A large-diameter removable hydrostatic packer and downhole operation system

Abstract

The present application relates to the technical fields of oil and gas well downhole tools, and discloses a large-diameter retrievable hydrostatic packer, comprising: a center pipe assembly; a sealing assembly arranged on the center pipe assembly and used for radially deforming under the drive of axial force to seal the annular space between the center pipe assembly and the well wall; an anchoring assembly arranged on the center pipe assembly and used for radially displacing and fixing the well wall under the drive of axial force; and a composite hydraulic drive component connected with the sealing assembly and the anchoring assembly respectively and used for generating the axial pressure through the differential pressure of downhole fluid to drive the sealing assembly and the anchoring assembly and for limiting the displacement direction of the sealing assembly and the anchoring assembly. The large-diameter retrievable hydrostatic packer meets the demand of downhole large-flow operation and is convenient for smoothly pulling out the tool after the completion of the later operation, thereby realizing the repeated use of the wellbore.

Description

Technical Field

[0001] This invention relates to the field of downhole tools technology for oil and gas wells, specifically to a large-diameter removable hydrostatic packer and downhole operation system. Background Technology

[0002] In the development and completion of offshore oil and gas fields, packers are key downhole tools for achieving downhole formation separation, well testing, and workover operations. To adapt to formation environments at different depths and achieve effective annular sealing, existing packers typically rely on the physical movement of the surface operating string (such as lifting, lowering, or rotating) to transmit mechanical force, or on pressurizing the inside of the string after dropping a sealing ball from the wellhead downhole to achieve tool anchoring and sealing within the casing.

[0003] However, with the increasing number of complex well operations (such as highly deviated wells and deep wells with extended reach), under harsh well conditions, the intense friction of long-distance tubing can cause the mechanical force applied from the surface to be severely attenuated or even completely dissipated when it is transmitted to the bottom of the well. The traditional drive method that relies on throwing foreign objects to build pressure is not only time-consuming, but is also easily affected by sand at the bottom of the well or scale on the tubing wall, which can damage the sealing surface and prevent pressure from being built up, making it difficult to guarantee the absolute reliability of well sealing operations. Summary of the Invention

[0004] The purpose of this invention is to solve the problem of insufficient wellbore sealing reliability, and to propose a large-diameter removable hydrostatic packer and downhole operation system.

[0005] In a first aspect, embodiments of the present invention provide a large-diameter removable hydrostatic packer, comprising: Central tube assembly; A sealing assembly, disposed on the central tube assembly, is used to deform radially under axial force to seal the annular space between the central tube assembly and the well wall; An anchoring assembly, disposed on the central tube assembly, is used to radially displace and fix the well wall under axial force; A composite hydraulic drive component, connected to the sealing assembly and the anchoring assembly respectively, is used to generate the axial pressure through downhole fluid pressure differential to drive the sealing assembly and the anchoring assembly, and to limit the displacement direction of the sealing assembly and the anchoring assembly.

[0006] In one embodiment, it further includes: A locking ring sleeve is fitted onto the outside of the central tube assembly; The connecting sleeve is slidably fitted onto the central tube assembly and located inside the locking ring sleeve; The second shear pin has its two ends connected to the locking ring sleeve and the connecting sleeve. A sliding ring is slidably sleeved on the central tube assembly and connected to the connecting sleeve, and the sliding ring abuts against the anchoring assembly.

[0007] In one embodiment, the composite hydraulic drive component includes a hydrostatic actuation assembly, the hydrostatic actuation assembly comprising: The lower connector is fixedly sleeved onto the central tube assembly; The lower piston sleeve is slidably sleeved on the central tube assembly. The inner wall of the lower piston sleeve, the lower connector, and the outer wall of the central tube assembly form a hydraulic chamber. The lower piston sleeve is provided with a limiting clearance groove. A rupture disc is disposed through the lower piston sleeve and communicates with the hydraulic chamber; The first shear pin has both ends that pass through and connect the lower connector and the lower piston sleeve; The transmission assembly is mounted on the central tube assembly and abuts against the lower piston sleeve.

[0008] In one embodiment, the transmission assembly includes: The upper piston sleeve is slidably fitted onto the central tube assembly; A limiting block is disposed through the upper piston sleeve, the limiting block abuts against the central tube assembly, and the limiting block is adapted to the limiting clearance groove; A hydraulic piston sleeve is slidably mounted on the central tube assembly and connected to the upper piston sleeve and the locking ring sleeve; A lower locking ring is connected to the hydraulic piston sleeve. The lower locking ring and the central tube assembly form a one-way ratchet engagement to limit the reverse axial displacement of the hydraulic piston sleeve.

[0009] In one embodiment, the composite hydraulic drive component further includes a backup hydraulic actuation assembly, the backup hydraulic actuation assembly comprising: A pressure-transmitting hole is radially penetrated and formed on the central tube assembly; A spare piston is slidably sleeved on the central tube assembly and located on the external communication path of the pressure transmission hole; the spare piston is connected to the connecting sleeve. A locking ring is connected inside the locking ring sleeve, and the locking ring and the outer wall of the connecting sleeve form a one-way stop fit.

[0010] In one embodiment, the anchoring component includes: An axially limiting semi-ring is engaged in a pre-set annular groove on the outer wall of the central tube assembly; A pair of cones, including an upper cone and a lower cone, are slidably fitted onto the central tube assembly at an interval facing each other; The third shear pin connects the axial limiting semi-ring and the lower cone through both ends; A pair of slips, including an upper slip and a lower slip, are slidably fitted onto the central tube assembly. The slips slide in conjunction with the cone. Under axial force, the cone drives the slips to expand radially.

[0011] In one embodiment, it further includes: An upper guide ring is sleeved on the central tube assembly and abuts against the upper cone, forming a receiving cavity between the upper guide ring and the upper cone; The fourth shear pin connects the upper guide ring and the central tube assembly through both ends; A C-shaped limiting ring is disposed within the receiving cavity. The C-shaped limiting ring is used to abut against the first step portion disposed on the outer wall of the central tube assembly during the displacement of the upper guide ring and the upper cone.

[0012] In one embodiment, the sealing assembly is disposed on the transmission path between the upper guide ring and the lower cone, and the sealing assembly includes: The lower guide ring is slidably sleeved on the central tube assembly and connected to the lower cone. The elastic rubber sleeve is slidably sleeved on the central tube assembly and located between the upper guide ring and the lower guide ring.

[0013] In one embodiment, the system further includes an unsealing component, the unsealing component comprising: An upper clamping seat is fitted onto the central tube assembly. The upper clamping seat has a mounting notch, and the upper clamping slip engages with the mounting notch. The fifth shear pin connects the upper locking seat and the central tube assembly through both ends; A retaining ring is slidably sleeved on the central tube assembly, and the retaining ring is used to abut against the second step portion protruding from the outer wall of the central tube assembly; An upper moving ring is connected to the central tube assembly, and a retaining ring is located between the upper moving ring and the upper clamp seat; A support ring is connected to the central tube assembly and is embedded inside the connecting sleeve.

[0014] Secondly, embodiments of the present invention provide a downhole operation system, comprising: Working tubing; A large-diameter removable hydrostatic packer is connected in series in the working string, and the internal flow channel of the working string is connected to the central tube assembly of the large-diameter removable hydrostatic packer.

[0015] Compared with the prior art, the technical solution of this application has the following beneficial technical effects: This packer directly utilizes the hydrostatic pressure difference of the downhole fluid as its power source, generating the axial pressure required to drive the sealing and anchoring components without the need for surface-based mechanical force transmission. Power transmission is unaffected by tubing length, wellbore inclination angle, or tubing friction loss, enabling it to stably output sufficient driving force even in harsh well conditions such as ultra-deep and highly inclined wells, ensuring reliable execution of anchoring and sealing actions. Furthermore, the composite hydraulic drive component possesses dual functions of driving and displacement limiting, precisely controlling the displacement direction of the sealing and anchoring components. This ensures uniform radial deformation of the sealing components, tight annular sealing, and precise radial displacement of the anchoring components, resulting in stable engagement with the wellbore. This further enhances the overall performance of the packer. The large-diameter, removable integrated structural design not only meets the needs of high-flow-rate downhole operations but also facilitates easy tool retrieval after subsequent operations, enabling wellbore reuse. Attached Figure Description

[0016] Figure 1 This is a schematic diagram of the overall connection structure of the present invention; Figure 2 This is a schematic diagram of the connection structure between the central tube assembly and part of the hydrostatic actuation assembly of the present invention; Figure 3 This is a schematic diagram of the connection structure between the piston sleeve and part of the transmission components of the present invention; Figure 4 This is a schematic diagram of the connection structure between part of the transmission component and the central tube component of the present invention; Figure 5 For the present invention Figure 4 Enlarged view of point A in the middle; Figure 6 This is a schematic diagram of the connection structure between the central tube assembly and some of the spare hydraulic actuation components of the present invention; Figure 7 This is a schematic diagram of the connection structure between the central tube assembly and the connecting sleeve of the present invention; Figure 8 For the present invention Figure 7 Enlarged view at point B in the middle; Figure 9 This is a schematic diagram of the connection structure between the central tube assembly and the sealing assembly of the present invention; Figure 10 This is a schematic diagram of the connection structure between the central tube assembly and the elastic rubber sleeve of the present invention; Figure 11 This is a schematic diagram of the connection structure between the central tube assembly and part of the anchoring assembly of the present invention; Figure 12 For the present invention Figure 11 Enlarged view of point C in the middle.

[0017] In the diagram: 1. Central tube assembly; 2. Sealing assembly; 21. Lower guide ring; 22. Elastic rubber sleeve; 3. Anchoring assembly; 31. Axial limiting half ring; 32. Cone; 321. Upper cone; 322. Lower cone; 33. Third shear pin; 34. Slip; 341. Upper slip; 342. Lower slip; 4. Hydrostatic actuation assembly; 41. Lower connector; 42. Lower piston sleeve; 43. First shear pin; 44. Transmission assembly; 441. Upper piston sleeve; 442. Limiting block; 443. Hydraulic piston sleeve; 444. Lower locking ring; 45. Rupture disc; 5. Spare hydraulic actuation assembly; 51. Pressure transmission hole; 52. Spare piston; 53. Upper locking ring; 6. Locking ring sleeve; 7. Connecting sleeve; 8. Second shear pin; 9. Lower sliding ring; 10. Upper guide ring; 11. Fourth shear pin; 12. C-type limiting ring; 13. Upper slip seat; 14. Fifth shear pin; 15. Retaining ring; 16. Upper moving ring; 17. Support ring. Detailed Implementation

[0018] The technical solutions of the embodiments of the present invention will be clearly and completely described below with reference to the accompanying drawings. Obviously, the described embodiments are only some embodiments of the present invention, and not all embodiments. Based on the embodiments of the present invention, all other embodiments obtained by those skilled in the art without creative effort are within the scope of protection of the present invention.

[0019] According to a first aspect of this application, this application provides a large-diameter removable hydrostatic packer, comprising: Central tube assembly 1; The sealing assembly 2 is disposed on the central tube assembly 1 and is used to deform radially under axial force to seal the annular space between the central tube assembly 1 and the well wall; Anchoring component 3 is mounted on central tube component 1 and is used to radially displace and fix the well wall under axial force. The composite hydraulic drive component is connected to the sealing assembly 2 and the anchoring assembly 3 respectively, and is used to generate axial pressure through the downhole fluid pressure difference to drive the sealing assembly 2 and the anchoring assembly 3, and to limit the displacement direction of the sealing assembly 2 and the anchoring assembly 3.

[0020] In this application, the central tube assembly 1 is provided with a first section, a second section, and a third section along the central axis. The first section is the upper central tube, the second section is the mandrel, and the third section is the lower connecting sleeve. Specifically, the central tube assembly 1 is a hollow tubular structure that forms a through internal flow channel. In the non-setting transport and installation state, the outer diameter of the sealing assembly 2 is smaller than the inner diameter of the casing and does not contact the well wall. During setting, the axial pressure generated by the composite hydraulic drive component is transmitted through the anchoring assembly 3, causing the sealing assembly 2 to undergo radial elastic expansion under axial compression, tightly fitting against the inner wall of the casing, achieving an annular seal between the central tube assembly 1 and the well wall. During unsealing, the axial compression force is released, and the sealing assembly 2 automatically retracts to its initial size, ensuring the removability of the packer. During the installation of anchoring component 3, its outer diameter is smaller than the inner diameter of the casing, and it does not contact the casing. During setting, it expands radially under the axial force of the composite hydraulic drive component, and its outer edge teeth or hard interlocking surface embeds into the inner wall of the casing to form a firm mechanical anchor, preventing the packer from shifting under axial load and ensuring a stable and reliable sealing position. The composite hydraulic drive component uses the downhole fluid pressure difference as the driving energy, converting fluid pressure energy into axial mechanical thrust. At the same time, the composite hydraulic drive component has a built-in one-way limiting mechanism to limit the displacement direction of sealing component 2 and anchoring component 3, ensuring that after setting, each part can only maintain its position in the setting direction and cannot retract in the opposite direction, thereby maintaining the setting force without decay. This drive method, which uses the downhole in-situ fluid pressure difference as a power source, allows the packer's setting action to be automatically triggered by the downhole environmental pressure, and the setting pressure is precisely controllable.

[0021] In some embodiments of this application, it also includes: Locking ring 6 is fitted onto the outside of the central tube assembly 1; The connecting sleeve 7 is slidably mounted on the central tube assembly 1 and located inside the locking ring sleeve 6; The second shear pin 8 has two ends that pass through and connect the locking ring sleeve 6 and the connecting sleeve 7; The sliding ring 9 is slidably sleeved on the central tube assembly 1 and connected to the connecting sleeve 7. The sliding ring 9 abuts against the anchoring assembly 3. Specifically, as shown... Figure 7As shown, the locking ring sleeve 6 is a cylindrical structure, coaxially fitted onto the outer wall of the first part of the central tube assembly 1, located on the axial transmission path between the composite hydraulic drive component and the anchoring component 3. The inner wall of the locking ring sleeve 6 has an inner annular groove for installing the upper locking ring 53, and the side wall of the locking ring sleeve 6 has radially opened pin holes for installing the second shear pin 8. The connecting sleeve 7 is a thin-walled cylindrical structure, coaxially slidably fitted onto the outer wall of the central tube assembly 1, located in the inner space of the locking ring sleeve 6. A clearance fit is maintained between the outer wall of the connecting sleeve 7 and the inner wall of the locking ring sleeve 6, allowing the connecting sleeve 7 to slide axially relative to the locking ring sleeve 6. The outer wall of the connecting sleeve 7 has a locking tooth surface structure adapted to the upper locking ring 53. The upper end of the connecting sleeve 7 is fixedly connected to the lower sliding ring 9. Specifically, in this application, the connection method is a threaded connection. The connecting sleeve 7 cooperates with the second shear pin 8, forming a shearable temporary fixed connection with the locking ring sleeve 6 through the second shear pin 8. The upper end face of the sliding ring 9 abuts against the upper end face of the lower slip 342 in the anchoring assembly 3. During the packer setting process, the axial thrust generated by the composite hydraulic drive component is transmitted to the sliding ring 9 in sequence through the locking ring sleeve 6 and the connecting sleeve 7. The sliding ring 9 applies this axial thrust to the anchoring assembly 3, driving the slip 34 in the anchoring assembly 3 to expand radially along the cone 32 to engage the inner wall of the sleeve.

[0022] In some embodiments of this application, the composite hydraulic drive component includes a hydrostatic actuation assembly 4, which includes: The lower connector 41 is fixedly sleeved on the central tube assembly 1; The lower piston sleeve 42 is slidably sleeved on the central tube assembly 1. The inner wall of the lower piston sleeve 42, the lower connector 41 and the outer wall of the central tube assembly 1 form a hydraulic chamber, and the lower piston sleeve 42 is provided with a limiting clearance groove. A rupture disc 45 is disposed through the lower piston sleeve 42 and communicates with the hydraulic chamber. The first shear pin 43 has both ends that pass through and connect the lower connector 41 and the lower piston sleeve 42; The transmission assembly 44 is mounted on the central tube assembly 1 and abuts against the lower piston sleeve 42. The lower connector 41 is an annular flange structure, which is threadedly fixed to the lower outer wall of the third section of the lower connecting sleeve of the central tube assembly 1, forming the lower end connector of the packer and serving as the lower end sealing wall of the hydraulic chamber. The lower connector 41 is provided with a sealing mating surface, on which O-ring mounting grooves and back ring mounting grooves are opened. An O-ring and a back ring are installed, forming a dynamic seal with the inner wall of the lower piston sleeve 42 to prevent leakage of the pressure medium in the hydraulic chamber.

[0023] The lower piston sleeve 42 is a hollow cylindrical structure with a certain wall thickness, which is coaxially slidably sleeved on the outer wall of the central tube assembly 1, located above the lower connector 41. Figure 2 , Figure 3 As shown, the lower end of the inner wall of the lower piston sleeve 42, the upper end face of the lower connector 41, and the outer wall of the lower connecting sleeve of the central tube assembly 1 together form a sealed hydraulic chamber. Before the packer is inserted into the well, the interior of the hydraulic chamber is under normal pressure or vacuum, with the pressure close to zero. A through mounting hole is provided on the outer wall of the lower piston sleeve 42 for installing the rupture disc 45. This mounting hole connects the hydraulic chamber with the annular space outside the packer. The limiting clearance groove is a long groove-shaped structure extending axially along the inner wall of the lower piston sleeve 42, used to provide radially opening clearance space for the limiting block 442 in the transmission assembly 44 during the axial displacement of the lower piston sleeve 42. In this application, the limiting clearance groove is machined as a through groove with a rectangular cross-section, and the groove width is adapted to the width of the limiting block 442.

[0024] One side of the fracture disk 45 is connected to the hydraulic chamber, and the other side is opposite to the annular space outside the packer. After the packer is lowered into the well to the predetermined position with the tubing string, the annular hydrostatic pressure outside the packer gradually increases with the well depth. When the annular pressure reaches the design fracture pressure value of the fracture disk 45, the fracture disk 45 undergoes structural rupture, and the high-pressure fluid in the annulus rushes into the hydraulic chamber, causing the pressure in the hydraulic chamber to rise instantaneously from zero to the annular pressure value. This creates a pressure difference with the sealing cavity of the upper part of the piston sleeve 42, thereby generating an upward hydraulic thrust on the lower end face of the lower piston sleeve 42. This drives the lower piston sleeve 42 to overcome the shear resistance of the first shear pin 43 and slide upward axially.

[0025] The first shear pin 43 is a standard shear pin structure that penetrates the wall thickness of the lower connector 41 radially. Its two ends are inserted into the corresponding pin holes preset on the lower connector 41 and the lower piston sleeve 42, respectively, to temporarily fix the lower connector 41 and the lower piston sleeve 42 into one unit, so as to prevent the lower piston sleeve 42 from undergoing unexpected axial displacement when the packer is in a non-working state such as during transportation or insertion.

[0026] The transmission assembly 44 is mounted on the central tube assembly 1, located above the lower piston sleeve 42, with its lower end face abutting against the upper end face of the lower piston sleeve 42. During the upward axial displacement of the lower piston sleeve 42, the upper end face of the lower piston sleeve 42 pushes the transmission assembly 44 to move upward synchronously, thereby transmitting the hydraulic driving force upward to the anchoring assembly 3 and the sealing assembly 2.

[0027] In some embodiments of this application, the transmission assembly 44 includes: The upper piston sleeve 441 is slidably sleeved on the central tube assembly 1; The limiting block 442 is disposed through the upper piston sleeve 441. The limiting block 442 abuts against the central tube assembly 1 and is adapted to the limiting clearance groove. The hydraulic piston sleeve 443 is slidably sleeved on the central tube assembly 1 and connected to the upper piston sleeve 441 and the locking ring sleeve 6. A lower locking ring 444 is connected to the hydraulic piston sleeve 443. The lower locking ring 444 forms a one-way ratchet engagement with the central tube assembly 1 to limit the reverse axial displacement of the hydraulic piston sleeve 443. The upper piston sleeve 441 is a hollow cylindrical structure that is coaxially slidably fitted on the outer wall of the central tube assembly 1, located above the lower piston sleeve 42. An O-ring and a back ring are provided between the inner wall of the upper piston sleeve 441 and the outer wall of the central tube assembly 1 to form a sliding seal engagement. The lower end face of the upper piston sleeve 441 abuts against the upper end face of the lower piston sleeve 42, receiving axial thrust from the lower piston sleeve 42 during the setting process. A through-hole for mounting a limiting block 442 is provided radially on the side wall of the upper piston sleeve 441. An external thread or screw hole is provided on the upper end of the outer wall of the upper piston sleeve 441 for fixed connection with the hydraulic piston sleeve 443.

[0028] The limiting block 442 is a block-shaped structure with a certain thickness, which penetrates and is installed in the limiting block mounting hole on the side wall of the upper piston sleeve 441. Figure 3 , Figure 4 and Figure 5 As shown, a first serrated portion is provided on the outer wall of the second section of the mandrel of the central tube assembly 1. The limiting block 442 is provided with a second serrated portion that engages with and limits the first serrated portion. Through the engagement of the first serrated portion and the second serrated portion, when the packer is in the initial unset state, the central tube assembly 1 and the limiting block 442 form a temporary limit, restricting the upper piston sleeve 441 from moving. At the same time, when the first shear pin 43 is not cut off, the limiting block 442 cannot be radially ejected outward into the limiting clearance groove, locking the upper piston sleeve 441 and the central tube assembly 1 into one piece, preventing the upper piston sleeve 441 from axially moving in the non-working state.

[0029] During the setting and starting process, after the lower piston sleeve 42 slides upward a certain distance under hydraulic pressure, the limiting clearance groove on the outer wall of the lower piston sleeve 42 moves upward to the radial position where the limiting block 442 is located. The limiting clearance groove provides the limiting block 442 with a radially outward clearance space. Under the action of elastic force, the limiting block 442 ejects radially outward and disengages from the locking position on the outer wall of the central tube assembly 1. The locking relationship between the upper piston sleeve 441 and the central tube assembly 1 is released, and the upper piston sleeve 441 gains the ability to slide freely along the axial direction. Subsequently, the lower piston sleeve 42 continues to push the upper piston sleeve 441 upward, and the upper piston sleeve 441 drives the hydraulic piston sleeve 443 to move upward synchronously, completing the force transmission. In this application, the number of limiting blocks 442 can be set to 3 or 4 evenly distributed circumferentially according to the locking force requirements.

[0030] The hydraulic piston sleeve 443 is a hollow cylindrical structure that is coaxially slidably fitted onto the outer wall of the central tube assembly 1, located above the upper piston sleeve 441. The lower end of the hydraulic piston sleeve 443 is fixedly connected to the upper piston sleeve 441 by threads and screws, and the upper end is fixedly connected to the locking ring sleeve 6 by threads, forming a rigid, linked whole. During the setting process, when the upper piston sleeve 441 moves upward, it simultaneously drives the hydraulic piston sleeve 443 and the locking ring sleeve 6 to move upward together, thereby transmitting the axial thrust to the anchoring assembly 3 and the sealing assembly 2 above the locking ring sleeve 6.

[0031] The inner wall of the lower locking ring 444 is machined with serrated ratchet teeth, and the outer wall of the first section of the central tube assembly 1 is provided with axially serrated tooth surfaces that mate with it. During packer setting, the hydraulic piston sleeve 443 moves upward axially, and the inner teeth of the lower locking ring 444 and the tooth surfaces on the outer wall of the central tube assembly 1 form a toothed meshing relationship. The inclined guiding effect between the tooth surfaces allows the lower locking ring 444 to slide smoothly upward with the hydraulic piston sleeve 443. After the packer is set, the packer bears the annular pressure differential load from downhole. This load is transmitted to the hydraulic piston sleeve 443 through the sealing assembly 2 and the anchoring assembly 3, causing the hydraulic piston sleeve 443 to bear a downward reverse axial force. At this time, the inner teeth of the lower locking ring 444 and the toothed surface on the outer wall of the central tube assembly 1 form a reverse tooth meshing relationship. The right-angle engagement surface between the toothed surfaces prevents the lower locking ring 444 from moving downward, thereby locking the hydraulic piston sleeve 443 in the setting position, effectively preventing the attenuation of the setting force and the failure of the seal. In this application, a first piston chamber is formed between the lower piston sleeve 42 and the third lower connecting sleeve of the central tube assembly 1, and a second piston chamber is formed between the upper piston sleeve 441 and the second mandrel of the central tube 1, thus forming a double piston chamber. By axially arranging the first and second piston chambers in the extremely limited radial space downhole, the parallel introduction of fluid pressure and the series superposition of mechanical thrust are realized. This structure expands the total pressure-bearing area and, while ensuring the same axial thrust for setting, can reduce the required hydraulic setting pressure.

[0032] In some embodiments of this application, the composite hydraulic drive component further includes a backup hydraulic actuation assembly 5, which includes: A pressure transmission hole 51 is radially penetrated and opened on the central tube assembly 1; The spare piston 52 is slidably sleeved on the central tube assembly 1 and located on the external communication path of the pressure transmission hole 51. The spare piston 52 is connected to the connecting sleeve 7. The upper locking ring 53 is connected inside the locking ring sleeve 6. The upper locking ring 53 forms a one-way stop fit with the outer wall of the connecting sleeve 7. The pressure transmission hole 51 is a through hole structure that penetrates the pipe wall radially along the central tube assembly 1, connecting the internal flow channel of the central tube assembly 1 and the annular hydraulic cavity space between the outside of the central tube assembly 1 and the hydraulic piston sleeve 443. Figure 6 , Figure 7and Figure 8 As shown, the spare piston 52 is a hollow annular piston structure, coaxially and slidably fitted onto the outer wall of the central tube assembly 1, located on the external communication path of the pressure transmission hole 51. An O-ring and a back ring are provided between the inner wall of the spare piston 52 and the outer wall of the central tube assembly 1, forming a sliding seal to prevent leakage of pressurized fluid along the inner wall gap. An O-ring and a back ring are also provided between the outer wall of the spare piston 52 and the inner wall of the hydraulic piston sleeve 443, forming a sliding seal. The lower end face of the spare piston 52, together with the end of the spindle of the central tube assembly 1 and the inner wall of the hydraulic piston sleeve 443, forms a sealed spare hydraulic chamber. The external outlet of the pressure transmission hole 51 is located within the cavity of this spare hydraulic chamber, allowing the pressurized fluid inside the central tube assembly 1 to enter the spare hydraulic chamber through the pressure transmission hole 51. The upper end of the spare piston 52 is fixedly connected to the lower end of the connecting sleeve 7 by a thread. When the spare piston 52 is driven by hydraulic pressure to move upward along the axis, the spare piston 52 pushes the connecting sleeve 7 to move upward synchronously.

[0033] After the packer is lowered to the predetermined position downhole, if the annular hydrostatic column pressure is insufficient to trigger the rupture disc 45, for example in shallow wells or under low-density well fluid conditions, the hydrostatic actuation assembly 4 cannot be properly activated and set. In this case, the operator can drop a sealing ball into the internal flow channel of the central tube assembly 1 from the wellhead. The sealing ball falls onto a pre-set ball seat below the packer, sealing the internal flow channel of the central tube assembly 1. Then, the tubing string is pressurized by the surface pump set. The pressurized fluid inside the tubing string enters the standby hydraulic chamber through the pressure transmission hole 51, acting on the lower end face of the standby piston 52, generating an upward axial thrust on the effective pressure-bearing area of ​​the standby piston 52. When this axial thrust reaches the set shear value of the second shear pin 8, the second shear pin 8 is sheared, the temporary locking relationship between the connecting sleeve 7 and the locking ring sleeve 6 is released, and the standby piston 52 pushes the connecting sleeve 7 to move upward axially. The upward movement of the connecting sleeve 7 drives the sliding ring 9 upward synchronously. The sliding ring 9 transmits axial thrust to the anchoring assembly 3, initiating the setting action of the anchoring assembly 3 and the sealing assembly 2. The backup hydraulic actuation assembly 5 and the hydrostatic actuation assembly 4 form a redundant dual hydraulic drive system, improving the setting success rate of the packer under various complex well conditions. Even if the main drive system fails due to the fracture plate failing to rupture as designed, the backup drive system can still reliably complete the setting operation, ensuring the safety and continuity of downhole operations.

[0034] The locking ring 53 is an annular part with a one-way stop tooth structure, connected to a pre-set annular groove on the inner wall of the locking ring sleeve 6. The inner tooth surface of the locking ring 53 faces the outer wall of the connecting sleeve 7, and the corresponding section of the outer wall of the connecting sleeve 7 is machined with an axial sawtooth tooth surface that mates with the inner tooth surface of the locking ring 53. During the standby hydraulic setting process, the connecting sleeve 7 moves axially upward under the drive of the standby piston 52. The inner teeth of the locking ring 53 and the tooth surface on the outer wall of the connecting sleeve 7 form a toothed meshing relationship. The inclined guide effect between the tooth surfaces allows the connecting sleeve 7 to smoothly pass upward through the locking ring 53. After setting is completed, the packer bears the annular pressure differential load. The pressure differential load is transmitted downward to the connecting sleeve 7 through the sealing assembly 2 and the anchoring assembly 3, causing the connecting sleeve 7 to bear a downward reverse axial force. At this time, the inner teeth of the locking ring 53 and the toothed surface on the outer wall of the connecting sleeve 7 form a reverse tooth meshing relationship. The right-angle locking surface between the toothed surfaces prevents the connecting sleeve 7 from moving downward, thereby locking the connecting sleeve 7 in the setting position and effectively preventing the setting force from weakening and the seal from failing.

[0035] In some embodiments of this application, the anchoring component 3 includes: The axial limiting semi-ring 31 is engaged in the pre-set annular groove on the outer wall of the central tube assembly 1; A pair of cones 32, including an upper cone 321 and a lower cone 322, are slidably sleeved on the central tube assembly 1 with their surfaces spaced apart from each other. The third shear pin 33 is connected at both ends to the axial limiting half ring 31 and the lower cone 322; A pair of slips 34, including an upper slip 341 and a lower slip 342, are slidably fitted onto the central tube assembly 1. The slips 34 slide against a cone 32. Under axial force, the cone 32 drives the slips 34 to expand radially. An annular groove is opened circumferentially along the outer wall of the central tube assembly 1. The groove depth and width are adapted to the cross-sectional dimensions of the axially limiting semi-ring 31. After the axially limiting semi-ring 31 is engaged in the annular groove, it is constrained radially by the groove wall and axially limited by the upper and lower groove walls, preventing the axially limiting semi-ring 31 from disengaging radially or moving axially, thus forming a secure axial positioning reference. Figure 9 As shown, the outer end face of the axial limiting semi-ring 31 is fixedly connected to the lower cone 322 by the third shear pin 33, so that the lower cone 322 is fixed on the central tube assembly 1 in the initial state with the axial limiting semi-ring 31 as the axial positioning reference point.

[0036] Both the upper cone 321 and the lower cone 322 are annular structures with conical surfaces, and are coaxially and slidably fitted onto the outer wall of the central tube assembly 1. The conical surface of the upper cone 321 faces upward, and the conical surface of the lower cone 322 faces downward, with their conical surfaces arranged at intervals facing each other.

[0037] During the packer setting process, when the axial thrust generated by the composite hydraulic drive component is transmitted to the lower slip 342 via the sliding ring 9, the lower slip 342 slides along the conical surface of the lower cone 322 to the top of the conical surface. The axial force is then completely converted into an axial load on the lower cone 322. When this axial load reaches the shear threshold of the third shear pin 33, the third shear pin 33 is sheared off, and the lower cone 322 is released from the axial limiting half-ring 31, gaining the ability to slide upwards axially. This, in turn, pushes the sealing assembly 2 to undergo axial compression to complete the seal. The third shear pin 33 ensures that the radial expansion anchoring of the lower slip 342 is completed first, followed by the axial compression sealing of the sealing assembly 2, avoiding premature compression deformation of the sealing assembly 2 before the slip is anchored, which could lead to seal failure.

[0038] The inner conical surface of the upper slip 341 engages with the outer conical surface of the upper cone 321 to form a conical sliding pair; the inner conical surface of the lower slip 342 engages with the outer conical surface of the lower cone 322 to form a conical sliding pair. During the setting process, when the axial force drives the cones 32 to move in opposite directions, the wedge effect of the conical surface converts the axial force into a radial component, driving the slip 34 to slide outward along the conical surface, i.e., radial expansion occurs. The outer wall of the slip 34 is machined with hard alloy teeth or a layer of tungsten carbide hard alloy particles. After the slip 34 expands radially, the teeth or hard particles on the outer wall embed into the inner wall of the casing, forming a reliable mechanical engagement and anchoring, preventing axial movement of the packer when subjected to axial loads downhole.

[0039] The anchoring assembly 3 adopts a symmetrically arranged double-cone double-slip structure, enabling the packer to withstand bidirectional axial loads from both above and below after setting. When a pressure difference exists between the upper and lower annulus after the packer is sealed, the axial load generated by the pressure difference, whether upward or downward, can be borne by the anchoring force on the corresponding side of the upper slip 341 and lower slip 342. This effectively prevents axial movement of the packer under bidirectional pressure difference loads, ensuring a stable and reliable sealing position for the sealing assembly 2 and improving the long-term service performance of the packer under complex formation pressure conditions. Springs are installed in both the upper slip 341 and lower slip 342 to assist in the recovery of the upper slip 341 and lower slip 342.

[0040] In some embodiments of this application, it also includes: The upper guide ring 10 is sleeved on the central tube assembly 1 and abuts against the upper cone 321. The upper guide ring 10 and the upper cone 321 enclose and form a receiving cavity. The fourth shear pin 11 is connected to the upper guide ring 10 and the central tube assembly 1 through both ends; A C-shaped limiting ring 12 is disposed within the receiving cavity. The C-shaped limiting ring 12 abuts against the first stepped portion of the outer wall of the central tube assembly 1 during the displacement of the upper guide ring 10 and the upper cone 32. The upper guide ring 10 is a ring-shaped rigid structure, coaxially sleeved on the outer wall of the central tube assembly 1, located between the sealing assembly 2 and the upper cone 321. The lower end face of the upper guide ring 10 abuts against the lower end face of the upper cone 321, receiving axial thrust from the upper cone 321 during the setting process. Figure 10 , Figure 11 and Figure 12 As shown, the upper guide ring 10 is temporarily fixedly connected to the central tube assembly 1 by the fourth shear pin 11. When the packer is in the initial unset state, the upper guide ring 10 is locked to the central tube assembly 1 by the fourth shear pin 11 and cannot move axially. The lower end of the inner wall of the upper guide ring 10 and the upper inner wall of the upper cone 321 form an annular receiving cavity, which is used to receive and install the C-type limiting ring 12.

[0041] During the packer setting process, after the elastic sleeve 22 in the sealing assembly 2 is fully axially compressed and completes radial expansion sealing, the continuously increasing axial force continues to be applied to the upper guide ring 10. When this axial force reaches the shear threshold of the fourth shear pin 11, the fourth shear pin 11 is sheared, and the upper guide ring 10 is released from the central tube assembly 1, gaining the ability to slide upward axially. After the upper guide ring 10 moves upward, it drives the upper cone 321 to move upward synchronously. The outer conical surface of the upper cone 321 drives the upper slip 341 to expand radially along the conical surface to engage the inner wall of the sleeve, completing the anchoring action of the upper slip 341.

[0042] The C-shaped limiting ring 12 is an elastic annular part with an open notch, disposed within the receiving cavity formed between the upper guide ring 10 and the upper cone 321. The inner wall of the C-shaped limiting ring 12 has a first protruding tooth, and the outer wall of the central tube assembly 1 also has a second protruding tooth that matches the first protruding tooth of the C-shaped limiting ring 12. During the retraction of the packer, the central tube assembly 1 is lifted, and the first and second protruding teeth form a toothed meshing relationship. The inclined guiding effect between the tooth surfaces allows the central tube assembly 1 to slide smoothly upward relative to the C-shaped limiting ring 12. If jamming occurs during the lifting process, preventing further upward movement, a counter-force is applied to the central tube assembly 1, i.e., pushing the central tube downward. In component 1, due to the reverse tooth meshing relationship between the tooth surfaces of the first and second convex teeth, the upper guide ring 10 and the upper cone 321 will move downward as a whole. After adjusting their overall position, they will move upward. As the central tube component 1 continues to move upward, the C-shaped limiting ring 12 can move to the first step of the central tube component 1. The first step abuts against the C-shaped limiting ring 12, forming an axial support for the upper cone 321 and the upper guide ring 10, so that the upper cone 321 and the upper guide ring 10 can be suspended on the central tube component 1 and lifted up to the wellhead together to realize the unsealing and recovery function.

[0043] In some embodiments of this application, the sealing assembly 2 is disposed on the transmission path between the upper guide ring 10 and the lower cone 322, and the sealing assembly 2 includes: The lower guide ring 21 is slidably sleeved on the central tube assembly 1 and connected to the lower cone 322; The elastic sleeve 22 is slidably fitted onto the central tube assembly 1 and located between the upper guide ring 10 and the lower guide ring 21. The lower guide ring 21 is a ring-shaped rigid structure that is coaxially slidably fitted onto the outer wall of the central tube assembly 1 and located below the elastic sleeve 22. Figure 9 As shown, both the upper end face of the lower guide ring 21 and the lower end face of the upper guide ring 10 are provided with annular skirt structures. The end of the elastic rubber sleeve 22 can be snapped into the annular skirt structure. The annular skirt structure plays a dual role of radial guidance and end extrusion prevention. On the one hand, it guides the radial expansion direction of the elastic rubber sleeve 22 to expand outward evenly. On the other hand, it effectively seals the annular gap between the outer edge of the lower guide ring 21 and the inner wall of the sleeve, preventing the end rubber material of the elastic rubber sleeve 22 from being squeezed out of the gap under high pressure conditions, which would cause damage to the sealing surface or even seal failure.

[0044] The elastic sleeve 22 is a hollow cylindrical elastic sealing element, coaxially sliding on the outer wall of the central tube assembly 1, axially located between the lower end face of the upper guide ring 10 and the upper end face of the lower guide ring 21. The inner wall of the elastic sleeve 22 maintains a clearance fit with the outer wall of the central tube assembly 1, allowing the elastic sleeve 22 to slide freely along the axial direction of the central tube assembly 1. During the initial transport and lowering of the packer in its unset state, the elastic sleeve 22 is in a naturally relaxed state, with its outer diameter smaller than the inner diameter of the casing, maintaining sufficient radial clearance to ensure the packer can smoothly pass through the reduced and variable diameter sections of the casing's inner diameter and be lowered to the predetermined depth.

[0045] In some embodiments of this application, an unsealing component is also included, which includes: The upper clamp seat 13 is sleeved on the central tube assembly 1. The upper clamp seat 13 has a mounting notch, and the upper clamp 341 is engaged in the mounting notch. The fifth shear pin 14 is connected at both ends to the upper slip seat 13 and the central tube assembly 1; The retaining ring 15 is slidably sleeved on the central tube assembly 1, and the retaining ring 15 is used to abut against the second step portion protruding from the outer wall of the central tube assembly 1. The upper moving ring 16 is connected to the central tube assembly 1, and the retaining ring 15 is located between the upper moving ring 16 and the upper clamp seat 13; The support ring 17 is connected to the central tube assembly 1 and embedded inside the connecting sleeve 7. The upper clamp seat 13 is a ring-shaped rigid structure, coaxially fitted onto the outer wall of the central tube assembly 1, located directly above the upper clamp 341. Multiple mounting notches are spaced apart on the outer periphery of the upper clamp seat 13, the shape and size of each notch being adapted to the upper end locking joint of each fan-shaped segment of the upper clamp 341. For example... Figure 11 As shown, in the initial state of the packer, the upper end locking joints of each segment of the upper slip 341 are respectively engaged into the corresponding mounting notches, suspending the upper slip 341 on the upper slip seat 13. The weight of the upper slip 341 and its own weight load during the lowering process are borne by the upper slip seat 13, preventing the upper slip 341 from sliding axially to a non-predetermined position due to its own weight during the lowering process. The upper slip seat 13 is fixedly connected to the central tube assembly 1 by the fifth shear pin 14, so that the upper slip seat 13 remains axially fixed relative to the central tube assembly 1 during setting and normal operation.

[0046] During the packer release process, the operator cuts off the lower end of the center tube assembly 1 downhole using a cutting tool, as follows: Figure 7As shown, during cutting, the cutting can be performed along the indicator line Y1, lifting the central tube assembly 1 from the ground. During the upward movement of the central tube assembly 1, the upper slip seat 13 is connected to the central tube assembly 1 via the fifth shear pin 14 and moves upward along with it. However, the upper slip 341 is still in a radially expanded state, and its teeth are engaged with the inner wall of the sleeve, generating downward resistance against the upper slip seat 13. When the lifting force increases to the shear threshold of the fifth shear pin 14, the fifth shear pin 14 is sheared, and the fixed connection between the upper slip seat 13 and the central tube assembly 1 is released.

[0047] The retaining ring 15 is an annular structure that is coaxially slidably fitted onto the outer wall of the central tube assembly 1, located in the axial space between the upper moving ring 16 and the upper slip seat 13. The inner diameter of the retaining ring 15 is slightly larger than the outer diameter of the central tube assembly 1 in this section, allowing the retaining ring 15 to slide freely axially. A second step is protruding above the section where the retaining ring 15 is located on the outer wall of the central tube assembly 1. The second step is an annular step surface formed by the sudden increase in the outer diameter of the central tube assembly 1. In the initial state and setting state of the packer, the ends of the retaining ring 15 and the upper moving ring 16 abut against each other, forming an axial upper limit. During the unsealing process, after the central tube assembly 1 is lifted, the fifth shear pin 14 cuts off, the upper slip seat 13 disengages from the central tube assembly 1, and as the central tube assembly 1 continues to be lifted, the retaining ring 15 abuts against the second step, and the step surface of the second step prevents the retaining ring 15 from moving further downward. At this time, the lower end face of the retaining ring 15 serves as the suspension support surface, and the upper slip seat 13 and the upper slip 341 suspended thereon can be placed above the retaining ring 15 and indirectly suspended on the central tube assembly 1 through the retaining ring 15.

[0048] The support ring 17 is a ring-shaped structure, fixedly connected to the outer wall of the central tube assembly 1, and embedded in the inner space of the connecting sleeve 7. Specifically, the support ring 17 is fixed using a threaded connection in this application. During packer setting, as the connecting sleeve 7 moves axially upward, it slides along the outer wall surface of the support ring 17. During packer unsealing, the central tube assembly 1 is lifted, causing the support ring 17 to move upward as well. When the upper end face of the support ring 17 moves to abut against the lower end face of the sliding ring 9, the support ring 17 acts as an axial lifting structure, bearing the weight of all parts on the connecting sleeve 7 and the sliding ring 9, and pulling these parts upward with the central tube assembly 1 to the wellhead.

[0049] The overall unpacking process of the packer assembly is as follows: When the downhole operation is completed and the packer needs to be removed, firstly, using a downhole cutting tool such as a chemical cutter or mechanical cutter, the central tube assembly 1 is circumferentially cut at a preset cutting position at the lower end, separating the upper and lower sections of the central tube assembly 1. Then, the upper section of the central tube assembly 1 is lifted from the surface. During the lifting process, along... Figure 1Lifting upwards in the direction indicated by the middle arrow causes the central tube assembly 1 to move upwards, with the upward-moving ring 16 initially moving upwards along with it. When the lifting force increases to the shearing threshold of the fifth shear pin 14, the fifth shear pin 14 is sheared, and the upper slip seat 13 disengages from the central tube assembly 1. Continuing to lift the central tube assembly 1, the retaining ring 15 abuts against the second step. As it continues to move upwards, the upper slip 341 is unanchored and suspended from the upper slip seat 13 via the clamping joint. Simultaneously, the elastic rubber sleeve 22 elastically retracts to its initial outer diameter after the axial compression force is released, disengaging from the inner wall of the sleeve, thus releasing the seal. Continuing to lift the central tube assembly 1, the axial limiting half-ring 31 abuts against the lower guide ring 21, causing the entire lower cone 322 to move upwards. At this point, the lower cone 322 disengages from the lower slip 342, and the teeth of the lower slip 342 disengage from the inner wall of the sleeve, completing the unanchoring of the lower slip 342. After the central tube assembly 1 is lifted a certain distance, the upper end face of the support ring 17 abuts against the inner side of the lower end face of the sliding ring 9. The support ring 17 then supports the sliding ring 9, the connecting sleeve 7, and all the parts below them. Finally, all the parts of the packer are suspended or supported on the central tube assembly 1 and lifted together with the central tube assembly 1 to the wellhead for retrieval. No metal parts or foreign objects remain in the wellbore, providing a clean and unobstructed wellbore passage for subsequent operations.

[0050] The introduction of the unsealing component enables the packer to combine the high reliability of a permanent hydrostatic packer with the flexible recovery capability of a retrievable packer. In operations requiring packer recovery, such as well testing, temporary packing, and well workover, operators can complete the entire unsealing and recovery process simply by cutting the lower end of the center tube and lifting the tubing string. This streamlined and quick process eliminates the need for downhole milling operations, reducing operating costs and risks, and improving the economic efficiency of offshore oilfield development.

[0051] According to a second aspect of this application, this application provides a downhole operation system, comprising: Working tubing; A large-diameter retrievable hydrostatic packer is connected in series within the work string, with the internal flow channels of the work string connected to the central tube assembly 1 of the packer. The work string, serving as the fluid transport and mechanical load-bearing channel connecting surface wellhead equipment and downhole functional tools, extends along the wellbore trajectory. The large-diameter retrievable hydrostatic packer is rigidly connected to the work string sequence in series via pre-set standard tubing threads at both ends of its central tube assembly 1. After connection, the internal flow channels of the work string and the central tube assembly 1 achieve complete interconnection and smooth transition, forming a full-bore main channel from the wellhead to the bottom of the well with no or minimal diameter reduction.

[0052] In downhole workover systems, when multiple large-diameter retrievable hydrostatic packers are used for tiered well completion or multi-stage well testing, the packers are arranged in series at axial intervals along the workover string. Once the system is lowered to the target depth, no mechanical operations such as lifting, lowering, or rotating the workover string are required at the surface wellhead. In the high hydrostatic pressure environment of deep wells and extended reach wells, the external annular fluid acts directly on the fracture plate in the hydrostatic actuation assembly through the through-hole on the outer wall of the lower piston sleeve. When the hydrostatic pressure reaches the set fracture threshold of the fracture plate, the fracture plate ruptures instantaneously, and the hydraulic energy of the downhole fluid pressure difference is immediately converted into mechanical axial thrust to drive the lower piston sleeve upward. This thrust is then precisely and without damage transmitted through the transmission assembly, locking ring sleeve, and sliding ring to the anchoring assembly and sealing assembly, completing automatic anchoring and sealing under high pressure and achieving precise setting at specific pressures.

[0053] If the downhole hydrostatic pressure is insufficient or the fracture plate fails to trigger for any reason, the system can insert a sealing ball into the ball seat below the packer through the internal flow channel of the working tubing. Subsequently, the working tubing is pressurized via a surface pump truck. High-pressure fluid flows through the internal flow channel and through the pressure transmission hole on the central tube assembly 1 into the backup hydraulic actuation assembly, driving the backup piston upwards to shear the second shear pin, thus completing the setting action. This dual-drive redundancy design completely solves the problem of force transmission dissipation inherent in traditional mechanical packers.

[0054] During the testing or production phase, a massive amount of oil and gas fluid from high-yield offshore oil and gas wells surges from the formation below the packer and enters the working tubing. The fluid does not experience significant throttling pressure drop or eddy current resistance as it flows through the packer section, maximizing the production capacity of the high-yield well and improving production efficiency. Simultaneously, the locking ring mechanisms at both ends of the packer form a rigid, one-way ratchet lock with the central tubing assembly 1. Regardless of the alternating axial loads generated by drastic temperature changes or pressure fluctuations during oil and gas production, the packer's sealing force does not diminish, achieving long-term, absolute annular sealing reliability.

[0055] When the well testing or temporary packing task is completed and the downhole workover system needs to be retrieved, a cable or coiled tubing carrying an internal cutting tool is lowered through the large-diameter channel of the workover string and center tube assembly 1, cutting it at the pre-designated weak point at the bottom of the center tube assembly 1. Subsequently, the surface winch directly lifts the workover string, and the tension of the string acts directly on the center tube assembly 1, shearing the fifth shear pin and triggering the release mechanism. The packer slips radially retract to release anchoring, the elastic sleeve rebounds to release the packer, and all packer components are safely suspended and supported on the center tube assembly 1, smoothly pulled out of the wellhead along with the workover string. The entire release process eliminates the need for complex milling and grinding operations using large workover rigs, completely eliminating the risk of fish falling into the well and significantly reducing the high post-maintenance and development costs of offshore oilfields.

[0056] It should be noted that, in this document, relational terms such as "first" and "second" are used only to distinguish one entity or operation from another, and do not necessarily require or imply any such actual relationship or order between these entities or operations. Furthermore, the terms "comprising," "including," or any other variations thereof are intended to cover non-exclusive inclusion, such that a process, method, article, or apparatus that comprises a list of elements includes not only those elements but also other elements not expressly listed, or elements inherent to such a process, method, article, or apparatus. Without further limitations, an element defined by the phrase "comprising one..." does not exclude the presence of other identical elements in the process, method, article, or apparatus that includes said element.

[0057] Although embodiments of the invention have been shown and described, it will be understood by those skilled in the art that various changes, modifications, substitutions and alterations can be made to these embodiments without departing from the principles and spirit of the invention, the scope of which is defined by the appended claims and their equivalents.

Claims

1. A large-diameter removable hydrostatic packer, characterized in that, include: Central tube assembly (1); A sealing assembly (2) is disposed on the central tube assembly (1) and is used to deform radially under axial force to seal the annular space between the central tube assembly (1) and the well wall; An anchoring assembly (3) is disposed on the central tube assembly (1) and is used to radially displace and fix the well wall under axial force drive; A composite hydraulic drive component is connected to the sealing assembly (2) and the anchoring assembly (3) respectively, for generating the axial pressure through the downhole fluid pressure difference to drive the sealing assembly (2) and the anchoring assembly (3), and for limiting the displacement direction of the sealing assembly (2) and the anchoring assembly (3).

2. The large-diameter removable hydrostatic packer according to claim 1, characterized in that, Also includes: A locking ring sleeve (6) is fitted onto the outside of the central tube assembly (1); The connecting sleeve (7) is slidably sleeved on the central tube assembly (1) and located inside the locking ring sleeve (6); The second shear pin (8) is connected to the locking ring sleeve (6) and the connecting sleeve (7) through both ends. The sliding ring (9) is slidably sleeved on the central tube assembly (1) and connected to the connecting sleeve (7). The sliding ring (9) abuts against the anchoring assembly (3).

3. The large-diameter removable hydrostatic packer according to claim 2, characterized in that, The composite hydraulic drive component includes a hydrostatic actuation assembly (4), which comprises: The lower connector (41) is fixedly sleeved on the central tube assembly (1); The lower piston sleeve (42) is slidably sleeved on the central tube assembly (1). The inner wall of the lower piston sleeve (42), the lower connector (41) and the outer wall of the central tube assembly (1) form a hydraulic chamber. The lower piston sleeve (42) is provided with a limiting clearance groove. A rupture disc (45) is disposed through the lower piston sleeve (42) and communicates with the hydraulic chamber; The first shear pin (43) is connected at both ends through the lower connector (41) and the lower piston sleeve (42). The transmission assembly (44) is disposed on the central tube assembly (1) and abuts against the lower piston sleeve (42).

4. The large-diameter removable hydrostatic packer according to claim 3, characterized in that, The transmission assembly (44) includes: The upper piston sleeve (441) is slidably sleeved on the central tube assembly (1); A limiting block (442) is disposed through the upper piston sleeve (441), the limiting block (442) abuts against the central tube assembly (1), and the limiting block (442) is adapted to the limiting clearance groove; The hydraulic piston sleeve (443) is slidably sleeved on the central tube assembly (1) and connected to the upper piston sleeve (441) and the locking ring sleeve (6); The lower locking ring (444) is connected to the hydraulic piston sleeve (443). The lower locking ring (444) and the central tube assembly (1) form a one-way ratchet engagement to limit the reverse axial displacement of the hydraulic piston sleeve (443).

5. The large-diameter removable hydrostatic packer according to claim 1, characterized in that, The composite hydraulic drive component further includes a backup hydraulic actuation assembly (5), which includes: A pressure-transmitting hole (51) is radially opened through the central tube assembly (1); The spare piston (52) is slidably sleeved on the central tube assembly (1) and located on the external communication path of the pressure transmission hole (51). The spare piston (52) is connected to the connecting sleeve (7). The upper locking ring (53) is connected inside the locking ring sleeve (6), and the upper locking ring (53) forms a one-way stop fit with the outer wall of the connecting sleeve (7).

6. The large-diameter removable hydrostatic packer according to claim 1, characterized in that, The anchoring component (3) includes: An axial limiting half-ring (31) is snapped into a pre-set annular groove on the outer wall of the central tube assembly (1); A pair of cones (32), including an upper cone (321) and a lower cone (322), are slidably fitted onto the central tube assembly (1) with their surfaces spaced apart. The third shear pin (33) is connected at both ends to the axial limiting half ring (31) and the lower cone (322). A pair of slips (34), including an upper slip (341) and a lower slip (342), are slidably fitted on the central tube assembly (1). The slips (34) are slidably engaged with the cone (32). Under axial force, the cone (32) is used to drive the slips (34) to expand radially.

7. The large inner diameter removable hydrostatic packer according to claim 6, characterized in that, Also includes: The upper guide ring (10) is sleeved on the central tube assembly (1) and abuts against the upper cone (321). The upper guide ring (10) and the upper cone (321) enclose and form a receiving cavity. The fourth shear pin (11) is connected to the upper guide ring (10) and the central tube assembly (1) through both ends. A C-shaped limiting ring (12) is disposed in the receiving cavity. The C-shaped limiting ring (12) is used to abut against the first step portion disposed on the outer wall of the central tube assembly (1) during the displacement of the upper guide ring (10) and the upper cone (32).

8. The large-diameter removable hydrostatic packer according to claim 7, characterized in that, The sealing assembly (2) is disposed on the transmission path between the upper guide ring (10) and the lower cone (322), and the sealing assembly (2) includes: The lower guide ring (21) is slidably sleeved on the central tube assembly (1) and connected to the lower cone (322); The elastic rubber sleeve (22) is slidably sleeved on the central tube assembly (1) and located between the upper guide ring (10) and the lower guide ring (21).

9. The large-diameter removable hydrostatic packer according to claim 1, characterized in that, It also includes an unsealing component, which includes: The upper clamp seat (13) is sleeved on the central tube assembly (1), and the upper clamp seat (13) has a mounting notch, and the upper clamp (341) is engaged in the mounting notch; The fifth shear pin (14) is connected at both ends to the upper slip seat (13) and the central tube assembly (1). A retaining ring (15) is slidably sleeved on the central tube assembly (1), and the retaining ring (15) is used to abut against the second step portion protruding from the outer wall of the central tube assembly (1); The upper moving ring (16) is connected to the central tube assembly (1), and the retaining ring (15) is located between the upper moving ring (16) and the upper clamp seat (13); The support ring (17) is connected to the central tube assembly (1) and is embedded in the inner side of the connecting sleeve (7).

10. A downhole operation system, characterized in that, include: Working tubing; At least one large-diameter removable hydrostatic packer as described in any one of claims 1 to 9, wherein the large-diameter removable hydrostatic packer is connected in series in the working string, and the internal flow channel of the working string is connected to the central tube assembly (1) of the large-diameter removable hydrostatic packer.

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