Packer bypass pressure relief system capable of preventing slip from being opened in advance

Abstract

A packer system (10) includes a packer mandrel (20), an upper support or metering ring (30), a sealing member (40), an upper slip device (50), an upper cone (60), a lower cone (70), a lower slip device (80), a seating sleeve (90), and a seating piston (100). The sealing member (40) has a lowered position and a seated position. When in the seated position, wellbore sealing is performed at a specific location in the wellbore. When the seating sleeve (90) is in the bypass position, the load of the seating piston (100) is transferred from the lower slip arrangement (80) to the lower cone (70), the sealing member (40) and the upper cone (60) to ensure that the sealing member (40) and the upper slip arrangement (50) are seated prior to the lower slip arrangement (80). When the seating sleeve (90) is in a release position for separation from the seating piston (100), the load of the seating piston (100) is ultimately applied to the lower slip arrangement to deploy the lower slip arrangement (80) at an appropriate time and location.

Description

[0001] Claim of priority

[0002] This application claims the benefit of the following non - provisional applications, the entire content of each of which is incorporated herein by reference:

[0003] Application No.: USN 18049374; Filing Date: October 25, 2022; Title: Packer bypass pressure - relief system to prevent premature opening of slips. Technical Field

[0004] The present invention relates to isolating production zones from non - production zones in a wellbore. More specifically, the present invention relates to a packer system fixed at a specific location within a wellbore. More specifically, the present invention relates to a packer system equipped with a setting sleeve that bypasses and relieves the downhole hydraulic pressure load applied by a lower slip to prevent the lower slip from deploying before reaching the intended location in the wellbore. Background Art

[0005] In a wellbore, hydrocarbons are located in rock formations at specific depths. The rock formations at this depth can be classified as production zones to target the flow of fluid to the location of the hydrocarbons. The flow of fluid will assist in recovering hydrocarbons from the wellbore. Rock formations at other depths that do not contain hydrocarbons are referred to as "non - production zones". There is no need to waste fluid in non - production zones that do not contain hydrocarbons. Therefore, in order to successfully recover hydrocarbons from the wellbore, the production zones should be isolated from the non - production zones.

[0006] Known downhole tools can be used to isolate production zones from non - production zones to ensure that fluid can be delivered to the production zones rather than the non - production zones. Examples of downhole tools that can be used for isolation include bridge plugs, packers, or other tools with isolation valves.

[0007] In a conventional process, a packer is run downhole into the wellbore. When it reaches the correct location within the wellbore, the packer expands against the wellbore wall to be fixed at a specific location within the wellbore. A cone assembly drives a slip device from a retracted position to an expanded position. The slip device grabs the wellbore wall in the expanded position or when expanding to fix the packer at the specific location. Downhole operations can be performed after the packer is fixed at this specific location.

[0008] When setting the packer using hydraulic pressure, fluid is pumped to the bottom of the wellbore. As the fluid fills the wellbore, the pressure gradually increases, so the hydraulic pressure acts upward from the bottom of the wellbore. Figures 1 to 4Shows a packer system 1 using the prior art, which includes a packer mandrel 2, a support ring or measuring ring 3, an upper slip device 4, an upper cone 5, a sealing member 6, a lower cone 7, a lower slip device 8, and a setting piston 9. The downhole hydraulic pressure will push upward on the pipe fittings at the bottom of the packer system 1. These pipe fittings will first push the setting piston 9 onto the lower slip device 8, and then the lower slip device 8 will receive all the pressure applied by the setting piston 9 to transition from the retracted position to the deployed position.

[0009] The lower slip device 8 in the retracted position begins to set the packer system 1 in place. The lower slip device 8 is strong enough to withstand the transition to the deployed position to ensure that the pressure through the lower slip device 8 can push the lower cone 7, the sealing member 6, and the upper cone 5. The pressure through the lower slip device 8 will drive the sealing member 6 to expand to the sealing diameter, and the upper slip device 4 will expand under the action of the upper cone 5 to lock onto the wellbore when the sealing member is at the desired position within the wellbore. Additionally, a prior art release component (e.g., a shear pin) can be used to prevent the lower slip device 8 from receiving all the pressure applied by the setting piston 9. However, since all the pressure will now act on the prior art release component, the problems caused by excessive hydraulic pressure cannot be avoided. The prior art high-strength lower slips will have adverse consequences due to the extremely high pressure required and may not form a stable seal with the packer system due to never deploying.

[0010] Figures 1 to 4 Also includes a high-strength lower slip device 8 using the prior art with a high pressure differential required to release the lower slip device 8. Figure 3 Shows the lower slip device 8 still in the retracted position before sealing the lower side of the sealing member 6 by fracturing, where the upper slip device 4 with the upper cone 5 and the sealing member 6 has been deployed in this retracted position. As Figure 4 shown, the components will be set when the sealing member 6 reaches the sealing diameter, and the high-strength lower slip device 8 will be deployed by applying additional hydraulic pressure. The setting of the packer system 1 depends entirely on the lower slip device 8. In the packer system using this prior art, the premature deployment of the lower slip device 8 will cause fatal damage.

[0011] Figures 1 to 2It also includes a lower slip device using the prior art, which will at least partially transition the lower slip device 8 from the retracted position to the deployed position, and at the same time the lower slip device 8 will push the lower cone 7, the sealing member 6 and the upper cone 5. In this low-strength lower slip device 8, the premature deployment of the low-strength lower slip device 8 still causes problems. The components will finally be set down when the sealing member 6 reaches the sealing diameter, but the additional hydraulic pressure applied will deploy the lower slip device 8 and the upper slip device simultaneously. When the sealing diameter is reached, a high pressure difference is required to move the sealing member 6 to simultaneously push the fully or partially deployed lower slip device 8 and the deployed sealing member 6, so as to fully deploy the upper slip device 4. When the additional hydraulic pressure is insufficient, the upper slip device 4 will not be fully deployed. After the sealing member 6 and the lower slip device 8 are installed, the packer system can still operate normally, but it will bring additional failure risks. Even if the premature deployment of this lower slip device does not immediately cause fatal damage like the first prior art high-strength lower slip device, the prior art low-strength lower slip device 8 will still encounter different problems - improper setting down of the upper slip device 4 and the need for extremely high pressure.

[0012] Since the lower slip device is very important for the sealing of this type of packer system that sets down and stably bears downhole hydraulic pressure, it is necessary to control the quality and strength of the lower slip device to ensure that the packer system can be easily and reliably triggered at the appropriate part by engaging other components of the lower slip device. For the low-strength lower slip device, while bleeding through the load bypass to prevent the premature deployment of the lower slip device, the proper setting down of the upper slip device can be completed and the upward downhole hydraulic pressure required for setting down can be easily established through the setting piston.

[0013] Various patents have been granted and various publications have been issued for the load bypass components in the packer system. U.S. Patent No. 3,684,010 granted to Young on August 15, 1972, discloses a compression sleeve that will deploy the sealing member and set it on top of the slip device before opening the slip device. The pressure on the compression sleeve will bypass the slip device. U.S. Patent No. 4,460,040 granted to Boyer on July 17, 1984, discloses an internal member for compressing the seal while delivering the cone to the correct position where it can bypass the slip 70. In U.S. Patent No. 2,338,326 granted to Green on January 4, 1944, the mandrel can pass through the seal, the cone and the slip, so as to open the slip by engaging the collar with the cone. The mandrel 13 can be used as a load bypass of the prior art. U.S. Patent No. 3,374,839 granted to Lebourg on March 26, 1968 shows another bypass mandrel.

[0014] For various aspects of this technology, see other references. U.S. Patent No. 6378606, issued to Swor et al. on April 30, 2022, describes a conventional packer system that sets by hydraulic pressure. It only includes a lower slip device and a sealing member, and the upper slip device is completely removed, so its sealing and support only rely on the seal and the lower slips. The cone for deploying the "lower" slips does not seat the sealing member. U.S. Patent No. 10392897, issued to Wise et al. on August 27, 2019, and U.S. Patent No. 10450827, issued to Wise et al. on October 22, 2019, both describe methods for retrieving a packer by overcoming the differential pressure of at least one slip released by shear pins. Prior art patents can rely on differential pressure, but the components are used differently (e.g., for retrieval). U.S. Patent No. 10989015, issued to Roy on April 27, 2021, only adds a degradable slip or wedge / cone as a release component. The releasable slip uses prior art, but a suitable degradation material needs to be selected to release the slip from the retracted position to the deployed position. Summary of the Invention

[0015] An object of the present invention is to provide a packer system that can be used to isolate a production zone from a non-production zone in a wellbore for downhole operations.

[0016] An object of the present invention is to provide a packer system that can be set at a specific location in a wellbore by downhole hydraulic pressure.

[0017] An object of the present invention is to provide a packer system that can prevent premature deployment of the lower slip device of the packer system by a setting sleeve.

[0018] Another object of the present invention is to provide a packer system that has a lower cone, a sealing member, and an upper cone that can transfer a load to the packer system without a lower slip device.

[0019] Another object of the present invention is to provide a packer system that has a sealing member in the set position and an upper slip device in the deployed position before the lower slip device is deployed.

[0020] Another object of the present invention is to provide a packer system that has a setting sleeve that removably engages a setting piston and can be used to apply pressure on the lower cone.

[0021] Another object of the present invention is to provide a packer system that has a setting sleeve that removably engages a setting piston and can be used to apply pressure on the lower cone, the sealing member, and the upper cone.

[0022] Another object of the present invention is to provide a packer system equipped with a setting sleeve that has a bypass position relative to a setting piston for transferring a load through a lower slip assembly and to a lower cone.

[0023] Another object of the present invention is to provide a packer system that has a release position relative to a setting piston for applying pressure on a lower slip assembly to deploy the lower slip assembly.

[0024] Another object of the present invention is to provide a packer system that has a setting sleeve for distributing downhole hydraulic pressure to a lower cone, a sealing member, an upper cone, and a lower slip assembly.

[0025] Another object of the present invention is to provide a packer system in which the setting sleeve distributes downhole hydraulic pressure to a lower cone, a sealing member, an upper cone, a release member on the setting sleeve for bypassing the lower slip assembly, and the lower slip assembly itself.

[0026] The above and other objects and advantages of the present invention will become apparent by reading the accompanying specification, drawings, and claims.

[0027] Embodiments of the present invention include a packer system having a packer mandrel, an upper support ring or metering ring, a sealing member, an upper slip assembly, an upper cone, a lower cone, a lower slip assembly, a setting sleeve, and a setting piston. The sealing member includes a run-in position having a run-in diameter and a setting position having a setting diameter. The setting diameter needs to be greater than the run-in diameter for wellbore sealing, and the packer system needs to reach the run-in diameter to be deployed through the wellbore to a desired location. When the sealing member is in the run-in position, the upper slip assembly will be in an upper slip initial position. The upper slip initial position is a retracted position of the upper slip assembly for the retracted packer system during deployment through the wellbore. The upper slip assembly will make a sliding engagement with the upper cone between the upper slip initial position and an upper slip engagement position. When the sealing member is in the setting position, the upper slip engagement position will become a deployed position. When the sealing member is in the run-in position, the lower slip assembly will be in a lower slip initial position. The lower slip initial position is a retracted position of the lower slip assembly for the retracted packer system during deployment through the wellbore. The lower slip assembly will make a sliding engagement with the lower cone between the lower slip initial position and a lower slip engagement position. When the sealing member is in the setting position, the lower slip engagement position will become a deployed position.

[0028] In the present invention, the setting sleeve is mounted on the packer mandrel between the packer mandrel and the lower slip assembly. The setting sleeve will engage in a removable manner with a setting piston driven by downhole hydraulic pressure. When the setting sleeve engages with the setting piston, the setting sleeve will have a bypass position relative to the setting piston, and when the setting sleeve is separated from the setting piston, it will have a release position relative to the setting piston.

[0029] When the setting piston is in the bypass position, it will apply pressure to the setting sleeve, and then the setting sleeve will apply pressure to the lower cone. The lower slip assembly is located between the setting piston and the lower cone. Then, the setting piston will apply pressure to the lower cone adjacent to the sealing member and the upper cone on the setting sleeve. When the setting sleeve is in the bypass position, all the pressure of the setting piston will no longer act on the lower slip assembly. When the setting sleeve is in the bypass position, the load of the setting piston will bypass the lower slip assembly to reduce the risk of premature deployment.

[0030] When the setting sleeve is in the release position, the setting piston will apply pressure to the lower slip assembly through the setting sleeve, rather than to the lower cone, the sealing member, and the upper cone. The lower slip assembly is still in sliding engagement with the lower cone between the initial position of the lower slip and the engagement position of the lower slip. The setting piston can now deploy the lower slip assembly to the engagement position of the lower slip.

[0031] The setting sleeve embodiment of the present invention includes a release member located at the setting piston end of the setting sleeve for separating the setting piston from the setting sleeve. The release member such as a shear pin, a shear screw, or a shear ring can determine the removable engagement relationship between the setting piston and the setting sleeve. The release member will transition the setting sleeve from the bypass position to the release position. When the sealing member is in the setting position and the upper slip assembly is in the engagement position of the upper slip, the lower slip assembly will become the last deployable component to be set in the wellbore in the packer system. The release member will drive the setting sleeve to transition from the bypass position to the release position to deploy the lower slip assembly.

[0032] In this embodiment, all the pressure of the setting piston will act on multiple components (setting sleeve, release member, lower cone, sealing member, upper cone) simultaneously. At the bypass position, only a part of the pressure of the setting piston will act on the release member. Therefore, the release member will not break prematurely. When the sealing member is in the setting position and the upper slip assembly is in the engagement position of the upper slip, the above components can be locked in the wellbore. All the pressure of the setting piston will act more on the release member. Finally, as the sealing member and the upper slip assembly are locked in the wellbore, the pressure applied by the setting piston on the release member will gradually increase. After the pressure increases, it is now sufficient to break the release member. The above pressure increase phenomenon will only occur on the release member when the sealing member and the upper slip assembly are deployed and locked.

[0033] The present invention also includes an upper support ring or a metering ring, which has an unlocking position relative to the sealing member and a locking position relative to the sealing member on the packer mandrel. The upper support ring cooperates with the upper cone to deploy the upper slip assembly when the setting sleeve is in the bypass position.

[0034] Embodiments of the packer system also include a hydraulic pressure applying device for setting the piston. The lower support ring or lower metering ring, upper piston, lower mandrel, upper piston housing, lower piston, and bottom nipple may all generate downhole hydraulic pressure involved in the present invention.

[0035] The present invention includes a method of performing downhole operations using a packer system. The packer system will be deployed into the wellbore in its minimum diameter. The setting sleeve will be in the bypass position. After the packer system reaches the desired location within the wellbore, the setting piston will apply pressure to the setting sleeve. The setting sleeve will apply pressure to the lower cone, sealing member, and upper cone through the setting piston. When pressure is applied to the setting sleeve in the bypass position, the sealing member and upper slip device will deploy. After the sealing member and upper slip device deploy, the setting piston will separate from the setting sleeve to place the setting sleeve in the release position. The setting piston will now engage the lower slip device to apply pressure to the lower slip device 80, causing it to slide from the lower slip initial position to the lower slip engaged position. When the three deployable components (upper slip device, sealing member, and lower slip device) are all deployed, downhole operations can be performed in the wellbore.

[0036] Another embodiment of the method of the present invention includes the step of separating the setting piston from the setting sleeve when the setting sleeve has a release component. The piston may apply shear pressure to the release component.

[0037] The present invention provides a packer system for isolating a production zone from a non-production zone in a wellbore to perform downhole operations. The packer system and method can set the packer system at a specific location within the wellbore without premature deployment, thus ensuring that the packer system can be set and locked in the appropriate intended location to perform various downhole operations. BRIEF DESCRIPTION OF THE DRAWINGS

[0038] Figure 1 is a cross-sectional view of a packer system using the prior art, which shows the cross-section A in dashed brackets and shows the lower slip device in the retracted position.

[0039] Figure 2 is Figure 1 an exploded cross-sectional view of the shown cross-section A.

[0040] Figure 3 is Figure 1 a cross-sectional view of the packer system using the prior art as shown, which shows the process of the lower slip device transitioning from the retracted position to the deployed position.

[0041] Figure 4 is Figure 1 a cross-sectional view of the packer system using the prior art as shown, which shows the lower slip device in the deployed position.

[0042] Figure 5 is a cross-sectional view and a front view of an embodiment of the packer system of the present invention, wherein the sealing member is in the run-in position and the setting sleeve is in the bypass position.

[0043] Figure 6 is Figure 5 an enlarged cross-sectional view and a front view of a part of the embodiment of the packer system shown.

[0044] Figure 7 is Figure 5 an enlarged cross-sectional view and a front view of the remaining part of the embodiment of the packer system shown.

[0045] Figure 8 is another cross-sectional view and a front view of an embodiment of the packer system of the present invention, wherein the sealing member is in the run-in position and the setting sleeve is in the bypass position. Figure 8 also includes an enlarged cross-sectional view of the setting sleeve, the lower slip device, the lower cone, and the setting piston in the bypass position of the present invention.

[0046] Figure 9 is Figure 8 an enlarged cross-sectional view corresponding to the enlarged cross-sectional view shown, which shows an alternative embodiment of the setting sleeve in the bypass position.

[0047] Figure 10 is another enlarged cross-sectional view and a front view of the setting sleeve, the lower slip device, the lower cone, and the setting piston in the bypass position of the present invention.

[0048] Figure 11 is an enlarged front view of the setting sleeve in the bypass position, the sealing member in the set position, and the upper slip device in the upper slip engagement position. The lower slip device can transition from the initial lower slip position to the lower slip engagement position.

[0049] Figure 12 is an enlarged front view of the setting sleeve in the release position, the sealing member in the set position, the upper slip device in the upper slip engagement position, and the lower slip device in the lower slip engagement position. Detailed Description

[0050] Figures 5 to 12Shows an embodiment of the packer system 10 of the present invention. The packer system 10 includes a packer mandrel 20, an upper support or metering ring 30, a seal member 40, an upper slip device 50, an upper cone 60, a lower cone 70, a lower slip device 80, a setting sleeve 90, and a setting piston 100. The packer mandrel 20 has an upper mandrel end 22 and a lower mandrel end 24, and the upper support ring 30 is placed at the upper mandrel end 22. The seal member 40 has an upper seal end 42 and a lower seal end 44 opposite the upper seal end. The seal member 40 includes a running-in position with a running-in diameter and a setting position with a setting diameter. The setting diameter needs to be greater than the running-in diameter for wellbore sealing, and the packer system 10 needs to reach the running-in diameter to be deployed through the wellbore to the desired location.

[0051] The upper slip device 50 has an upper support ring end 52 and an upper cone end 54 opposite the upper support ring end. The upper slip device 50 is located between the upper support ring 30 and the upper seal end 42 of the seal member 40. When the seal member 40 is in the running-in position, the upper slip device 50 will be in the upper slip initial position. The upper slip initial position is the retracted position of the upper slip device 50 for the retracted packer system 10 during wellbore deployment.

[0052] The upper cone 60 has an upper slip end 62 and an upper seal end 64 opposite the upper slip end 62. The position of the upper seal end 64 can ensure that pressure can be applied to the upper seal end 42 of the seal member 40. The upper slip device 50 will make a sliding engagement with the upper cone 60 between the upper slip initial position and the upper slip engagement position. When the seal member 40 is in the setting position, the upper slip engagement position will become the deployed position.

[0053] The lower cone 70 has a lower slip end 72 and a lower seal end 74 opposite the lower slip end 72. The position of the lower seal end can ensure that pressure can be applied to the lower seal end 44 of the seal member 40.

[0054] The lower slip device 80 has a lower setting sleeve end 82 and a lower cone end 84 opposite the lower setting sleeve end 82. When the seal member 40 is in the running-in position, the lower slip device 80 will be in the lower slip initial position. The lower slip initial position is the retracted position of the lower slip device 80 for the retracted packer system 10 during wellbore deployment. The lower slip device 80 will make a sliding engagement with the lower cone 70 between the lower slip initial position and the lower slip engagement position. When the seal member 40 is in the setting position, the lower slip engagement position will become the deployed position.

[0055] Figures 5 to 12 Shows the setting sleeve 90 having a lower tapered engagement end 92 and a setting piston end 94 opposite the lower tapered engagement end 92. The setting sleeve 90 is mounted on the packer mandrel 20 between the packer mandrel 20 and the lower slip device 80.

[0056] In the present invention, downhole hydraulic pressure will drive a setting piston 100 having a setting end 102 removably engaged with the setting piston end 94 of the setting sleeve 90 to ensure that pressure can be applied to the lower cone 70 on the setting sleeve 90. The lower slip device 80 is located between the setting piston 100 and the lower cone 70.

[0057] Figures 5 to 11 The setting sleeve 90 is shown in a bypass position relative to the setting piston 100, wherein the setting piston end 94 of the setting sleeve 90 is removably engaged with the setting piston 100. Figure 12 The setting sleeve 90 is shown in a release position relative to the setting piston 100, wherein the lower slip device 80 is engaged with the setting piston 100. As Figures 5 to 11 shown, when the setting sleeve 90 is in the bypass position, the setting piston 100 will apply pressure to the lower cone 70, the sealing member 40, and the upper cone 60 on the setting sleeve 90. All the pressure of the setting piston 100 will no longer act on the lower slip device 80. When the setting sleeve 90 is in the bypass position, the load of the setting piston 100 will bypass the lower slip device 80 to reduce the risk of premature deployment of the slip device 80. The lower pressure difference will ensure that the sealing member 40 can transition to the setting position, while the upper slip device 50 can transition to the upper slip engagement position, which is no longer deployed by the prior art partially or fully deployed lower slip device.

[0058] As Figure 12 shown, when the setting sleeve 90 is in the release position, the setting piston 10 will apply pressure to the lower slip device 80 through the setting sleeve 90, and will not apply pressure to the lower cone 70, the sealing member 40, and the upper cone 60. The lower slip device 80 will make a sliding engagement with the lower cone 70 between the lower slip initial position and the lower slip engagement position. When the sealing member 40 is in the setting position, the lower slip engagement position will become the deployment position. In addition, the pressure difference driving the deployment of the lower slip device 80 is lower than the prior art pressure level because the lower slip device 80 no longer needs to be so strong and pressure-resistant to avoid premature deployment. The packer system 10 described in the present invention only requires a smaller pressure to achieve setting, thereby reducing the risk of premature deployment. The lower slip device 80 makes a sliding engagement with the setting sleeve 90 in the release position. The lower slip device 80 can slide from the lower slip initial position to the lower slip engagement position above the setting sleeve 90 and the lower cone 70.

[0059] In an embodiment where the setting sleeve 90 is in the bypass position, the setting piston end 94 of the setting sleeve 90 is removably engaged with the setting piston 100 to ensure that pressure can be applied to the lower cone 70, the sealing member 40, and the upper cone 60 on the setting sleeve 90 through the lower slip device 80. The setting sleeve 90 extends through the lower slip device 80 to ensure that the external force applied by the setting piston 100 does not act on the lower slip device 80. The setting sleeve 90 is installed around the packer mandrel 20, and the lower slip device 80 is installed around the setting sleeve 90. In this concentric relationship, the pressure on the setting sleeve 90 bypasses the lower slip device 80. The present invention includes the concentric relationship and other physical relationships between the lower slip device 80 and the setting sleeve 90 to ensure that the load of the setting piston 100 can bypass the lower slip device 80.

[0060] Figures 8 to 12 An embodiment of the packer system 10 is shown, in which the setting sleeve 90 includes a release member 96 on the setting piston end 94 to ensure that the setting piston 100 can be separated from the setting sleeve 90. Figure 8 and Figures 10 to 12 A shear pin 98 or a shear screw is shown as the release member 96. Figure 9 A shear ring 99 is shown as the release member 96. The release member 96 will ensure that the setting sleeve 90 can transition from the bypass position to the release position. The lower slip device 80 must ultimately expand to the lower slip engagement position to ensure that the packer system 10 can be fully set at the desired location in the wellbore. To expand the lower slip device 80, pressure still needs to be applied through the setting piston 100. When the sealing member 40 is in the set position and the upper slip device 50 is in the upper slip engagement position, the lower slip device 80 will be the last component that needs to be set in the wellbore. The release member 96 can transition the setting sleeve 90 from the bypass position to the release position.

[0061] In this embodiment, the setting sleeve 90 in the bypass position relative to the setting piston will apply the pressure of the setting piston 100 to the release member 96, the setting sleeve 90, the lower cone 70, the sealing member 40, and the upper cone 60. All the pressure of the setting piston 100 will act on multiple components simultaneously. Only a part of the pressure of the setting piston 100 will act on the release member 96 in the bypass position. Therefore, the release member 96 will not break prematurely. The sealing member 40 in the setting position and the upper slip device 50 in the upper slip engagement position will bear the pressure of the setting piston 100 because these components are now locked in the wellbore. All the pressure of the setting piston 100 will act more on the release member 96. As the sealing member 40 and the upper slip device 50 are locked in the wellbore, the pressure applied by the setting piston 100 on the release member 96 will gradually increase. After the pressure increases, it is now sufficient to break the release member 96. The above pressure increase on the release member 96 will occur only when the sealing member 40 and the upper slip device 50 are deployed and locked. The risk of premature separation of the setting sleeve 90 and the setting piston 100 is significantly reduced and can be controlled not to be earlier than when the packer system 10 is ready for the lower slip device 80 (prematurely, accidentally, or deliberately) to deploy.

[0062] Figure 5 , Figure 6 , Figure 8 and Figure 12 Shows an embodiment of the upper support ring 30 or the metering ring, which has an unlocking position relative to the sealing member 40 and a locking position relative to the sealing member 40 on the packer mandrel 20. The packer mandrel 20 will hold the upper support ring 30 in place on the packer mandrel 20, while the sealing member 40 and the upper slip device 50 will move relative to the upper support ring 30. The pressure exerted by the setting piston 100 on the setting sleeve 90 will push the upper cone 60 into the upper slip device 50 because the upper support ring 30 will hold the upper slip device 50 in place relative to the packer mandrel 20. When there is pressure, the upper slip device 50 cannot move along the packer mandrel 20; therefore, the upper slip device 50 must deploy from the upper slip initial position to the upper slip engagement position.

[0063] Figure 5 , Figure 6 and Figure 8 Shows the unlocking position when the sealing member 40 is in the running-in position and the upper slip device 50 is in the upper slip initial position. As Figure 12As shown, the locking position is closer to the sealing member 40 than the unlocking position. When the sealing member 40 is in the setting position and the upper slip device 50 is in the upper slip engagement position, the upper support ring 30 will be in the locking position. In the present invention, when the lower slip device 80 is in the lower slip engagement position, the setting sleeve 90 is in the release position, the lower slip device 80 is in the lower slip initial position, and the setting sleeve 90 is in the bypass position, the upper support ring 30 will be in the locking position. When the sealing member 40 is in the setting position, the setting sleeve 90 will separate from the setting piston 100 and then transition to the release position corresponding to the upper support ring 30 in the locking position.

[0064] The packer system 10 may further include a hydraulic pressure applying device for the setting piston 100. The downhole hydraulic pressure described in the present invention can be generated by the hydraulic pressure applying device, wherein the hydraulic pressure applying device includes a lower support ring 110 or a lower metering ring, an upper piston 122, a lower mandrel 114, an upper piston housing 116, a lower piston 118, and a bottom nipple 120. The lower support ring 110 is installed on the packer mandrel 20 and connected to the setting piston 100. The upper piston 112 engages with the setting piston 100 and is supported on the lower support ring 110. The lower mandrel 114 is connected to the lower mandrel end 24 of the packer mandrel 20. The upper piston housing 116 is installed around the upper piston 112, the packer mandrel 20, and the lower mandrel 114. The lower piston 118 is installed around the lower mandrel to ensure that it can cooperate with the upper piston 112 to drive the setting piston 100 in the chamber formed by the upper piston housing 116. The bottom nipple 120 is fixed on the lower mandrel 118 to ensure that the drill string can continue to be hung. The hydraulic pressure applying device described in the present invention will drive the setting piston 100 to set the packer system 10 at the desired position in the wellbore.

[0065] Embodiments of the present invention include a method for performing downhole operations using a packer system 10. The method includes lowering the packer system 10 into a wellbore when the sealing member 40 is in the run-in position, the upper slip device 50 is in the upper slip initial position, the lower slip device 80 is in the lower slip initial position, and the setting sleeve 90 is in the bypass position. The packer system 10 has its minimum diameter in this configuration to ensure smooth passage through the wellbore. The method includes placing the packer system 10 at a desired location within the wellbore. At the desired location, the setting piston 100 applies pressure on the setting sleeve 90. The setting sleeve 90 applies pressure on the lower cone 70, the sealing member 40, and the upper cone 60 through the setting piston 100. The sealing member 40 expands from the run-in position to the set position. The upper slip device 50 slides from the upper slip initial position to the upper slip engaged position. The pressure applied on the upper cone 60 by the setting sleeve 90 pushes the upper cone 60 into the upper slip device 50 to expand the upper slip device 50. The setting sleeve 90 remains in the bypass position. After the sealing member 40 is in the set position and the upper slip device 50 is in the upper slip engaged position, the setting piston 100 separates from the setting sleeve 90 to place the setting sleeve 90 in the release position. The setting piston 100 engages the lower slip device 80 to apply pressure on the lower slip device 80 when the setting sleeve 90 is in the release position. The lower slip device 80 now slides from the lower slip initial position to the lower slip engaged position relying on the pressure applied by the setting piston 100. Embodiments of the present invention also include the step of performing downhole operations when the sealing member 40 is in the set position, the upper slip device 50 is in the upper slip engaged position, and the lower slip device 80 is in the lower slip engaged position.

[0066] Another embodiment of the method of the present invention includes Figures 8 to 12 the setting sleeve 90 shown consisting of a release member 96 on the setting piston end 94. In this embodiment of the method, the step of separating the setting piston 100 from the setting sleeve 90 includes shearing the release member 96.

[0067] Another embodiment of the method of the present invention includes Figure 5 and Figure 8The hydraulic pressure application device shown, which is composed of a lower support ring 110 or a lower metering ring, an upper piston 122, a lower mandrel 114, an upper piston housing 116, a lower piston 118, and a bottom nipple 120. The lower piston 118 is installed around the lower mandrel 114 to ensure that it can cooperate with the upper piston 112 to drive the setting piston 100 in the chamber formed by the upper piston housing 116. The step of applying pressure on the setting sleeve 90 further includes the steps of establishing downhole hydraulic pressure through the upper piston 112 and the lower piston 118 and applying hydraulic pressure on the setting piston 100. The upper piston 112 and the lower piston 118 cooperate to generate downhole hydraulic pressure on the setting piston 100. The object of the present invention is to provide a packer system for isolating a production layer from a non-production layer in a wellbore for downhole operations.

[0068] The present invention provides a packer system for isolating a production layer from a non-production layer in a wellbore for downhole operations. The packer system and method reliably set the packer system at a specific location in a controlled and planned manner. The packer system can be set and locked at a specific location for performing various downhole operations. The packer system is set by downhole hydraulic pressure. The setting sleeve of the packer system has a bypass position and a release position to prevent the premature deployment of the lower slip device of the packer system. In the present invention, the lower slip device can now avoid the fatal premature deployment of the "high-strength" lower slip device of the prior art. The present invention also avoids the extremely high pressure difference required for the deployment of the sealing component and the upper slip device due to the deployment of the "low-strength" lower slip device in the prior art. The setting sleeve of the present invention transfers the load to the lower cone, the sealing member, and the upper cone of the packer system at the bypass position, rather than on the lower slip device. The sealing member can be deployed to the setting position, and the upper slip device can be deployed to the upper slip engagement position or the deployment position. The setting piston transfers the load to the lower cone through the lower slip device. Then, when the setting sleeve transitions from the bypass position relative to the setting piston to the release position, the lower slip device can be deployed.

[0069] The setting sleeve is removably engaged with the setting piston to apply pressure to the lower cone, the sealing member, and the upper cone in the bypass position. The setting sleeve will disengage from the setting piston in the release position to drive the setting piston to engage the lower slip device. Then, the setting piston can apply pressure to the lower slip device to deploy the lower slip device. The downhole hydraulic pressure can now be reliably distributed to the lower cone, the sealing member, the upper cone, and then to the lower slip device. The release component on the setting sleeve will ensure that the load can bypass the lower slip device and be transmitted back to deploy the lower slip device. The present invention allows the lower slip device to be manufactured using more standardized and conventional materials without the use of special strengthening materials. The lower slip device and the upper slip device can be made of the same material, and the lower slip device used to achieve the hydraulic setting of the packer system does not require the use of special materials. In addition, the present invention also avoids the higher differential pressure required for the "low-strength" lower slips in the prior art. The lower slip device is no longer fully or partially deployed. When the sealing member and the upper slip device are deployed, they can be deployed through the fully or partially deployed lower slip device without applying additional pressure. Depending on the relationship between the setting sleeve and the setting piston, the sealing member and the upper slip device will be deployed before the pressure of the setting piston engages the lower slip device and any release components. The present invention solves the problem of premature deployment of the lower slip device in the absence of the high differential pressure required in the prior art.

[0070] The foregoing disclosure and description of the present invention are illustrative and explanatory of the present invention. Various changes can be made to the details of the illustrated structures, configurations, and methods without departing from the true spirit of the present invention.

Claims

1. A packer system, comprising: A packer mandrel having an upper mandrel end and a lower mandrel end; An upper support ring located at the upper mandrel end; A sealing member having an upper sealing end and a lower sealing end opposite the upper sealing end, the sealing member including a run-in position having a run-in diameter and a setting position having a setting diameter greater than the run-in diameter for wellbore sealing; An upper slip device having an upper support ring end, an upper cone end opposite the upper support ring end, and an upper slip initial position, wherein the sealing member is in the run-in position and the upper slip device is located between the upper support ring and the upper sealing end; An upper cone having an upper slip end and an upper sealing end opposite the upper slip end, the upper sealing end being positioned to ensure pressure can be applied to the sealing member at the upper sealing end, the upper slip device being in sliding engagement with the upper cone and having an upper slip engagement position when the sealing member is in the setting position; A lower cone having a lower slip end and a lower sealing end opposite the lower slip end, the lower sealing end being positioned to ensure pressure can be applied to the sealing member at the lower sealing end; A lower slip device having a lower setting sleeve end, a lower cone end opposite the lower setting sleeve end, and a lower slip initial position when the sealing member is in the run-in position, the lower slip device being in sliding engagement with the lower cone and having a lower slip engagement position when the sealing member is in the setting position; A setting sleeve having a lower cone engagement end and a setting piston end opposite the lower cone engagement end, the setting sleeve being mounted on the packer mandrel between the packer mandrel and the lower slip device; And A setting piston having a setting end removably engaged with the setting piston end of the setting sleeve to ensure pressure can be applied to the lower cone on the setting sleeve, the lower slip being located between the setting piston and the lower cone.

2. The packer system according to claim 1, wherein the setting sleeve has a bypass position relative to the setting piston, and the setting piston end of the setting sleeve is removably engaged with the setting piston to ensure that pressure can be applied to the lower cone, the sealing member, and the upper cone on the setting sleeve, and wherein the setting sleeve has a release position relative to the setting position, and the lower slip device is engaged with the setting piston to ensure that pressure can be applied to the lower slip device so as to make a sliding engagement with the lower cone at the lower slip engagement position.

3. The packer system according to claim 2, wherein the setting sleeve has the bypass position relative to the setting piston, and the setting piston end of the setting sleeve is removably engaged with the setting piston to ensure that pressure can be applied to the lower cone, the sealing member, and the upper cone on the setting sleeve through the lower slip device.

4. The packer system according to claim 1, wherein the setting sleeve includes a release component at the setting piston end to ensure that the setting piston can be separated from the setting sleeve when the sealing member is in the setting position and the upper slip device is in the upper slip engagement position.

5. The packer system according to claim 4, wherein the release component includes a shear pin.

6. The packer system according to claim 4, wherein the release component includes a shear ring.

7. The packer system according to claim 4, wherein the setting sleeve has the bypass position relative to the setting piston, and the setting piston end of the setting sleeve is removably engaged with the setting piston to ensure that pressure can be applied to the lower cone, the sealing member, the upper cone, and the release component on the setting sleeve simultaneously.

8. The packer system according to claim 1, wherein the upper support ring has an unlocking position relative to the sealing member and a locking position relative to the sealing member on the packer mandrel, the locking position being closer to the sealing member than the unlocking position, the upper support ring being in the locking position, the sealing member being in the setting position, and the upper slip device being in the upper slip engagement position.

9. The packer system according to claim 8, wherein the upper support ring is in the locking position, the lower slip device is in the lower slip engagement position, and the setting sleeve is in the release position.

10. The packer system according to claim 8, wherein the upper support ring is in the locking position, the lower slip device is in the lower slip initial position, and the setting sleeve is in the bypass position.

11. The packer system according to claim 1, further comprising: a hydraulic device for the setting piston.

12. The packer system according to claim 11, wherein the hydraulic pressure applying device comprises: A lower support ring mounted on the packer mandrel and connected to the setting piston; An upper piston engaged with the setting piston and supported on the lower support ring; A lower mandrel connected to the lower mandrel end; An upper piston housing around the upper piston, the packer mandrel, and the lower mandrel; A lower piston around the lower mandrel to ensure cooperative driving of the setting piston with the upper piston; And A bottom nipple fixed to the lower mandrel.

13. A downhole operation method, comprising the following steps: Running the packer system according to claim 1 in a wellbore, wherein the sealing member is in the run-in position, the upper slip device is in the upper slip initial position, the lower slip device is in the lower slip initial position, and the setting sleeve is in the bypass position; Placing the packer system at a specific location within the wellbore; Applying pressure to the setting piston on the setting sleeve; Applying pressure to the lower cone, the sealing member, and the upper cone through the setting sleeve; When the setting sleeve is in the bypass position, using the pressure applied through the setting sleeve and the lower cone to expand the sealing member from the run-in position to the setting position; When the setting sleeve is in the bypass position, the upper slip device is slid from the upper slip initial position to the upper slip engagement position by the pressure applied through the setting sleeve, the lower cone, and the sealing member; When the sealing member is in the setting position and the upper slip device is in the upper slip engagement position, the setting piston is separated from the setting sleeve to ensure that the setting sleeve can be placed in the release position; When the setting sleeve is in the release position, pressure is applied to the lower slip device through the setting piston; And When the setting sleeve is in the release position, the lower slip device is slid from the lower slip initial position to the lower slip engagement position by the pressure applied by the setting piston.

14. The method according to claim 13, further comprising the following steps: When the sealing member is in the setting position, the upper slip device is in the upper slip engagement position, and the lower slip device is in the lower slip engagement position, the lower slip device is slid from the lower slip initial position to the lower slip engagement position by the pressure applied by the setting piston, and then downhole operations are performed.

15. The method according to claim 13, wherein the setting sleeve comprises a release member at the setting piston end, and The step of separating the setting piston from the setting sleeve includes: Shear the release component.

16. The method according to claim 13, wherein the step of applying pressure to the lower cone by the setting piston on the setting sleeve includes: Establish downhole hydraulic pressure; And Apply the hydraulic pressure on the setting piston.

17. The method according to claim 16, wherein the packer system further comprises: A lower support ring mounted on the packer mandrel and connected to the setting piston; An upper piston that engages with the setting piston and is supported on the lower support ring; A lower mandrel connected to the lower core shaft end; An upper piston housing around the upper piston, the packer mandrel, and the lower mandrel; A lower piston around the lower mandrel to ensure that the setting piston can be driven in cooperation with the upper piston; And A bottom nipple fixed on the lower mandrel, and Wherein the step of establishing downhole hydraulic pressure includes the following steps: Establish downhole hydraulic pressure through the lower piston and the upper piston.

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