Method and apparatus for disconnecting completion string sections

Abstract

The invention relates to a method and apparatus that can withstand high forces and capable of disconnect floating seals within a polish bore receptacle in a controlled manner by applying annulus pressure. This invention provides reliable and efficient solutions for positioning assembly downhole and separating completion string sections that facilitate wellbore operations while minimizing risk.

Description

CROSS-REFERENCE TO RELATED APPLICATIONS

[0001] Not applicable.FEDERALLY SPONSORED RESEARCH AND DEVELOPMENT

[0002] Not applicable.JOINT RESEARCH AGREEMENT

[0003] Not applicable.REFERENCE TO A "SEQUENCE LISTING", A TABLE, OR A COMPUTER PROGRAM LISTING APPENDIX SUBMITTTED ON A COMPACT DISC AND AN INCORPORATION- BY-REFERENCE OF THE MATERIAL ON THE COMPACT DISC

[0004] Not applicable.PRIOR ART

[0005] Not applicable.BACKGROUND OF THE INVENTION

[0006] Completion strings are utilized in oil and gas wells to facilitate production and other downhole operations. Traditional methods for disconnecting completion string sections involve complex and time-consuming procedures. There is a need for an improved method and apparatus that enable quicker, safer, and more efficient disconnection of completion string sections.

[0007] Hydrocarbons in global energy demand still significant. The availability and economic viability of oil reservoirs that are relatively shallow in depth are decreasing, these reservoirs have historically been important sources of oil production, but their significance has diminished over time due to factors such as depletion, technological advancements, and changing industry dynamics. Oil companies are drilling more deep wells driven by the pursuit of new reserves, technological advancements, and economic considerations. As technology has advanced, the oil and gas industry has developed the capability to explore and extract hydrocarbons from deeper and more complex reservoirs. This has shifted the industry's focus towards deeper formations that were previously uneconomical to tap.

[0008] Deep oil wells are often designed with telescopic stages to address the challenges and complexities associated with drilling and completing wells at significant depths. Telescopic staging involves the use of multiple casing or tubing strings that overlap and telescope into one another as they are run into the wellbore. This design provides several advantages for drilling and completing deep oil wells. Deep wells designed in telescopic stages have small tubing or narrow diameter tubing in the bottom section for a variety of technical and operational reasons, this represents advantages and addresses specific challenges associated with drilling, completion, and production operations at significant depths. One of the challengers is related to the tubing limitations in completions at extreme depths, such as pressure, tension, burst and collapse ratings.

[0009] To design the well, completion engineers consider in addition to the limitations of the tubing, among other factors, RIG tension limitations. Rig tension is the force exerted on the rig components due to the weight of the drill string, casing, tubing, and other downhole equipment. Exceeding the rig's tension limitations can lead to a range of risks and potential issues that can impact completions operations, rig safety, and overall, well integrity, well control challenges, accidents, and injuries. Understanding rig tension limitations and the associated risks, operators ensure safe and efficient completion operations while protecting well integrity and personnel safety. The design of an oil well completion involves careful planning, engineering, and consideration of various factors to ensure the safe and efficient production of oil or gas from the reservoir. Oil well completion design aims to optimize well productivity while maintaining well integrity and safety. Involved, among others, wellbore trajectory (vertical, deviated, horizontal), casing program, specifying the size, weight, and type of casing strings to be used; the appropriated Completion Equipment Selection such as production tubing, packers, perforated intervals, screens, valves, and safety equipment; selection of materials that can withstand well conditions, including temperature, pressure, and corrosive substances; proper selection of packers to isolate and anchor specific production zones with the appropriate sealing mechanisms, such as elastomeric seals, to prevent fluid leaks between different sections of the wellbore; integration of the use of safety devices, such as subsurface safety valves, to prevent uncontrolled flow of fluids and ensure well integrity; implementation of downhole monitoring tools, such as pressure and temperature gauges, to continuously assess well performance; and the design the tubing configuration to efficiently transport fluids from the reservoir to the surface facilities. This production tubing must handle anticipated loads, pressures, and temperatures.

[0010] During the production stage of a well, various forces act on the tubing, which is the pipe used to transport produced fluids from the reservoir to the surface. These forces can impact the completion system integrity, well performance, and overall production operations. These forces are, tension force as the axial pull exerted on the tubing due to the weight of the production string (tubing and any attached equipment) and the fluid column within the tubing, Pressure forces result from the hydrostatic or applied pressure within the tubing. These forces act radially outward on the tubing walls, creating hoop stress. Bursting Force, collapse, bending and shear forces may arise from tubing movement, deviation, or interactions with downhole tools, as the temperature changes from production operations can cause thermal expansion and contraction of the tubing. Managing these forces is essential for ensuring the safe and efficient production of hydrocarbons from the well. Engineers carefully design the tubing, select appropriate materials, and monitor well conditions to ensure that the tubing can withstand the forces generated during production while maintaining its structural integrity.

[0011] During the design of the oil well completion, is must be chosen in how many trips the completion will be runed. The choice between single-trip and double-trip completions installation methods depends on various factors, including well complexity, cost considerations, operational efficiency, and the specific goals of the completion operation. Each method has its advantages and disadvantages. Here's an overview of both approaches:

[0012] Double-Trip Upper Completions Installation: In a double-trip upper completions installation, the completion components are deployed in two separate trips into the wellbore. The first trip may involve the bottom completion components, such as production packer containing a seal bore receptacle, and other downhole tools bellow as seating nipple, pump out plug and entry guide. This assembly is normally introducing to the desire packer setting depth using a drill pipe that is stronger than the production tubing. The second trip is assembly with a locator with floating seals which is compatible with the seal bore receptacle previously installed in the well, the second trip is deployed using the production tubing and contains others completions components as sliding sleeve, downhole pressure and temperature sensors and sub surface safety valves.

[0013] The advantages of running double-trip upper completions are Flexibility: Double- trip installations allow for greater flexibility in wellbore design and completion strategy, accommodating a wider range of downhole conditions. Complex Wellbores: Double-trip methods are preferred for complex wellbore geometries, multiple zones, or situations where precise placement of completion components are critical.

[0014] The disadvantages are, Increased Rig Time: Double-trip installations require additional trips in and out of the wellbore, potentially leading to increased rig time and higher costs. Operational Complexity: Multiple trips and additional handling of equipment can increase operational complexity and the risk of potential issues during installation.

[0015] Single-Trip Integral Upper Completions Installation: In a single-trip completions installation, all completion components are assembled and deployed in a single run into the wellbore. This approach aims to minimize rig time, reduce operational complexity, and enhance efficiency. Single-trip completions are typically used when the well conditions and completion design allow for straightforward deployment without the need for intermediate steps.

[0016] Advantages are Efficiency: Single-trip installations can save time and reduce costs by eliminating the need for multiple runs in and out of the wellbore. Reduced Risk: Fewer trips in and out of the wellbore mean reduced exposure to potential hazards and risks associated with rig operations. Faster Production: Once the completion is installed, production can begin immediately without the need for additional trips.

[0017] Disadvantages: Complexity: Single-trip completions require careful planning, design, and coordination to ensure all components are properly assembled and deployed in a single run. Limitations: Single-trip installations may not be suitable for wells with complex completion designs, challenging downhole conditions, multiple zones to be completed or RIG tension limitations.

[0018] It is an essential part of all completion procedures, whether it is one or two trips, to verify the operation of the Packer by applying pressure to the annular space. Downhole packers are tested by applying annulus pressure for several important reasons related to their proper functioning, well integrity, and safety. An annulus is the space between two concentric objects, such as the casing and tubing strings in an oil or gas well. Applying pressure to the annulus refers to exerting pressure on the outer side of the packer (outside the tubing) to verify the sealing integrity and as per regulatory authorities often requires thorough testing of downhole equipment, including packers, to ensure well integrity, environmental protection, and safe operations.

[0019] Controlling tubing forces during well production is essential to ensure the structural integrity of the tubing, wellbore stability, and safe and efficient operations. Various methods and techniques are employed to manage these forces and prevent issues such as tubing failure, wellbore damage, and production disruptions. Here are some key strategies to control tubing forces during a well production stage:

[0020] A Double trip completion involves transporting the packer with the drill pipe to the settling depth on the first trip, the packer contains a polished interior and immediately below carries a tube extension with a polished interior that is compatible with seals attached to the locator that would be installed in a second trip along with other accessories and production tubing. Seals are installed in the packer that is already in position, and the locator is left floating so that it can move upward, or contract or expand by moving downward, in accordance with the recommendations from the pipe movement analysis.

[0021] In the case of integral completions of a single trip, the locator is installed inside a polished interior receptacle that is placed on top of the packer. The two pieces of metal are joined by various tension-cutting mechanisms, the most common of which are shear pins (shear screws), shear rings, etc. made from bronze, steel, or some metallurgical alloy. The tension rupture systems should be calibrated based on the analysis of the pipe movement and the limitations that represent a variety of factors such as the limit tension of the RIG, pipe tension limitations, string weight, well geometry, fluids in the well, pressure events, and the total depth of the string, among others.

[0022] In oil or gas wells during the production stage, managing tubing movement is crucial to ensure well integrity, production efficiency, and safe operations. To address these movement considerations and ensure proper tubing behavior, well completions typically involve meticulous well design, proper material selection, and hydraulic modeling. Advanced tools such as expansion seals system and other mechanical systems may also be employed to mitigate tubing movement issues.

[0023] Expansion seals system, also known as polish bore receptacles (PBR) or floating seal assemblies refers to a type of tubing that incorporates a sealing mechanism designed to expand or contract and create a secure seal when forces act on the tubing. This type of tubing is used in applications where a reliable and leak-proof seal is essential. The expansion seal tubing is designed with a built-in mechanism that allows it to expand or contract. This movement creates a tight seal between the tubing locator and the seal bore, preventing leaks or fluid / gas escape. Common seal materials include rubber, elastomers, thermoplastics, and certain metals. The design of expansion seal tubing allows it to withstand varying levels of pressure, ensuring that the seal remains intact even under high- pressure conditions.

[0024] The polish bore receptacle is an element that compensates pipe movement during the production stage of the well to avoid transmitting these forces to the packer. In the case of a two-trip completion design, the installation is performed on the second trip. The one- trip integral completion involves installing the polish bore receptacle on top of the packer and transporting it along with all the completion accessories to the packer's seating position. Shear pins or shear rings that connect the locator with the polished receptacle are used to fix the elements of the polish bore receptacle during descent. It is necessary to lower the polish bore receptacle in an immobile position until the shear pins or shear rings are cut with tension so it can fulfill its function of sealing and compensating the forces of pipe movement. Current Polished Bore Receptacles use shear screws to deploy, this limits the amount of weight that they can handle. This problem also limits the axial loads these systems can withstand during wellbore completion operations. The use of shear screws is a common practice in the completion field since these components are relatively predictable during operation and can operate in HPHT conditions; however, they come with a series of disadvantages that can risk the success of the completion operation.

[0025] The installation in an integral completion represents a technical challenge, the union between the locator that carrier the seals with the polished surface of the seal bore is normally made with shear pins (shear screws) or shear rings, these cutting elements must be calibrated to be cut with tension. The completion operations are becoming more complex over the course of the years, each individual wellbore has specifications to achieve to allow stable production. Sometimes, it's necessary to have more production tubing, accessories or tubing-conveyed perforating are attached bellow the packer, this adds more load to the shear screws on the PBR since this is the component that carries all the weight of the components connected to the external part of the PBR. This means a challenge since the load is strictly limited to the shear value of the shear screws.

[0026] A common completion string consists of a PBR connected to a Packer followed by some type of removable plug. The operator will handle the system trying to reach the desired depth. Once the completion string reaches the objective, direct pressure is applied to activate the Packer; this causes the slips to come out and anchor to the Casing, the activation also causes the elastomer to seal and isolate the annulus of the casing. Once the Packer is fully activated it stays fixed in place, as a result, the external part of the PBR is also fixed in place, since is directly connected to the Packer.

[0027] After verification, the operator pulls out the completion string to cause the shear screws to detach the internal part of the PBR from the external part, allowing the completion string to have free movement without putting all the axial loads on the Packer's slips.

[0028] To determine the cutoff value of the shear elements, engineers should consider that, the packer is hydraulically set, that is, it requires pressure inside the pipe to activate, this pressure is exerted on the entire system and represents a resultant force that impacts all the elements including the locator shear elements. The applied pressure should be enough to actuate the packer but not as high as the shear strength limit of the shear elements (to release the locator and floating seals).

[0029] Deficiency in this calculation or premature cutting of the cutting shear elemtents may result in a detachment of the Seal Bore and its displacement towards the bottom of the hole together with the packer and other accessories connected below the PBR.

[0030] The shear elements should not be too strong due to the tension limitations that are determined by the weight of the string, the weight that is loaded below the packer such as sand control screens or conveyed tubing guns, the capacity of the connections, metallurgy, the tension capacity of the RIG, among others. If the calculation is inaccurate or the shear elements couldn't be cut, there is a risk of exceeding the tension values of any of the connections of the completion assembly, tearing or exceeding the tension capacity of the RIG.

[0031] In short, the shear screw / shear ring cut-off value must be greater than the setting pressure of the packer, greater than the rupture value due to the effect of the force exerted by the pressure on the area of the locator, and less than the maximum tension capacity of the RIG.

[0032] The foregoing represents limitations when selecting the type of completion, a series of operational and safety risks, and possible impact on the environment in case of failure.

[0033] Oil and gas extraction from deeper reservoirs requires the development of technologies that will enable efficient and safe extraction. In the case of deep wells, completions can be either two-trip or integral with one trip, however, both require an element that compensates for the movement of the pipe due to the various forces that lengthen or shorten the tubing in various stages of well production. Since the packer is fixed at a single point, it is necessary to incorporate floating seals to compensate for these pipe movements and ensure that they do not have an impact on the packer. This pipe movement is compensated for by the polish bore receptacle or floating seals, which is installed in the well in combination with the packer and other completion elements. Even though single trip integral completions are more efficient and quicker, one of the biggest risks is the installation and commissioning of the polish bore receptacle. Because the polish bore receptacle release mechanism is designed to operate under tension, the stress applied to the completion assembly while hydraulically activating the packer and releasing the polish bore receptacle creates uncertainty and operational risks. In case the previously described operation fails at some point, the completion string must be retrieved to surface, causing a great loss of profit, and at least doubling the amount of time originally planned to finish the operation.

[0034] There are a variety of factors that determine and limit the tensioning of the string to this depth, including the geometry and construction of the well and the design of the completion. The potential failure of a failure during the release of the PBR could be catastrophic, resulting in costly downtime, equipment damage, and safety hazards.

[0035] The use of shear screws also limits the tension and / or compression that the operator can put on the completion string, this is important because sometimes there are wellbores with high inclination or with high density substances that put high axial loads on the completion string just by trying to reach the desired depth.

[0036] Because of this, design engineers prefer to install two-trip completions even though they are more costly and time-consuming.

[0037] There's also a need to have a system with multiple activation mechanisms as a contingency in case something fails, this is to minimize the risk of having to pull out the completion string and lowering it again to finish the operation, thus, saving money and time.

[0038] As mentioned before, external factors as traction or fluid density may affect the reliability of the shear screws during operation, therefore, there is a further need to provide a system that is capable of withstand higher loads and that is also able to carry more weight than the current systems.SUMMARY OF THE INVENTION

[0039] The disclosed method and apparatus can withstand high axial and pressure forces to deploy the completion assembly downhole safely and disconnect the floating seals within a polish bore receptacle by applying pressure throughout the annulus of the wellbore from the surface to the packing element in a controlled manner. Secondary activation mechanisms are also incorporated into the system.

[0040] The apparatus includes a disconnecting assembly comprising a locking mechanism, a hydraulic actuator, and a control system. The completion string sections are designed with mating interfaces that enable secure disconnection.

[0041] The invention reduces all risk of premature PBR disconnection, increases the amount of weight that can be loaded below the packer, rig tensile capacity, packer settling pressure and other conditions that are limiting to the installation of a single trip integral completion. It is a device that is installed in the upper part of the locator, it is activated with a hydraulic pressure in a controlled and safe way.

[0042] The method involves the following steps:

[0043] Engaging Locking Mechanism: The system is safely assembled on the surface together with the other string sections. It is safely deployed at the desired depth in the hole along with the other elements of the completion.

[0044] Hydraulic Pressure Application: Hydraulic annular pressure is applied to the hydraulic actuator, generating a force that initiates the disconnection process.

[0045] Controlled Separation: The control system regulates the hydraulic pressure to ensure controlled and gradual separation of the completion string sections. The disconnection pressure can be regulated according to the particular characteristics of each application.

[0046] Back up Releasing Mechanism: The systems have two secondary release systems mechanism; one is by applying weight on the tool and the other with rotation to the right.

[0047] Release test: After the separation process has been executed, disconnection test can be performed when tensioning the string and checking the loss of tension.

[0048] Reconnection: The completion string sections cannot be reconnected by reversing the hydraulic pressure. The releasing system has a lock that will leave the locking mechanism deactivated.BRIEF DESCRIPTION OF DRAWINGS

[0049] FIG. 1 is an exploded view of the whole assembly of the apparatus. The names of the components are listed below:

[0050] 1. PBR Top Sub.

[0051] 2. Mandrel.

[0052] 3. Locator Sub.

[0053] 4. Releasing Sleeve.

[0054] 5. Latch.

[0055] 6. Sprin Retainer.

[0056] 7. Snap Ring.

[0057] 8. Spring.

[0058] 9. Compression Sleeve.

[0059] 10. Screw Shear.

[0060] 11. Key.

[0061] 12. V-Seal.

[0062] 13. O'ring A.

[0063] 14. O'ring B.

[0064] 15. Backup Ring A.

[0065] 16. Backup Ring B.

[0066] 17. Shear Screw.

[0067] 18. Set Screw.

[0068] 19. Omega Lock Ring.

[0069] FIG. 2 is a perspective view of the apparatus without any cross-sectional view. It is shown the disconnecting apparatus in it's run position (locked with the PBR Top Sub [1]).

[0070] FIG. 3 shows a cross-sectional view of the apparatus in its rest condition. It could be appreciated that the Latch [5] is locked on the PBR Top Sub [1].

[0071] FIG. 4 shows a cross-sectional view of the apparatus in its hydraulically activated condition. The Releasing Sleeve [4] moved upward allowing the Latch [5] to be free for disconnecting from the PBR Top Sub [1].

[0072] FIG. 5 shows a cross-sectional view of the apparatus in its hydraulically activated condition and illustrates the Latch [5] collapsing due to the tension applied to the production string.

[0073] FIG. 6 shows a cross-sectional view of the apparatus in its compresion activated condition. It is showed the Compression Sleeve [9] and the Releasing Sleeve [4] move upward and the Screw Shear

[10] cut due to the compression.

[0074] FIG. 7 shows a cross-sectional view of the apparatus in its rest condition after compression being applied.

[0075] FIG. 8 shows a cross-sectional view of the apparatus with the Latch [5] released completely by tension.

[0076] FIG. 9 shows a cross-sectional view of the apparatus in its torque activated condition.

[0077] FIG. 10 shows a cross-sectional view of the apparatus with the Latch [5] released completely by torsion.

[0078] FIG. 11 Illustrates a flow diagram of the apparatus activation.DETAILED DESCRIPTION OF THE INVENTION

[0079] The Hydraulic Setting Tool replaces the locator with shear pins commonly used in the conventional PBR systems. This means that the completion operation is to put the production string in the desired depth, then proceeding to activate the Packer. Once the Packer is fixed in position with the Casing, then we can proceed with the operations to activate the Hydraulic Setting Tool.

[0080] The Hydraulic Setting Tool is designed to deploy Polished Bored Receptacles alongside their respective completion tools in a reliable and effective manner.

[0081] To achieve this, it is designed with three different release mechanisms that are described as follows:

[0082] The primary release mechanism (activation by Annular Hydraulic Pressure) is explained below (see FIG. 11):

[0083] The Latch [5] is installed in the upper part of the Mandrel [2], this is an element that has an ACME-type pin thread with a counterclockwise direction. The Latch [5] has slots that allow the expansion of the diameter of the ACME-type thread that has a built- type Collet, that is, with longitudinal grooves with a naturally collapsed position, to increase the diameter of the Collet-type thread, support is placed inside it, in this case, it is the Releasing Sleeve [4], that is, the outer diameter of the ACME-type thread of the Latch [5] is determined by the support exerted by the outer diameter of Releasing Sleeve [4] on the inside of the lower end of the Latch [5], in this way, the Latch [5] serves as a link for the entire system with the box thread in the PBR Top Sub [1] (see FIG. 3).

[0084] The hydraulic chamber is actuated with pressure coming from the outside of the tool due to communication that exists from the annular to the inside of the tool through a slot in the Latch [5]. The Releasing Sleeve [4] is a cylinder with seals inside that maintain the hermeticity to exert the necessary force that allows the cutting of the Shear Screw

[17] , the pressure applied on the ring exceeds the force of the Shear Screw

[17] , in this way the Releasing Sleeve [4] moves upwards and is blocked in its new position by the Snap Ring [7] that is previously collapsed and housed in a slot of the Mandrel [2], when the Releasing Sleeve [4] is displaced to its upper limit it impacts with the Mandrel [2] and simultaneously aligns a slot that allows the Snap Ring [7] to increase its diameter, in this way, the Releasing Sleeve [4] is locked in its upper position without allowing it to return to its initial position (see FIG. 4). When carrying out this displacement upwards, the Releasing Sleeve [4] has simultaneously stopped supporting the increase in diameter of the Latch [5], allowing it to return to its natural collapsed position with a smaller diameter (see FIG. 5), with this the mechanical link with the PBR Top Sub [1] is lost, allowing the Mandrel [2] to move freely up and down without any restriction (see FIG. 8).

[0085] The first backup release mechanism (compression) is explained below: (see FIG. 11).

[0086] Following the packer activation, the external section of the Polished Bore Receptacle must be fixated in place as a result. Once the fixation is verified and the system is in rest condition (see FIG. 3), if the hydraulic annular pressure fails to release the tool successfully, a load must be applied to the tool so the Mandrel [2] is pushed down due to the force applied to the completion string, this movement is transmitted to the Locator Sub [3] that is attached to the Compression Sleeve [9] due to the Screws Shear

[10] radially screwed to the Locator Sub [3]. Since the external part of the PBR is fixed in place, the Compression Sleeve [9] is being pushed against an internal profile of the Retrieving Landing Head [1] as a result, this causes the Screws Shear

[10] to activate (see FIG. 6) displacing the Compression Sleeve [9] into an upper position, pushing the Releasing Sleeve [4] until the Shear Screws

[17] are mechanically activated, displacing it until it impacts with the Mandrel [2] and simultaneously aligns a slot that allows the Snap Ring[7] to increase its diameter, in this way, the Releasing Sleeve [4] is locked in its upper position without allowing it to return to its initial position while the Compression Sleeve [9] stays loose between the Releasing Sleeve [4] and the Locator Sub [3]. The Omega Lock Ring

[19] keeps the sheared parts from the Screws Shear

[10] inside the Compression Sleeve [9] preventing them from falling into the wellbore. With the help of tension applied to the completion string, the Latch [5] collapses due to the lack of support presented in the Releasing Sleeve [4] (see FIG. 7), disconnecting the internal parts of the PBR from the external, allowing the Mandrel [2] to move freely up and down without any restriction (see FIG. 8).

[0087] The second backup release mechanism (Clockwise Torque Turns) is explained below (see FIG. 11):

[0088] Following the packer activation, the external section of the Polished Bore Receptacle must be fixated in place as a result. Once the fixation is verified and the system is in rest condition (see FIG. 3) if the hydraulic annular pressure and the compression release mechanism fail to release the tool successfully, clockwise torque must be applied to the Mandrel [2] while also being pulled back; with the use of the Keys

[11] installed in the Spring[8] area, the torque is transmitted from the Mandrel [2] to the Latch [5] which is designed with a lefthand ACME-type thread to prevent detachment in other components of the wellbore completion tools (see FIG. 9).

[0089] The ACME-type thread profile is designed for easy detachment using tension on the Latch [5], however, reattachment due to compression is not possible, this is to prevent the internal part of the PBR from jamming with the Retrieving Landing Head [1]. This leaves the internal part of the Polished Bore Receptacle unattached from the external part, allowing the Mandrel [2] to move freely up and down without any restriction (see FIG. 10).

[0090] The disclosed method and apparatus offer several advantages, including:

[0091] Quicker Disconnection: The method enables rapid and controlled disconnection of completion string sections, reducing downtime during wellbore operations. It does not require additional steps in the completion procedure, it is activated with annular pressure, the moment of testing the hermeticity of the packing element is used to increase pressure and activate the disconnector.

[0092] RIG tension limitations: The risk of over-stressing during a comprehensive completion of a single trip is reduced / eliminated.

[0093] Hermeticity: The system will maintain hermeticity with high pressure and temperature seals that will not allow the communication of fluids from tubing to annulus or vice versa.

[0094] Burst and collapse: The system resists higher burst and collapse pressures ratings than premium tubing threads.

[0095] Improved Safety: The controlled disconnection process enhances safety by minimizing the risk of sudden or uncontrolled movements.

[0096] Enhanced Efficiency: The apparatus simplifies the disconnection process, improving overall operational efficiency.

[0097] Flexibility: The method and apparatus can be adapted for various completion string configurations and wellbore conditions.

Claims

1. A hydraulic downhole disconnector comprising:a. A locking mechanism configured to securely disengage components of a completion string within a wellbore.b. A hydraulic actuator operatively connected to the locking mechanism; the hydraulic actuator being adapted to generate a controlled force for initiating separation of said components.c. A control system communicatively coupled to the hydraulic actuator; the control system configured to regulate hydraulic pressure to control the disengagement process.d. A tubing interface configured to facilitate connection to a production tubing, wherein said hydraulic downhole disconnector is configured to selectively isolate a section of the completion string.e. A disconnector assembly configured to engage a seal bore within a seal bore seal.f. A locator mechanism integrated within the disconnector assembly; the locator mechanism adapted to establish a precise axial position within the seal bore.g. A release mechanism operatively connected to the disconnector assembly; the release mechanism configured to selectively disengage the disconnector assembly from the seal bore.

2. The downhole disconnector of claim 1, wherein the locking mechanism further comprises a latch assembly configured to securely engage the internal diameter of a seal bore with the locator seal assembly.

3. The downhole disconnector of claim 1, wherein the hydraulic actuator mechanism further comprises a plurality of shear screws, shear rings or burst disks installed in the disconnector assembly, that shears whit hydraulic pressure.

4. The downhole disconnector of claim 1, wherein the hydraulic actuator is responsive to hydraulic pressure changes initiated from the surface in the annulus between the downhole disconnector and the internal diameter of the well casing.

5. The downhole disconnector of claim 1, further comprising a backup mechanical release mechanism operatively connected to the locking mechanism, the backup mechanical release mechanism configured to initiate separation in the event of hydraulic actuator failure.

6. The downhole disconnector of claim 1, further comprising a locking mechanism operatively coupled to the disconnector assembly, the locking mechanism configured to securely engage the seal bore when the disconnector assembly is in the engaged position.

7. The downhole disconnector of claim 1, further comprising a locking mechanism operatively coupled to the disconnector assembly, the locking mechanism configured to securely engage the latch when the disconnector assembly is in the release position.

8. The hydraulic downhole disconnector of claim 1, wherein the control system is programmable to adjust the rate of separation of said components of the completion string.

9. A method for selectively isolating a section of a completion string in a wellbore using the downhole disconnector of claim 1, comprising:a. Engaging the locking mechanism to securely connect the components of the locator seal assembly and the completion string.b. Engaging the disconnector assembly within the seal bore.c. Applying annular hydraulic pressure to the hydraulic actuator to generate a controlled force for initiating disengagement of said components.d. Regulating hydraulic pressure using the control system to control the rate of disengagement.e. Isolating the section of the locator seal assembly from the seal bore extension.

10. The method of claim 9, further comprising initiating separation using the backup mechanical release mechanism in the event of hydraulic actuator failure.

11. The method of claim 9, further comprising locking the disconnector assembly in the releasing position using the locking mechanism.

12. The method of claim 9, further comprising a packer installed bellow the downhole disconnector of claim 1 to provide an annular hermetic area to pressurize from the surface.

13. The method of claim 9, further comprising a connection that equals or exceeds the axial,burst pressure, and collapse stresses of the tubing completion design that carries higher weight below the packer equaling or exceeding the load value of premium production tubing threads.

14. The method of claim 9, further comprising a pressure apply within the annulus of the wellbore from the surface to the sealing element of the packer.

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