) and an disengaged position (Figure 4F) by interacting with the lock sleeve 70. Each of the collet fingers may have a fin formed at one end bottom of it. In the engaged position, the tweezer fins may mate with a complementary groove 72g of the contact plug 60b, thereby loosely connecting the contact plug 60b to the housing 61. The fingers of the tweezer may be cantilevered from the base of the clamp and have a stiffening forcing the fins in one direction to the disengaged position. Downward movement of the lock sleeve 70 may press the collet fins into the groove 72g against the stiffening of the collet fingers. The upward movement of the latch sleeve 70 may allow the tong fingers to stiffen to pull the fins from the slot 72g, thereby releasing the contact plug 60b from the launcher 60a.
[0085] Contact plug 60b may include a body 72, a mandrel 73, a spike 74, a shoulder seal 75, an anchor 76, and a seat 77. The body 72 may have a 72g groove formed in an inner surface thereof adjacent to an upper end thereof, a stop shoulder 72h formed on an inner surface thereof adjacent to groove 72g, one or more threaded sockets 72s formed through a wall thereof, and a threaded coupling formed at a lower end of the same. Each of the: body 72, mandrel 73, spike 74, anchor 76 and seat 77 can be made from a pierceable material, such as cast iron, non-ferrous metal or an alloy, a fiber reinforced composite, or a polymer engineered.
[0086] The mandrel 73 may be disposed in a hole in the body 72, may have a groove 73 formed in an outer surface thereof, a mooring profile 73p formed in the lower surface thereof adjacent to a lower end thereof, and a an upper seal groove 73u and a lower seal groove 73g each formed on an outer surface thereof and each bearing a seal. The mooring profile 73p may have a mooring shoulder, a hitch profile and a sealing hole for receiving the dart 43d (Figure 4D). Dart 43d may have a complementary mooring shoulder, a catch for engaging the engagement profile, thereby connecting the dart and contact plug 60b, and a seal for engaging the seal hole. A threaded fastener 78u can be received in each of the threaded sockets 72s and extend into slot 73g, thereby connecting the chuck 73 and the body 72. The threaded fasteners 78u can be shear fasteners to act as a safety shutoff to release the contact plug 60b in the event of a failure of the electronics assembly 62 and/or the latch 66.
[0087] The spike 74 may have an upper threaded coupling formed on an inner surface thereof engaged with the threaded coupling of the body, thereby connecting the spike and body 72. The body 72 may have a middle and lower portion with a diameter external reduced to form a recess to receive lip seal 75. Lip seal 75 can be connected to body 71 via a retainer between a shoulder 72h formed in an outer surface of body 72 and an upper end of spike 74. The lip seal 75 can include a vane stack (vertical stabilizers), a spare stack, and a lower end adapter. Each of the stacks may include one or more units (three are shown), each of the units having a replacement ring and a gasket molded over the respective replacement ring. Each gasket can be directional and made from an elastomer or elastomeric copolymer. An outer diameter of each of the gaskets may correspond to an inner diameter of the liner gaskets 15j, such as being slightly larger than the inner diameter. Each of the gaskets can be oriented to sealingly engage the gasket 15j in response to pressure above the gasket being greater than the pressure below the gasket. Each of the replacement rings and adapter can be made from pierceable materials. The top end of the spike may have a groove to match the end adapter drill edge.
[0088] The anchor 76 can include a mandrel, a longitudinal coupling, a torsion coupling and an external seal. The spike 74 may have a lower threaded coupling formed on the inner surface thereof and an outer groove formed on a lower end thereof. The anchor chuck may have a threaded coupling formed on an outer surface thereof engaged with the threaded spike coupling, thereby connecting the spike 74 and anchor 76. The anchor chuck may have a groove formed on an inner surface thereof to carry a seal, thereby isolating an interface formed between the anchor mandrel and the spike 74. The outer seal may be disposed in the outer groove of the spike. A retainer may have an outer portion extending in the outer groove of the spike and an inner portion retained between the lower end of the spike and an upper end of the torsion coupling, thereby retaining the outer seal in the outer groove of the spike. The twist coupling may be a nut having an inner threaded surface engaged with the threaded coupling of the anchor mandrel and having one or more helical fans formed on an outer surface thereof. The anchor chuck may have a tapered cone formed on an outer surface thereof and the longitudinal coupling can be arranged between the torque nut and the taper cone. The longitudinal coupling may be a split ring having teeth formed along an outer surface thereof and a tapered cone formed on an inner surface thereof, being complementary to the mandrel cone.
[0089] Seat 77 may include a nose/tip and an internal receiver connected together, such as through threaded couplings. The anchor chuck may have one or more (two are shown) holes formed through a wall thereof adjacent the lower end thereof. The nose may have one or more threaded sockets formed through a wall thereof and the receiver may have one or more corresponding holes formed in an outer surface thereof. A threaded shear fastener 78b may be received in each of the sockets and extend through the respective anchor chuck hole and into a corresponding receiving hole, thereby loosely connecting seat 77 to anchor 76. The receiver may have a cone. conical formed on an inner surface of the same to receive the sphere 43b (Figure 4A).
[0090] Figures 4A - 4F illustrate the operation of the plug release system 60. Once the casing string 15 has been advanced into the well hole 24 via the operating column 9 to a desired installation depth, the conditioner 80 can be circulated by cement pump 13 through valve 41 to prepare for pumping the cement slurry 81. Ball launcher 7b can then be operated and conditioner 80 can propel ball 43d down the operating column 9 to seat 77. Once ball 43b is docked in seat 77, pumping can continue to increase pressure in liner installation assembly (LDA)/actuation chamber 59 orifice.
[0091] Once a first pressure limit is reached, a piston of the linear suspension element 15h can adjust the slides thereof against the box 25. The pumping of the conditioner 80 can continue until a second pressure limit is reached and the operating tool 53 is unlocked. Pumping may continue until a third pressure limit is reached and seat 77 is released from contact plug 60b by fracturing shear fasteners 78b. The released seat 77 and ball 43b can then be operated by conditioner 80 through the casing hole to a detent (not shown) of the mooring collar 15c. The weight can then be adjusted down on casing string 15 and operating string 9 rotated, thereby releasing casing string 15 from adjustment tool 53. An upper portion of operating string 9 can be lifted and then lowered to confirm release of operating tool 53. Operating column 9 and casing column 15 can then be rotated 8 from the surface by means of upper motor 5 and rotation can continue during the cementing operation. The cement slurry 81 can be pumped from the mixer/agitator 42 into the cementing lashing ring 7c through the valve 41 via the cement pump 13. The cement slurry 81 can flow into the launcher 7d and be diverted past it. by dart 43d through derailleur and bypass passes.
[0092] Just before the desired amount of cement slurry 81 has been pumped, tag launcher 44 can be operated to drop radio frequency identification (RFID) tag 45 into the cement slurry. Once the desired amount of cement slurry 81 has been pumped, cement dart 43d can be released from launcher 7d via operation of the plug launcher actuator. A chiseling fluid 82 can be pumped into the cementing mooring ring 7c through valve 41 via cement pump 13. Chiseling fluid 82 can flow in launcher 7d and be forced behind dart 43d by closing the bypass passages , thereby propelling the dart into the hole in the operating column. The pumping of the chiseling fluid 82 via the cement pump 13 can continue until residual cement in the cement discharge conduit has been cleared. The pumping of chiseling fluid 82 can then be transferred to the slurry pump 34 by closing valve 41 and opening valve 6.
[0093] Dart 43d, cement slurry 81, and radio frequency identification (RFID) tag 45 must be directed and introduced through the orifice of the operating column by chisel fluid 82 until the tag reaches antenna 64 The tag 45 may transmit the command signal 49c to the antenna 64 as the tag passes therethrough. The MCU can receive the command signal from tag 45 and can wait for a pre-set period of time to allow dart 43d to seat in mooring profile 73p and for the resulting increase in pressure to propagate to pressure gauge 37m for confirmation of the dart berthing. This pre-set period of time can be determined using the speed of sound through the chisel fluid 82 and the depth of the mooring profile from the waterline 2s plus a margin relative to uncertainty. After the delay period has elapsed, the MCU can operate the actuator controller 62m to energize the solenoid 69s, thereby directing the latch sleeve 70 to the upper position and allowing the collet 71 to release the dart 43d and the contact plug 60b in a combined way.
[0094] Once released, the dart 43d and the contact plug 60b can be directed through the casing hole by the chisel fluid 82, thus directing the cement slurry 81 through the mooring collar 15c and widening shoe 15s in the annular crown 48. Pumping of chisel fluid 82 may continue until the combined dart and contact plug 43d, 60 dock over collar 15c, thereby engaging anchor 76 with the collar. Once the combined dart and contact plug 43d, 60 have docked, the pumping of chisel fluid 82 can be stopped and the upper portion of the operating column raised until the adjustment tool 52 exits the well-polished receptacle (PBR ) 15r. The upper portion of the operating column can then be lowered until the adjustment tool 52 is engaged over a top of the well polished receptacle (PBR) 15r. The weight can then be exerted on the well polished receptacle (PBR) 15r to adjust the packer 15p. Once the packer 15p has been adjusted, the rotation 8 of the operating column 9 can be stopped. The liner installation assembly (LDA) 9d can then be lifted from the liner column 15 and the chisel fluid 82 circulated to wash off excess cement slurry 81. The operating column 9 can then be retrieved to the unit Maritime Mobile Drilling Rig (MODU) 1m.
[0095] As discussed above, in the event of a failure of the plug release system 60, the pressure in the orifice of the liner installation assembly (LDA) can be increased by continuously pumping the chiseling fluid 82 until a sufficient pressure is struck to fracture fasteners 78u, thereby releasing chuck 73 (with seated dart 43d). An outer surface of the mandrel 73 may have a tapered cone formed therein adjacent to the lower end of the mandrel. An inner surface of the spike 74 may have a complementary taper cone formed therein adjacent to the lower end of the mandrel 73. The released mandrel 73 and the dart 43d may travel in a downward direction until the tapered cones are engaged, thereby vibrating/shaking contact buffer 60b in an attempt to remediate the fault. The safety shutdown release pressure can be set by configuring the 78u fasteners to match a pressure drawn from the weakest component of the liner installation assembly (LDA) 9d.
[0096] Alternatively, one or more radio frequency identification (RFID) tags may be embedded in the dart, such as in one or more sealing fins, thus making the need for the tag launcher 44 obvious. include a pressure sensor in fluid communication with the launcher orifice and the MCU can operate the solenoid once the predetermined pressure has been reached (after receiving the command signal). Alternatively, the electronics assembly may include a proximity sensor instead of the antenna, and the dart may have targets embedded in the fin stack for detection via the proximity sensor.
[0097] Additionally, the cementing head may additionally include a second dart and the plug release system may additionally include a second contact plug. The second contact plug may be released using the same launcher or the plug release system may include a second launcher to launch the second contact plug. The second dart can be launched before pumping the cement slurry. A second radio frequency identification (RFID) tag may be thrown just before the second dart, it may be embedded in the second dart, or it may be embedded in the sphere.
[0098] Figure 5 illustrates an alternative drilling system 100, in accordance with another embodiment of this invention. Drilling system 100 may include the marine mobile drilling unit (MODU) 1m, drilling rig 100r, fluid handling system 100h, fluid transport system 1t, pressure control assembly (PCA) 1p , and an operating column 109. The drilling rig 100r may include the oil well derrick 3. The floor 4, the upper engine 5 and the elevator. Fluid handling system 100h may include cement pump 13, slurry pump 34, tank 35, shale agitator 36, pressure gauges 37c, m, stroke counters 38c, m, one or more flow lines, such as cement line 114, mud line 139h, p and return line 40, cement mixer/mixer 42, ball launcher 7b, javelin launcher 7d, and one or more dart launchers. tag 44a,b.
The mud line 139h,p may include an upper segment 139h and a lower segment 139p connected by a flow tee also having an upper end of the cement line 114 connected thereto. A lower end of the lower segment of slurry line 139p can be connected to an outlet of the slurry pump 34 and an upper end of the upper segment of the slurry line 139h can be connected to the inlet of the upper motor. The 37m pressure gauge and shut-off valve 106 can be mounted as part of the lower segment of the 139p mud line. A lower end of cement line 114 can be connected to an outlet of cement pump 13. Ball launcher 7b, dart launcher 7d, tag launchers 44a, b, shutoff valve 41 and pressure gauge 37c can be assembled as part of cement line 114.
[00100] The plug launcher 7d may have a pipe ingot 143 loaded there instead of the dart 43d. Ingot 143 may include a body, a tail plate. The body can be made from a flexible material such as a foamed polymer. The foamed polymer can be a polyurethane. The body may be in the shape of a bullet (of ammunition) and include a nose portion, a tail portion and a cylindrical portion. The tail portion can be concave or flat. The portion of the nose can be conical, hemispherical or semi-ellipsoidal. The tail plate can be attached to the tail portion during body molding. The shape of the tail plate can match that of the cause portion. The tail plate can be made from a polymer (unfoamed) such as polyurethane.
[00101] An upper end of operating column 109 may be connected to the upper operating hollow shaft, such as through threaded couplings, during both: installation and cementation of casing column 15. Operating column 109 may include a Liner Deployment Assembly = Liner Installation Assembly (LDA) (Liner Installation Assembly) 109d and the drill pipe 9p. An upper end of liner installation assembly (LDA) 109p can be connected to a lower end of drill pipe 9p, such as through threaded couplings. The liner installation assembly (LDA) 109d may also be connected to the liner column 15. The liner installation assembly (LDA) 109d may include an upper detent 108, a bypass valve 50, the scrap hood 51, the adjustment tool 52, operating tool 53, spike 54, collapsing (upper) assembly 55, spacer 56, release clasp 57, collapsing (lower) assembly 155, a lower detent 177, and a system of buffer release 110.
[00102] An upper end of the upper detent 108 can be connected to a lower end of the drill pipe 9p and a lower end of the upper detent 108 can be connected to an upper end of the bypass valve 50, such as through couplings threaded. An upper end of the lower compaction assembly 155 may be connected to a lower end of the spacer 56, such as through threaded couplings. An upper end of lower detent 177 may be connected to a lower end of condensing assembly 155, such as through threaded couplings. An upper end of plug release system 110 may be connected to a lower end of upper detent 177, such as via threaded couplings.
[00103] The upper detent 108 may include a tubular housing, a tubular housing, and baffle for receiving ingot 143. The housing may have threaded couplings formed at each of the longitudinal ends thereof for connection to the drill pipe 9p at an upper end thereof and with the bypass valve 50 at a lower end thereof. The detent may have a longitudinal hole formed therethrough for the passage of the ball 43 therethrough. The housing may be disposed within the housing and connected therein, such as by being disposed between a lower shoulder of the housing and a threaded fastener connected to the housing. The box can have a solid top and a solid bottom, and a scaled body. The earmuff can be attached to the body. An annular crown can be formed between the body and the housing. The annular crown can serve as a bypass for fluid flow after ingot 143 has been stopped.
[00104] The compaction assembly 155 may include a body and one or more seal assemblies (two are shown). The body may have threaded couplings formed at each longitudinal end thereof for connection with spacer 56 at an upper end thereof and lower detent 177 at a lower end thereof. Each of the seal assemblies may include a directional seal, such as a cup seal, an inner seal, a gasket, and a washer. The inner seal may be disposed at an interface formed between the cup seal and the body. The gasket can be secured to the body, such as by means of a snap ring. The cup seal can be connected to the gasket, such as by molding or press-fitting. An outer diameter of the cup seal may correspond to an inner diameter of the lining suspension element 15h, such as being slightly larger than the inner diameter. The cup seal may be directed to sealingly engage the inner surface of the casing suspension element in response to pressure in the casing installation assembly (LDA) bore being greater than the pressure in the casing column bore (below of the coating suspension element).
The lower detent 177 may include a body and a seat for receiving the ball 43b and being secured to the body, such as by means of one or more shear fasteners. The seat can also be attached to the body by a cam and a follower. Once the ball 43b is retained, the seat can be released from the body by a pressure limit exerted on the ball. Once released, the seat and ball 43b can oscillate relative to the body in a catch chamber thereby reopening the casing installation assembly (LDA) orifice.
[00106] Figures 6A - 6C illustrate the plug release system 110. The plug release system 110 may include a launcher 110a and one or more cementation plugs, such as an upper shoulder plug 110t and a lower plug plug 110t. overhang 110b. Each of the launchers 110a and each of the cam plugs 110t, b may be a tubular member having a hole formed therethrough. Launcher 110a may include a housing 11, electronics assembly 62, battery 63, antenna 64, a mandrel 115 and an actuator.
[00107] Housing 111 may include two or more tubular sections 111a - h. Housing sections 111a - c and 111f - h can be connected to each other such as through threaded couplings. The interfaces between housing sections 111a - h can be isolated by means of seals. An upper end of the fourth housing section 111d may be connected to a lower end of the third housing section 111c, such as through threaded couplings. One end of the fifth housing section 111e can be connected to an upper end of the sixth housing section 111f, such as through threaded couplings. The fourth housing section 111d may have a shoulder formed on an outer surface thereof dividing the section into an upper portion having the enlarged outside diameter and a lower portion having the reduced outside diameter. The fifth housing section 111e may have a complementary shoulder formed on an inner surface thereof adjacent an upper end thereof and may receive the reduced lower portion and the shoulder, thereby longitudinally connecting the fourth housing section 111d and the fifth section of accommodation. The fourth housing section 111d may also have a torsional coupling, such as a complementary castellation, formed on a lower end thereof and the sixth housing section 111f may have a complementary castellation formed on an upper surface thereof and engaged with the castellation of the fourth housing section, in this way in a twisted way, connecting the sections. Housing 111 may have a coupling, such as a threaded coupling, formed on an upper end thereof for connection to lower detent 1777. Housing 111 may have recesses formed therein to receive antenna 64, electronics assembly 62, and the battery 63.
[00108] The mandrel 115 may be tubular and may have a longitudinal hole formed therethrough. The mandrel 115 can be disposed in the housing 111 and can be movable longitudinally with respect thereto from a locked position (shown) to a lower unlocked position (Figures 7B and 8B) and then to an upper unlocked position (Figures 7D and 8D ). Mandrel 115 can be loosely connected to housing 111 in the locked position, such as via one or more shear fasteners (not shown).
[00109] The actuator may include a hydraulic chamber, a quench chamber, a quench piston 121, an atmospheric chamber 116, an actuation chamber, a first solenoid 117a, a first spike 118a, a second solenoid 117b, a second spike 118b , a first rupture disk 119a, a second rupture disk 119b, an upper acting piston 120u, a lower acting piston 120b, and a gas chamber. A lower end of damper piston 121 can be connected to an upper end of mandrel 115, such as through threaded couplings. An interface between the dampening piston 121 and the mandrel 115 can be insulated by a seal. Housing 111 may have electrical conduits formed in a wall thereof to receive wires connecting antenna 64 to electronics assembly 62, connecting battery 63 to electronics assembly, and connecting solenoids 117a, b to electronics assembly.
[00110] The hydraulic, dampening, atmospheric and gas chambers each can be formed between the housing 111 and the damper piston 121 and/or the mandrel 115. A top balance/balance piston 122u can be arranged in the hydraulic chamber and can divide the chamber into an upper portion and a lower portion. A portal formed through a wall of the first housing section 111a can provide fluid communication between the upper portion of the hydraulic chamber and the annular crown 48. The lower portion can be filled with a hydraulic fluid such as oil 123. The hydraulic chamber it can be in limited fluid communication with the dampening chamber via a clutch stroke formed between a shoulder of the damper piston 121 and the first housing section 111a. Clutch stroke may stifle movement of chuck 115 to other positions. A seal may be disposed at an interface between the first housing section 111a and the mandrel 115.
[00111] The atmospheric chamber 116 can be formed radially between the housing 111 and the mandrel 115 and longitudinally between an shoulder 112a formed on an inner surface of the second housing section 111b and an upper end of the fourth housing section 111d. A seal may be disposed at an interface between shoulder 112a and mandrel 115 and the seals may be straddled at an upper interface between the third and fourth housing sections 111c, d. Bottom actuating piston 120b can be disposed in atmospheric chamber 116 and can divide the chamber into a bottom portion 116b and a middle portion 116m. The atmospheric chamber may also have an upper portion having a reduced diameter 116u defined by another shoulder 112b formed in an inner surface of the second housing section 111b. The upper actuating piston 120u may have an outer diameter corresponding to the reduced diameter of the upper portion of the atmospheric chamber 116u and may carry a seal to be engaged therein. Top actuating piston 120u can be connected to mandrel 115, such as through threaded couplings. The lower actuating piston 120b may be retained between a lower end of the upper actuating piston 120u and the upper end of the fourth housing section 111d when the mandrel is in the locked position.
[00112] A first actuation passage 124a formed in the fourth housing section 111d can be in fluid communication with the actuation chamber and with the lower portion of the atmospheric chamber 116b. The first rupture disk 119a may be disposed in the first actuation passage 124a, thereby closing the passage. A second actuation passage 124b formed in the third housing section 111c and the fourth housing section 111d may be in fluid communication with the actuation chamber and the middle portion of the atmospheric chamber 116m. The second rupture disk 119b can be disposed in the second actuation passage 124b, thereby closing the passage.
[00113] The solenoids 117a,b and the spikes 118a,b can be arranged in the actuation chamber. A gas passage 124c formed in the sixth housing section 111f can provide fluid communication between the gas chamber and the actuation chamber. A seal may be disposed at an interface between the fourth housing section 111d and the mandrel 115. A lower balance piston 122b may be disposed in the gas chamber and may divide the chamber into an upper portion and a lower portion. A portal formed through a wall of the seventh housing section 111g can provide fluid communication between the lower portion of the gas chamber and the annular crown 48. The upper portion may be filled with an inert gas such as nitrogen 125. Nitrogen 125 can be compressed to serve as a fluid power source for the actuator.
[00114] Each of the cam plugs 110t,b may include a respective body 126t,b, a mandrel 127t,b, a fastener such as a gripper 128t,b, a release valve 129t,b, and a valve seal. overhang 130t,b. Each of: body 126t,b, chuck 128t,b and release valve 129t,b can be made from one of the drilling materials. Each of the plug bodies 126t,b can be connected to a respective plug mandrel 128t,b, such as via threaded couplings.
[00115] Each of the lip seals 130t,b can be connected to the respective plug body 126t,b as if by being molded therein. Each of the lip seals 130t,b can include a plurality of directional fins and can be made of an elastomer or an elastomeric copolymer. An outside diameter of each of the fins may correspond to an inside diameter of the box 25, such as being slightly larger than the inside diameter of the box. Each of the lip seals 130t,b may be oriented to sealingly engage the housing 25 in response to an annular ring pressure above the lip seal being greater than the ring ring pressure under the lip seal.
[00116] Each of the release valves 129t,b may include a portion of the respective plug chuck 127t,b forming a valve body and a valve member, such as a hypercarrier, pivotally connected to the valve body and biased in one direction to the closed position, such as by means of a torsion spring. Each of the hypersupports can be positioned above the respective valve body to serve as a piston in the closed position for releasing and operating the respective plug 110t,b. In the locked position, launcher chuck 115 may extend through upper cap 110t and lower cap 110b, thereby bracing the open hypersupports. The upper hypercarrier may be solid and the lower hypercarrier may have a hole formed through it closed by means of a rupture disk.
[00117] Each of the tweezers 128t,b may have a lower base portion and fingers extending from the base portion to an end thereof. Each of the tongs can be connected to an upper end of the respective plug chuck 127t,b, such as through threaded couplings. Each of the tweezers 128t,b may be radially movable between an engaged position (shown) and an disengaged position through interaction with the launch chuck 115. Each of the tweezers fingers may have a fin formed on an upper end thereof . In the engaged position, the upper fins of the collet may mate with a complementary groove 113t formed in an inner surface of the seventh housing portion 111h, thereby loosely connecting the upper plug 110t to the housing 111. In the engaged position, the lower fins of the collet may mate with a complementary groove 113b formed in an inner surface of the upper plug chuck 127t, thereby loosely connecting the lower plug 110b with the upper plug 110t.
[00118] The fingers of each of the 128 t,b tweezers can meet cantilevered from the base of the tweezer and have a stiffening forcing the fins in one direction to the engaged position. The fins of each collet 128 t,b may be chamfered to interact with a chamfer of the respective groove 113t,b to radially push the respective fingers into the disengaged position in response to a downwardly directed force exerted on the respective mandrel of 127 t,b buffer by means of fluid pressure after closing the respective hypersupports. An outer diameter of the launch chuck 115 may correspond to an inner diameter of the fins of each of the tongs 128 t,b in the engaged position, thus preventing retraction of the fingers of each of the tongs.
[00119] The lower plug body 126b may have a torsion coupling formed on a lower end thereof. The twist coupling can be a self-oriented castellation to match a complementary profile of the floating collar 15c.
[00120] Alternatively, the seventh housing section 111h may be longitudinally connected to the sixth housing section 111g and free to rotate with respect thereto such that the shoulder plugs are not rotated with respect to the casing string during connection of the casing installation set. Alternatively, the upper plug body may have a twist coupling formed on a lower end thereof and the lower plug body may have a twist coupling formed on an upper end thereof. Alternatively, balance piston 122u and oil 123 can be omitted and nitrogen 125 used to dampen motion and operate 120u,b actuating pistons. Alternatively, balance piston 122b and nitrogen 125 can be omitted and the hydrostatic head in annular ring 48 used to operate the actuating pistons. Alternatively, balance piston 122b and nitrogen 125 can be omitted and oil 123 used to dampen movement and direct the actuating pistons. Alternatively, a fuse plug and heating element can be used to close each of the actuation passages and the respective passage can be opened by operating the heating element to melt the fuse cap. Alternatively, a solenoid actuated valve can be used to close each of the actuation passages and the respective passage can be opened by operating the solenoid valve actuator.
[00121] Figures 7A - 7D illustrate the operation of an upper portion of the plug release system 110. Figures 8A - 8D illustrate the operation of a lower portion of the plug release system 110. Once the casing column 15 has been advanced in the well hole 24 by means of the operating column 109 to a desired installation depth, the conditioner 80 can be circulated by means of the cement pump 13 through the open valve 41 (valve 106 closed), by the upper motor 5, by operating column 109 and casing column 15 to prepare for pumping the cement slurry 82. Spherical launcher 7b can then be operated and conditioner 80 can propel ball 43b through upper motor 5 and down from operating column 9 to lower detent 177. Once ball 43b engages in detent seat, pumping can continue to increase pressure in the casing installation assembly orifice nt (LDA)/ actuation chamber 59.
[00122] Once a first limit pressure is reached, a piston of the coating suspension element 15h can adjust the slips thereof against the box 25. The pumping of the conditioner 80 can continue until a second limit pressure is reached and the operating tool 53 is unlocked. Pumping may continue until a third limit pressure is reached and the detent seat is released from the detent body. The weight can then be adjusted down on casing string 15 and operating string 109 rotated, thereby releasing casing string 15 from adjustment tool 53. An upper portion of operating string 109 can be lifted and then lowered to confirm release of operating tool 53. Operating column 109 and casing column 15 can then be rotated 8 from the surface by means of an upper motor 5 and rotation can continue during the cementing operation. The first tag launcher 44a can then be operated to launch the first radio frequency identification (RFID) tag 45a into the conditioner 80. The cement slurry 81 can then be pumped from the mixer 42, through the cement line 114, valve 41, upper mud line segment 139h, and upper engine 5 in operating column 109 via cement pump 13.
Just before the desired amount of cement slurry 81 has been pumped, the second tag launcher 44b can be operated to drop the second radio frequency identification (RFID) tag 45b onto the cement slurry 81. Once the amount of cement slurry 81 has been pumped, ingot 143 can be released from launcher 7d via operation of the plug launcher actuator. Chiseling fluid 82 can be pumped via cement pump 13 to drive ingot 143 through upper motor 5 and operating column 109. The pumping chisel fluid 82 can then be transferred to slurry pump 34 via closing valve 41 and opening valve 106.
[00124] Ingot 143, cement slurry 81 and radio frequency identification (RFID) tags 45a,b can be operated through the orifice of the operating column by means of chisel fluid 82 until a first tag 45a reaches antenna 64. First tag 45a may transmit a first command signal to antenna 64 as the tag passes therethrough. The MCU can receive the first command signal from the first tag 45a and can operate the actuator controller 62m to energize the first solenoid 117a thereby operating the first pin 118a on the first rupture disk 119a. Once the first rupture disk 119a has been pierced, nitrogen from the gas chamber can operate the lower actuating piston 120b in an upward direction in a direction to the shoulder of the housing 112b. Lower actuating piston 120b can push upper actuating piston 120u and launcher chuck 115 in an upward direction in the middle portion of atmospheric chamber 116b. Once the stroke in an upward direction has been terminated whereby the lower actuating piston 120 is seated against the shoulder of the housing 112b, the launcher chuck 115 may be free/unobstructed from the lower launch valve 129b and the lower clamp 128b. The lower hypersustainer may close and pressure may increase thereon until the lower plug 110b is released from the upper plug 110t.
[00125] The released lower cap 110b can then be propelled through the casing string 15 via the fluid train. Ingot 143 can engage in upper detent 108 and lower plug can meet docking collar 15c. The continuous pumping of the chiseling fluid 82 can exert pressure on the docked lower plug 110b until the rupture disk thereof is ruptured, thereby opening the lower hypersupport orifice such that the cement slurry 81 can flow through. of the hole and in the annular crown 48. Contemporaneously, the second tag 45b can reach the antenna 64 and transmit a second command signal to the antenna 64 as the tag passes therethrough.
[00126] The MCU can receive the second command signal from the second tag 45b and can energize the second solenoid 117b, thereby operating the second spike 118b on the second rupture disk 119b. Once the second rupture disk 119b has been pierced, nitrogen 125 from the gas chamber can operate the top actuating piston 120u in an upward direction in a direction to shoulder 112a. Once the upward one-way stroke is over, the launcher chuck 115 can be freed/unobstructed from the 129u top release valve and the 128u top collet. The upper hypersustainer may close and pressure may build up therein until the upper plug 110u is released from the seventh housing section 111h.
[00127] Once released, the upper cap 110t can be operated through the casing hole via the chisel fluid 82, thus operating the cement slurry 81 through the mooring collar 15c and the flare shoe 15s in the annular crown 48 The pumping of chisel fluid 82 may continue until the upper plug 110t engages over the lower plug 110b in the floating collar 15c. Once the upper plug 110t has docked, the pumping of chisel fluid 82 can be stopped and the upper portion of the operating column raised until the adjustment tool 52 exits the well polished (PBR) receptacle 15r. The upper portion of the operating column d may then be lowered until the adjustment tool 52 engages over an upper portion of the well-polished receptacle (PBR) 15r. The weight can then be exerted on the well polished receptacle (PBR) 15r to adjust the packer 15p. Once the packer has been adjusted, rotation 8 of operating column 109 can be stopped. The liner installation assembly (LDA) 109d can then be lifted/lifted from the liner column 15 and the chisel fluid 83 circulated to wash off excess cement slurry 81. The operating column 9 can then be retrieved to the mobile offshore drilling unit (MODU) 1m.
[00128] Alternatively, the ingot can be omitted and the chisel fluid pumped directly behind the cement slurry or a gel plug can be used instead of the ingot. Alternatively, the lower buffer can be omitted. Alternatively, one or more radio frequency identification (RFID) tags may be embedded in the ingot, such as the tail, thereby obviating the need for a second tag launcher 44. Alternatively, the first tag and second tag may have identical command signals and the MCU can ignore the command signals for a pre-determined period of time after receiving the first command signal. Alternatively, the electronics assembly may include a proximity sensor in place of the antenna and the dart may have targets embedded in the first fin stack for detection by means of the proximity sensor.
[00129] Alternatively, any of the plug release systems 60, 110 can be used for installing a stand-up column rather than installing the casing column 15. Alternatively, an expandable casing suspension element can be used when instead of the suspension element and casing wrapper.
[00130] Although the above description has been directed to embodiments of the present invention, other and additional embodiments of the invention can be envisioned without departing from the basic scope of the present invention and the scope of the invention is determined by the appended claims.

权利要求:
Claims (19)
[0001]
1. Plug release system (60) for cementing a tubular column (15) in a wellbore comprising: a shoulder plug (60b); a tubular housing (61); characterized by a locking member (66) for releasably connecting the shoulder plug (60b) to the housing and comprising: a fastener (71) which is engaged with one of the shoulder plugs and the housing; a latch (70) movable between a locked position and an unlocked position, the latch keeping the catch engaged in the locked position; and, an actuator (69) connected to the lock and operable to at least move the lock from the locked position to the unlocked position; and, an electronic assembly (62) disposed in the housing and in communication with the actuator to operate the actuator in response to receipt of a command signal.
[0002]
2. Plug release system, according to claim 1, characterized in that the shoulder plug (60b) has a shaped hole to receive a release plug (43d).
[0003]
3. Buffer release system, according to claim 1 or 2, characterized in that the electronics assembly (62) is configured to wait a pre-established period of time after receiving the command signal before releasing the buffer of rebound (60b).
[0004]
A tampon release system, according to claim 1, characterized in that it further comprises an antenna (64) arranged in the housing and in communication with an orifice of the tampon release system (60) for receiving the command signal.
[0005]
5. Plug release system, according to claim 1, characterized in that: a clamp is a clamp (machine or automatic lathe) (71); the actuator is a solenoid (69s), and the lock is a sleeve (70) sliding along the caliper.
[0006]
6. Plug release system, according to claim 1, characterized in that the shoulder plug (60b) comprises an anchor (76) for engaging a mooring collar (15c) of the tubular column.
[0007]
7. Plug release system according to claim 1, characterized in that the shoulder plug (60b) comprises a body (72) and a seat (77) loosely connected to the body to receive an adjustment plug (43b).
[0008]
8. Plug release system, according to claim 1, characterized in that the rebound plug (60b) comprises: a body (72); a mandrel (73) having a shaped hole and a tapered cone formed on an outer surface thereof; one or more shear fasteners (78) that releasably connect the mandrel to the body; a spike (74) connected to the body and having a tapered cone formed on an inner surface thereof; wherein the chuck is operable to strike the spike in response to failure of the shear fasteners.
[0009]
9. Plug release system, according to claim 1, characterized in that: the shoulder plug (60b) comprises a valve member; the latch is further operable to drive the open valve member into the locked position, and, the valve member is operable to close in response to the latch moving to the unlocked position.
[0010]
10. Liner deployment assembly (LDA) assembly (9d) for suspending a casing column (15) from a cemented tubular column in a wellbore, characterized by comprising: an adjustment tool (52) operable to fit a casing string packer; an operating tool (53) operable to longitudinally and torsionally connect the casing string to an upper portion of the casing installation assembly (LDA); a spike (54) connected to the operating tool; a condenser assembly (55) for sealing against an inner surface of the casing string and an outer surface of the spike for connecting the casing string to a lower portion of the casing installation assembly (LDA); a release member (57) connected to the spike for disconnecting the compaction assembly from the aligner column; a spacer (56) connected to the consolidation assembly; and the plug release system (60) as defined in claim 1 connected to the spacer.
[0011]
11. Method for suspending an inner tubular column (15) from an outer tubular column (25) cemented in a well hole characterized by comprising: traversing the inner tube column and an installation set (9d) in a drilled well using an installation column (9), in which the installation assembly comprises a plug release system (60) as defined in any one of claims 1 to 9; pumping a cement slurry (81) into the installation column; directing the cement slurry through the installation column and the installation set while sending a command signal to a plug release system (60) of the installation set, in which the plug release system releases a bounce plug (60b) in response to receiving a command signal; and wherein the command signal is sent by casting a wireless identification tag (45) onto the cement slurry (81).
[0012]
12. Method according to claim 11, characterized in that: the cement slurry (81) is directed by pumping a release plug (43d) behind the cement slurry; the release plug engages the thrust plug (60b), and the plug release system releases the thrust plug after engagement of the release plug with the thrust plug (60b).
[0013]
13. Method according to claim 12, characterized in that the command signal is sent through a wireless identification tag (45) embedded in the release buffer.
[0014]
14. Method according to claim 12, characterized in that the engaged release plug and the rebound plug direct the cement slurry through the inner tubular column and into an annular crown (48) formed between the inner tubular column and the well hole.
[0015]
15. Method according to claim 13, characterized in that: an upper end of the installation column (9) is connected to an upper engine (5), and the cement slurry is pumped through the upper engine.
[0016]
16. Method according to claim 15, characterized in that the cement slurry is directed by pumping an ingot (metal) from the pipe (143) behind the cement slurry.
[0017]
The method of claim 16, further comprising fitting a hanger (15h) of the inner tubular column prior to pumping the cement slurry (81).
[0018]
18. Method according to claim 17, characterized in that the hanger (15h) is adjusted by pumping an adjustment cap (43b) through the installation column to a seat (77) of the cap release system and pressing a chamber formed between a condenser assembly (55) of the installation assembly and the shoulder plug.
[0019]
The method of claim 17, further comprising fitting a packer (15p) of the inner tubular column after pumping the cement slurry (81).

类似技术:

---

公开号 | 公开日 | 专利标题

---

BR102014028648B1|2021-08-31|Plug release system, liner installation set and method for suspending an inner tubular column from an outer tubular column

---

BR102014028665B1|2021-06-22|adjustment tool, installation set, system and method for suspending a tubular column from a casing column

---

US10422216B2|2019-09-24|Telemetry operated running tool

---

US10246965B2|2019-04-02|Telemetry operated ball release system

---

US9911016B2|2018-03-06|Radio frequency identification tag delivery system

---

BR102014028614B1|2021-11-23|BALL RELEASE SYSTEM, COATING INSTALLATION ASSEMBLY AND METHOD FOR SUSPENDING AN INTERNAL TUBULAR COLUMN FROM AN EXTERNAL TUBULAR COLUMN

---

BR102014028651B1|2021-11-03|OPERATING TOOL FOR INSTALLING A PIPE COLUMN IN A WELL HOLE, LINING INSTALLATION ASSEMBLY AND METHOD FOR SUSPENDING AN INNER PIPE COLUMN

同族专利:

---

公开号 | 公开日

---

AU2014259559B2|2016-07-28|

---

US9523258B2|2016-12-20|

---

CA2869837A1|2015-05-18|

---

US20150136395A1|2015-05-21|

---

AU2016250376B2|2018-09-13|

---

US10221638B2|2019-03-05|

---

NO2967216T3|2018-07-14|

---

CA2869837C|2017-09-19|

---

AU2016250376A1|2016-11-17|

---

US20170067304A1|2017-03-09|

---

BR102014028648A2|2015-09-08|

---

AU2014259559A1|2015-06-04|

---

EP2873801B1|2018-02-21|

---

EP2873801A1|2015-05-20|

引用文献:

---

公开号 | 申请日 | 公开日 | 申请人 | 专利标题

---

---

US2693859A|1949-05-23|1954-11-09|B And W Inc|Liner hanger|

---

US4405017A|1981-10-02|1983-09-20|Baker International Corporation|Positive locating expendable plug|

---

US4583593A|1985-02-20|1986-04-22|Halliburton Company|Hydraulically activated liner setting device|

---

US4893678A|1988-06-08|1990-01-16|Tam International|Multiple-set downhole tool and method|

---

US5174375A|1989-10-10|1992-12-29|Union Oil Company Of California|Hydraulic release system|

---

US5086844A|1989-10-10|1992-02-11|Union Oil Company Of California|Hydraulic release oil tool|

---

US5170847A|1989-10-10|1992-12-15|Union Oil Company Of California|Hydraulic release oil tool|

---

US5086843A|1990-09-27|1992-02-11|Union Oil Company Of California|Oil tool release joint|

---

US5146992A|1991-08-08|1992-09-15|Baker Hughes Incorporated|Pump-through pressure seat for use in a wellbore|

---

US5360069A|1993-03-30|1994-11-01|Baker Hughes Incorporated|Failsafe liner installation assembly and method|

---

US5435390A|1993-05-27|1995-07-25|Baker Hughes Incorporated|Remote control for a plug-dropping head|

---

US5560426A|1995-03-27|1996-10-01|Baker Hughes Incorporated|Downhole tool actuating mechanism|

---

US6056053A|1995-04-26|2000-05-02|Weatherford/Lamb, Inc.|Cementing systems for wellbores|

---

US5553667A|1995-04-26|1996-09-10|Weatherford U.S., Inc.|Cementing system|

---

GB9525044D0|1995-12-07|1996-02-07|Nodeco Ltd|Plugs for downhole tools|

---

CA2242307A1|1996-01-04|1997-07-17|Weatherford/Lamb, Inc.|Release mechanism|

---

GB9600103D0|1996-01-04|1996-03-06|Nodeco Ltd|Improvements to offshore drilling apparatus|

---

GB2350141B|1996-06-20|2001-01-10|Baker Hughes Inc|Remote control for a plug-dropping head|

---

US5833002A|1996-06-20|1998-11-10|Baker Hughes Incorporated|Remote control plug-dropping head|

---

US5954133A|1996-09-12|1999-09-21|Halliburton Energy Services, Inc.|Methods of completing wells utilizing wellbore equipment positioning apparatus|

---

NO303742B1|1996-12-06|1998-08-24|Nodeco As|Device for insertion of one or more scratch plugs in an extension year|

---

GB9721537D0|1997-10-11|1997-12-10|Weatherford Lamb|An apparatus and a method for launching plugs|

---

GB9723581D0|1997-11-07|1998-01-07|Weatherford Lamb|Plug for use in wellbore operations and apparatus for launching said plug|

---

US6536524B1|1999-04-27|2003-03-25|Marathon Oil Company|Method and system for performing a casing conveyed perforating process and other operations in wells|

---

GB2341404A|1998-09-12|2000-03-15|Weatherford Lamb|Plug and plug set for use in a wellbore|

---

NO315131B1|1998-11-12|2003-07-14|Baker Hughes Inc|Well setting tool for activating a well tool, as well as method for setting up a well tool|

---

US6318472B1|1999-05-28|2001-11-20|Halliburton Energy Services, Inc.|Hydraulic set liner hanger setting mechanism and method|

---

US6241018B1|1999-07-07|2001-06-05|Weatherford/Lamb, Inc.|Hydraulic running tool|

---

US6597175B1|1999-09-07|2003-07-22|Halliburton Energy Services, Inc.|Electromagnetic detector apparatus and method for oil or gas well, and circuit-bearing displaceable object to be detected therein|

---

US6527057B2|2001-03-27|2003-03-04|Baker Hughes Incorporated|Wiper plug delivery apparatus|

---

US20030230405A1|2001-04-09|2003-12-18|Allamon Jerry P.|System for running tubular members|

---

US6634428B2|2001-05-03|2003-10-21|Baker Hughes Incorporated|Delayed opening ball seat|

---

US6799638B2|2002-03-01|2004-10-05|Halliburton Energy Services, Inc.|Method, apparatus and system for selective release of cementing plugs|

---

US6802373B2|2002-04-10|2004-10-12|Bj Services Company|Apparatus and method of detecting interfaces between well fluids|

---

US6789619B2|2002-04-10|2004-09-14|Bj Services Company|Apparatus and method for detecting the launch of a device in oilfield applications|

---

US6866100B2|2002-08-23|2005-03-15|Weatherford/Lamb, Inc.|Mechanically opened ball seat and expandable ball seat|

---

US7219730B2|2002-09-27|2007-05-22|Weatherford/Lamb, Inc.|Smart cementing systems|

---

US6848511B1|2002-12-06|2005-02-01|Weatherford/Lamb, Inc.|Plug and ball seat assembly|

---

US7128154B2|2003-01-30|2006-10-31|Weatherford/Lamb, Inc.|Single-direction cementing plug|

---

US7441606B2|2003-05-01|2008-10-28|Weatherford/Lamb, Inc.|Expandable fluted liner hanger and packer system|

---

US6962206B2|2003-05-15|2005-11-08|Weatherford/Lamb, Inc.|Packer with metal sealing element|

---

WO2004104370A1|2003-05-20|2004-12-02|Weatherford/Lamb, Inc.|Hydraulic setting tool for liner hanger|

---

US7252152B2|2003-06-18|2007-08-07|Weatherford/Lamb, Inc.|Methods and apparatus for actuating a downhole tool|

---

US6966368B2|2003-06-24|2005-11-22|Baker Hughes Incorporated|Plug and expel flow control device|

---

US7182135B2|2003-11-14|2007-02-27|Halliburton Energy Services, Inc.|Plug systems and methods for using plugs in subterranean formations|

---

US7063148B2|2003-12-01|2006-06-20|Marathon Oil Company|Method and system for transmitting signals through a metal tubular|

---

GB2435657B|2005-03-15|2009-06-03|Schlumberger Holdings|Technique for use in wells|

---

US7426964B2|2004-12-22|2008-09-23|Baker Hughes Incorporated|Release mechanism for downhole tool|

---

US7766088B2|2005-07-07|2010-08-03|Baker Hughes Incorporated|System and method for actuating wellbore tools|

---

CA2661342C|2006-08-21|2013-02-05|Weatherford/Lamb, Inc.|Method for logging after drilling|

---

US7537060B2|2007-03-19|2009-05-26|Baker Hughes Incorporated|Coupler retained liner hanger mechanism and methods of setting a hanger inside a wellbore|

---

US8651174B2|2007-05-16|2014-02-18|Gulfstream Services, Inc.|Method and apparatus for dropping a pump down plug or ball|

---

US7845400B2|2008-01-28|2010-12-07|Baker Hughes Incorporated|Launching tool for releasing cement plugs downhole|

---

NO331150B2|2008-03-06|2011-10-24|Tco As|Device for removing plug|

---

US8276665B2|2008-04-03|2012-10-02|Halliburton Energy Services Inc.|Plug release apparatus|

---

WO2009137537A2|2008-05-05|2009-11-12|Weatherford/Lamb, Inc.|Signal operated tools for milling, drilling, and/or fishing operations|

---

EP2291576B1|2008-05-05|2019-02-20|Weatherford Technology Holdings, LLC|Tools and methods for hanging and/or expanding liner strings|

---

US20100051264A1|2008-08-29|2010-03-04|Baker Hughes Incorporated|Method and system for monitoring downhole completion operations|

---

NO330907B1|2008-10-23|2011-08-15|Peak Well Solutions As|Cementing head with wireless remote control|

---

US8307898B2|2008-12-23|2012-11-13|Bp Corporation North America Inc.|Method and apparatus for cementing a liner in a borehole using a tubular member having an obstruction|

---

WO2010085617A1|2009-01-22|2010-07-29|Blackhawk Specialty Tools, Llc|Method and apparatus for performing cementing operations|

---

NO333731B1|2009-04-01|2013-09-02|I Tec As|hanger|

---

US8505639B2|2010-04-02|2013-08-13|Weatherford/Lamb, Inc.|Indexing sleeve for single-trip, multi-stage fracing|

---

US8978750B2|2010-09-20|2015-03-17|Weatherford Technology Holdings, Llc|Signal operated isolation valve|

---

US20140008083A1|2010-11-12|2014-01-09|Lev Ring|Remote Operation of Setting Tools for Liner Hangers|

---

WO2012065123A2|2010-11-12|2012-05-18|Weatherford/Lamb, Inc.|Remote operation of cementing head|

---

US9004179B2|2011-03-02|2015-04-14|Team Oil Tools, Lp|Multi-actuating seat and drop element|

---

US9121232B2|2011-03-14|2015-09-01|Smith International, Inc.|Hydro-mechanical downhole tool|

---

US8479808B2|2011-06-01|2013-07-09|Baker Hughes Incorporated|Downhole tools having radially expandable seat member|

---

US9574414B2|2011-07-29|2017-02-21|Packers Plus Energy Services Inc.|Wellbore tool with indexing mechanism and method|

---

WO2014014959A1|2012-07-16|2014-01-23|Tempress Technologies, Inc.|Extended reach placement of wellbore completions|

---

US9068414B2|2012-09-14|2015-06-30|Baker Hughes Incorporated|Multi-piston hydrostatic setting tool with locking feature and a single lock for multiple pistons|

---

US9068413B2|2012-09-14|2015-06-30|Baker Hughes Incorporated|Multi-piston hydrostatic setting tool with locking feature and pressure balanced pistons|

---

BR112015009373B1|2012-10-26|2021-05-04|Halliburton Energy Services, Inc.|downhole tool kit for use in a wellbore and method for performing an oilfield operation in an underground wellbore|

---

US20140116713A1|2012-10-26|2014-05-01|Weatherford/Lamb, Inc.|RFID Actuated Gravel Pack Valves|

---

US9080404B2|2012-11-30|2015-07-14|Dril-Quip, Inc.|Method and system for interventionless hydraulic setting of equipment when performing subterranean operations|

---

US9500071B2|2012-12-03|2016-11-22|Halliburton Energy Services, Inc.|Extendable orienting tool for use in wells|

---

CA2895809C|2013-01-14|2017-10-03|Weatherford Technology Holdings, Llc|Surge immune liner setting tool|

---

US9284817B2|2013-03-14|2016-03-15|Halliburton Energy Services, Inc.|Dual magnetic sensor actuation assembly|

---

US10087725B2|2013-04-11|2018-10-02|Weatherford Technology Holdings, Llc|Telemetry operated tools for cementing a liner string|

---

US9523258B2|2013-11-18|2016-12-20|Weatherford Technology Holdings, Llc|Telemetry operated cementing plug release system|

---

US9777569B2|2013-11-18|2017-10-03|Weatherford Technology Holdings, Llc|Running tool|

---

US9528346B2|2013-11-18|2016-12-27|Weatherford Technology Holdings, Llc|Telemetry operated ball release system|

---

US9428998B2|2013-11-18|2016-08-30|Weatherford Technology Holdings, Llc|Telemetry operated setting tool|US9528346B2|2013-11-18|2016-12-27|Weatherford Technology Holdings, Llc|Telemetry operated ball release system|

---

US9777569B2|2013-11-18|2017-10-03|Weatherford Technology Holdings, Llc|Running tool|

---

US9523258B2|2013-11-18|2016-12-20|Weatherford Technology Holdings, Llc|Telemetry operated cementing plug release system|

---

US9428998B2|2013-11-18|2016-08-30|Weatherford Technology Holdings, Llc|Telemetry operated setting tool|

---

US9587466B2|2014-09-16|2017-03-07|Wild Well Control, Inc.|Cementing system for riserless abandonment operation|

---

CA2975090C|2015-03-26|2018-12-04|Halliburton Energy Services, Inc.|Multifunction downhole plug|

---

US9911016B2|2015-05-14|2018-03-06|Weatherford Technology Holdings, Llc|Radio frequency identification tag delivery system|

---

WO2017173522A1|2016-04-06|2017-10-12|Noetic Technologies Inc.|Apparatus for launching wiper plugs|

---

FR3061994A1|2017-01-19|2018-07-20|Tywaves|ANTENNA AND ITS USES|

---

WO2020091758A1|2018-10-31|2020-05-07|Halliburton Energy Services, Inc.|Integrated debris catcher and plug system|

---

US11098557B2|2019-09-06|2021-08-24|Baker Hughes Oilfield Operations Llc|Liner wiper plug with rupture disk for wet shoe|

---

US20210310338A1|2020-04-01|2021-10-07|Weatherford Technology Holdings, Llc|Running tool for a liner string|

法律状态:
2015-09-08| B03A| Publication of a patent application or of a certificate of addition of invention [chapter 3.1 patent gazette]|

---

2018-11-06| B06F| Objections, documents and/or translations needed after an examination request according [chapter 6.6 patent gazette]|

---

2020-05-05| B06U| Preliminary requirement: requests with searches performed by other patent offices: procedure suspended [chapter 6.21 patent gazette]|

---

2021-04-06| B25A| Requested transfer of rights approved|Owner name: WEATHERFORD TECHNOLOGY HOLDINGS, LLC (US) |

---

2021-07-27| B09A| Decision: intention to grant [chapter 9.1 patent gazette]|

---

2021-08-31| B16A| Patent or certificate of addition of invention granted [chapter 16.1 patent gazette]|Free format text: PRAZO DE VALIDADE: 20 (VINTE) ANOS CONTADOS A PARTIR DE 17/11/2014, OBSERVADAS AS CONDICOES LEGAIS. |

优先权:

---

申请号 | 申请日 | 专利标题

---

US14/083,021|2013-11-18|

---

US14/083,021|US9523258B2|2013-11-18|2013-11-18|Telemetry operated cementing plug release system|

---