Offshore gas well hydraulic control pipeline fixing assembly and speed pipe under-pressure lowering method

Abstract

The invention relates to the technical field of natural gas development, in particular to an offshore gas well hydraulic control pipeline fixing assembly and a speed pipe under-pressure lowering method. The problem that a speed pipe with a hydraulic control pipeline cannot be lowered under pressure in a conventional operation mode is solved, the hydraulic control pipeline can be lowered under pressure whether the hydraulic control pipeline is internally arranged or externally arranged, different fixing modes can be selected according to the actual situation and condition on site, the application range is wider, and the practicability is high. And the control problem of downhole tools of an offshore speed pipe continuous gas lift foam drainage system and the problem of operation under pressure are also solved, and well control safety is guaranteed.

Description

Technical Field

[0001] This invention relates to the field of natural gas development technology, and more specifically, to a fixing assembly for a hydraulic control pipeline in an offshore gas well and a method for pressing down a velocity line. Background Technology

[0002] The continuous gas lift bubble discharge system and method for offshore gas wells using velocity tubing enables continuous and stable production from gas wells that have reached water at different stages. It allows for real-time switching of the production process based on production dynamics, improving the well's drainage capacity, ensuring high production efficiency, and enhancing the recovery rate of offshore gas reservoirs. Offshore gas well operations require high well control. During continuous gas lift bubble discharge using velocity tubing, well control tools must be run downhole, connected to the surface control device via hydraulic control lines. Theoretically, hydraulic control lines can be externally or internally fixed. Internal lines require long-term stability while minimizing throttling effects, and currently, there are no commercially available devices for internally fixed hydraulic control lines on velocity tubing. For external methods, the velocity tubing is integrally formed without external couplings, and traditional fixing methods using strip clamps cannot securely fix the hydraulic control line. Furthermore, the velocity tubing is lowered into the wellbore using an injector chain clamp, and pressure must be controlled during operation using a blowout preventer system, requiring the velocity tubing to operate under pressurized conditions. Under the condition of an external hydraulic control line, the hydraulic control line fixing device, downhole tools, etc., cause a certain change in the outer diameter of the velocity tube, making it impossible to pass through a conventional gate blowout preventer.

[0003] Currently, there are no suitable hydraulic control line fixing devices or components for velocity tubing, making it difficult to run hydraulic control lines for velocity tubing in offshore gas wells under pressure. The fixing and installation of hydraulic control lines is a critical step in ensuring downhole safety during continuous bubble venting and gas lift operations in offshore gas wells. Therefore, there is an urgent need for the design of corresponding devices to control downhole tools for velocity tubing, while simultaneously meeting the requirements for running variable-diameter tools under pressure, enabling continuous bubble venting and gas lift operations while also satisfying the well control requirements of offshore gas wells. Summary of the Invention

[0004] To overcome the shortcomings of existing technologies where it is difficult to install offshore gas well velocity lines with hydraulic control lines under pressure, this invention provides a fixed assembly for offshore gas well hydraulic control lines and a method for installing velocity lines under pressure, enabling the installation of offshore gas well velocity lines with hydraulic control lines under pressure and meeting production requirements.

[0005] To solve the above-mentioned technical problems, the technical solution adopted by the present invention is: a hydraulic control pipeline fixing assembly for offshore gas wells, comprising: an inner ring for fixing the hydraulic control pipeline inside a velocity tube, and an outer ring for fixing the hydraulic control pipeline outside the velocity tube. The inner ring includes a body, a fixing ring disposed inside the body, a fastener connected to the fixing ring, an outward expansion drive unit connected to the body, and a plurality of abutment slips disposed on the body. The body is annular and has an opening. The two ends of the outward expansion drive unit are respectively connected to the two sides of the opening and are used to open the opening. The fastener is used to fix the hydraulic control pipeline on the fixing ring, and the abutment slips are used to clamp the inner wall of the velocity tube.

[0006] The built-in ring has a ring-shaped body with an opening, resembling a C-shape. A retaining ring is located on the body, through which the hydraulic control line passes and is secured using fasteners. This secures the built-in ring to the hydraulic control line. Simultaneously, an outward-expanding drive unit is located at the opening, expanding the opening and increasing the overall diameter of the body. This allows it to be secured within the speed tube via a contact slip. Specifically, the outer surface of the contact slip is equipped with anti-slip serrations. The outward-expanding drive unit can be driven by a motor, cylinder, hydraulic cylinder, or manually. Fasteners can be screws, clamps, etc. The external ring can employ conventional ring-shaped contraction and fastening structures, such as clamps, chains, belts, or grips.

[0007] With the above settings, in situations where the well space is limited, an internal ring can be used to fix the hydraulic control line. Under some conventional production conditions, an external ring can be used to fix the hydraulic control line, thus meeting the fixing requirements of the hydraulic control line under different complex conditions, ensuring the stability of the hydraulic control line, and meeting the pressurized running requirements of offshore gas wells with hydraulic control lines, so as to achieve continuous bubble gas lift operations while meeting the well control requirements of offshore gas wells.

[0008] Preferably, the outward expansion drive unit includes a housing, movable rods slidably disposed at both ends of the housing, and a pressure port disposed on the housing. A pressure-bearing cavity is provided between the end of the movable rod and the housing. The movable rod is rotatably connected to the main body, and the pressure port communicates with the pressure-bearing cavity.

[0009] Pressurization is applied into the pressure chamber through the pressurization port, which in turn pushes the moving rod to move outward. The moving rods at both ends of the housing then open the opening, and the inner ring is supported inside the speed tube by the abutting slip.

[0010] Preferably, a one-way valve is provided at the pressurization port.

[0011] A one-way valve is installed at the pressurization port. During operation, all the internal rings to be installed are first fixed to the hydraulic control line. Then, the hydraulic control line and the internal rings are inserted into the speed tube. The speed tube is then sealed and pressurized. The air pressure in the speed tube enters the pressure chamber of the external expansion drive unit through the one-way valve to fix all the internal rings. The operation is convenient and quick.

[0012] Preferably, it further includes a piston component that is slidably connected to the housing, the piston component being fixedly connected to the moving rod and disposed between the moving rod and the pressure-bearing cavity.

[0013] A pressure chamber is formed between the piston and the housing. Pressurizing the pressure chamber can push the piston, which in turn pushes the moving rod. The piston is designed to increase sealing performance. Specifically, sealing rings are provided between the piston and the housing, and between the moving rod and the housing.

[0014] Preferably, the housing is provided with a first anti-reverse tooth, and the piston is provided with a second anti-reverse tooth that abuts against the first anti-reverse tooth. The first anti-reverse tooth and the second anti-reverse tooth are used to prevent the moving rod from retracting.

[0015] The first and second anti-reverse teeth form a unidirectional moving structure, allowing the piston and moving rod to move only in one direction. This prevents the moving rod from retracting after it extends, thus improving the tightening effect of the inner ring.

[0016] Preferably, the external ring includes at least two fan blades that are rotatably connected in sequence, a slot provided on the fan blades, fastening buckles provided on the sides of the fan blades on both sides, and anti-slip teeth respectively provided on the inner side of the fan blades and in the slots. All the fan blades are arranged to form a ring structure and are fastened and fixed by the fastening buckles. The slots are used to hold the hydraulic control line.

[0017] All fan blades are rotatably connected, and the overall fan blade shape is arc-shaped, forming a ring structure. They are secured to the outer wall of the speed tube by fastening clips. Simultaneously, slots are used to hold the hydraulic control line. The outer ring, while fixed to the speed tube, also secures the hydraulic control line to it. Anti-slip teeth are designed to increase friction between the fan blades and the hydraulic control line and speed tube, improving the securing effect. Specifically, the fastening clips are equipped with one-way locking teeth similar to the first and second anti-reverse teeth. After the two fastening clips are tightened, the one-way locking teeth prevent detachment and ensure a secure hold.

[0018] Preferably, the upper and lower ends of the fan blade are respectively provided with anti-slip cards, which are used to abut against the speed tube.

[0019] The anti-slip card further enhances the overall anti-slip effect of the outer ring. Specifically, the anti-slip card has anti-slip teeth that abut against the speed tube, and the inner side or end extends toward the center of the fan blade, protruding from the inner side of the fan blade.

[0020] A method for pressure-driven installation of a velocity line in an offshore gas well, using any of the aforementioned offshore gas well hydraulic control line fixing components, includes the following steps: S1: Shut down the well, install the blowout preventer assembly including the gate and the first annular blowout preventer, the lower slips and the riser pipe, assemble the injector, and perform functional tests on the blowout preventer assembly, the lower slips and the injector. After passing the tests, insert the velocity pipe into the injector. S2: Install the speed tube connector and perform a tensile test. After passing the test, connect the well cleaning tool string. S3: Install the injector, pressure test the blowout preventer assembly, lower slips, riser pipe, and injector system. After passing the test, open the well access channel, unclog the well and control the rate tube descent speed. Clog the well to below the designed depth of the rate tube. S4: Retrieve the wellbore cleaning tool string, close the well access channel, disassemble the injector and wellbore cleaning tool string, and connect the velocity tube plugging tool. If an internal hydraulic control line downhole tool is used, proceed to step S5. If an external hydraulic control line downhole tool is used, proceed to step S10. S5: Install the injector, open the well access channel, lower the speed pipe to the downhole tool installation position, close the blowout preventer assembly and lower slips and manually lock them; S6: Disassemble the injector, cold cut the speed tube, and install the downhole tool with built-in hydraulic control line; S7: Reinsert the injector into the built-in hydraulic control line and velocity tube, connect the hydraulic control line and velocity tube to the downhole tool and perform a tensile test. After passing the test, install the injector. S8: Test the hydraulic control line, speed line and injector with pressure. After passing the test, open the lower slip and blowout preventer assembly, lower the speed line to the hanger installation position, close the blowout preventer assembly and lower slip and manually lock them. S9: Disassemble the injector, cold cut the speed tube and hydraulic control line, connect the built-in hydraulic control line hanger, hanger insertion tool and speed tube in sequence, install the injector, open the lower slip and blowout preventer assembly, lower the hanger to the hanging position and test the pressure. After passing the test, proceed to step S17. S10: Install the second annular blowout preventer, blowout preventer box, visual control window, upper slip, and injector above the riser pipe. Perform functional tests and pressure tests on the second annular blowout preventer, blowout preventer box, upper slip, etc. After passing the tests, close the blowout preventer box. S11: Install the injector, open the well access channel, lower the speed pipe to the downhole tool installation position, close the blowout preventer assembly and lower slips and manually lock them; S12: Remove the injector, cold cut the velocity tube, install the external hydraulic control line downhole tool and velocity tube, install the injector, open the lower slips and blowout preventer assembly, close the second annular blowout preventer, lower the downhole tool to the visible operating window, connect the hydraulic control line, and use the external ring to fix the hydraulic control line to the velocity tube. S13: Close the first annular blowout preventer in the blowout preventer group, open the blowout preventer box and the second annular blowout preventer, lower the downhole tool through the second annular blowout preventer and close it, open the first annular blowout preventer in the blowout preventer group, continue to lower the velocity tube, and use an external ring to fix the hydraulic control line to the velocity tube every 8-10m. S14: Lower the speed pipe to the suspension installation position, close the first annular blowout preventer in the blowout preventer assembly, close the upper slip and manually lock it; S15: Remove the injector, cold cut the speed tube, connect the external hydraulic control line hanger, hanger insertion tool and speed tube in sequence, install the injector, open the upper slip, lower the hanger to the operation window, and connect the hydraulic control line. S16: Open the second annular blowout preventer, lower the hanger through the second annular blowout preventer and then close it, open the first annular blowout preventer in the blowout preventer group, lower the hanger to the suspension position and test the pressure, if it passes the test, proceed to the next step. S17: Send the tool into the hand-release hanger, lift it into the riser pipe, close the main valve of the gas production tree and the wax removal valve, dismantle the working equipment and restore the wellhead; S18: Open the main valve of the gas production tree, pressurize the wing valve to break the speed pipe plugging tool, and put the well into production.

[0021] Preferably, in step S6, installing the downhole tool with the built-in hydraulic control line includes the following steps: A1: Insert the hydraulic control line into the retaining ring, secure the hydraulic control line with fasteners, and install an internal ring every 8-10m on the hydraulic control line; A2: Insert the hydraulic control line with the built-in ring into the speed tube and straighten it, then seal both ends of the speed tube; A3: Pressurize the inside of the speed tube. The fluid enters the pressure chamber through the one-way valve and pushes the moving rod to both sides, so that the contact slips press against the inner wall of the speed tube, thus fixing the built-in ring and hydraulic control line inside the speed tube. A4: After depressurization, perform a tensile test on the hydraulic control line. The test tensile force shall not be less than 30% and not more than 50% of the hydraulic control line tensile load.

[0022] Preferably, in step S3, during system pressure testing, low pressure (300±20psi / 5min) and high pressure (3000±100psi / 15min) are used sequentially. A pressure drop of less than 2% at the wellhead is considered acceptable. After passing the test, the well access channel is opened for well cleaning. The tubing is lowered at a speed of 10-15m / min at the normal downhole position and at a speed of 5m / min at the downhole diameter reduction position. During this period, a lifting and lowering test is performed every 400m-1500m to lower the tubing to the designed depth and the depth suspension weight value is recorded.

[0023] Compared with the prior art, the beneficial effects of the present invention are: It solves the problem that the velocity line with liquid control can not be run under pressure through conventional operation methods, and enables the liquid control line to be run under pressure whether it is internal or external. Different fixing methods can be selected according to the actual site conditions, making it more applicable. It also solves the control problem of downhole tools in the continuous gas lift bubble discharge system of offshore velocity line and the problem of operation under pressure, ensuring well control safety. Attached Figure Description

[0024] Figure 1 This is a schematic diagram of the built-in ring structure of a offshore gas well fluid control pipeline fixing assembly according to the present invention; Figure 2 yes Figure 1 A-A' cross-sectional view; Figure 3 yes Figure 1 B-B' cross-sectional view; Figure 4 This is a schematic diagram of the external ring structure of a offshore gas well fluid control pipeline fixing assembly according to the present invention; Figure 5 This is a schematic diagram of the external ring unfolding structure of a marine gas well fluid control pipeline fixing component according to the present invention; Figure 6 This is a schematic flowchart of a method for introducing a velocity pipe under pressure into an offshore gas well according to the present invention. Figure 7 This is a schematic diagram of the built-in hydraulic control pipeline insertion structure of a method for pressing down a velocity pipe in an offshore gas well according to the present invention. Figure 8 This is a schematic diagram of the external liquid control pipeline insertion structure of a method for introducing a velocity pipeline under pressure in an offshore gas well according to the present invention.

[0025] In the diagram: 1. Internal ring; 2. External ring; 3. Body; 4. Fixed ring; 5. Fastener; 6. External expansion drive unit; 7. Abutting slip; 8. Housing; 9. Moving rod; 10. Pressure chamber; 11. One-way valve; 12. Piston; 13. First check tooth; 14. Second check tooth; 15. Fan blade; 16. Slot; 17. Fastening buckle; 18. Anti-slip tooth; 19. Anti-slip clip; 20. First annular blowout preventer; 21. Blowout preventer assembly; 22. Lower slip; 23. Riser pipe; 24. Injector; 25. Second annular blowout preventer; 26. Blowout preventer box; 27. Visual operation window; 28. Upper slip; 29. ​​Wax removal valve; 30. Main valve; 31. Hydraulic control line; 32. Hollow sealing ring; 33. Sealing ring; 34. Shear gate; 35. Semi-sealed gate; 36. Full-sealed gate. Detailed Implementation

[0026] The accompanying drawings are for illustrative purposes only and should not be construed as limiting this patent. To better illustrate this embodiment, some components in the drawings may be omitted, enlarged, or reduced, and do not represent the actual dimensions of the product. It is understandable to those skilled in the art that some well-known structures and their descriptions may be omitted in the drawings. The positional relationships described in the drawings are for illustrative purposes only and should not be construed as limiting this patent.

[0027] In the accompanying drawings of the embodiments of the present invention, the same or similar reference numerals correspond to the same or similar components. In the description of the present invention, it should be understood that if terms such as "upper," "lower," "left," "right," "long," and "short" indicate the orientation or positional relationship based on the orientation or positional relationship shown in the drawings, they are only for the convenience of describing the present invention and simplifying the description, and do not indicate or imply that the device or element referred to must have a specific orientation, or be constructed and operated in a specific orientation. Therefore, the terms used to describe positional relationships in the drawings are only for illustrative purposes and should not be construed as limiting the present patent. For those skilled in the art, the specific meaning of the above terms can be understood according to the specific circumstances.

[0028] The technical solution of the present invention will be further described in detail below through specific embodiments and in conjunction with the accompanying drawings: Example 1 like Figure 1-2 As shown, a hydraulic control line fixing assembly for offshore gas wells includes: an inner ring 1 for fixing the hydraulic control line 31 inside a velocity tube, and an outer ring 2 for fixing the hydraulic control line 31 outside the velocity tube. The inner ring 1 includes a body 3, a fixing ring 4 disposed inside the body 3, a fastener 5 connected to the fixing ring 4, an outward expansion drive part 6 connected to the body 3, and a plurality of abutment slips 7 disposed on the body 3. The body 3 is annular and has an opening. The two ends of the outward expansion drive part 6 are respectively connected to the two sides of the opening and are used to open the opening. The fastener 5 is used to fix the hydraulic control line 31 on the fixing ring 4, and the abutment slips 7 are used to hold the inner wall of the velocity tube.

[0029] The built-in ring 1 has a ring-shaped body 3 with an opening, i.e., a C-shaped structure. A fixing ring 4 is provided on the body. The hydraulic control line 31 passes through the fixing ring and is then fixed using fasteners 5, thus fixing the built-in ring 1 to the hydraulic control line 31. Simultaneously, an outward expansion drive 6 is provided at the opening of the body 3. The outward expansion drive 6 is used to expand the opening, thereby increasing the overall diameter of the body 3, allowing it to be secured inside the speed tube by the abutment slip 7. Specifically, the outer surface of the abutment slip 7 is provided with anti-slip serrations. The outward expansion drive 6 can be a motor, cylinder, hydraulic cylinder, or manually driven. The fasteners 5 can be screws, clamps, etc. The external ring 2 can adopt a conventional ring-shaped shrink-fit fastening structure, such as clamps, chains, belts, or belt clamps.

[0030] The beneficial effects of this embodiment are as follows: With the above settings, when the space inside the well is small, the built-in ring 1 can be used to fix the hydraulic control line 31. Under some conventional production conditions, the external ring 2 can be used to fix the hydraulic control line 31 to meet the fixing requirements of the hydraulic control line 31 under different complex conditions, ensure the stability of the hydraulic control line 31, meet the pressurized running requirements of the offshore gas well with the hydraulic control line 31, so as to realize the continuous bubble gas lift operation while meeting the well control requirements of the offshore gas well.

[0031] Example 2 This embodiment further defines the features of Embodiment 1, and its difference from Embodiment 1 lies in: like Figure 1-3 As shown, the outward expansion drive unit 6 includes a housing 8, movable rods 9 slidably disposed at both ends of the housing 8, and a pressure port disposed on the housing 8. A pressure-bearing cavity 10 is provided between the end of the movable rod 9 and the housing 8. The movable rod 9 is rotatably connected to the main body 3, and the pressure port communicates with the pressure-bearing cavity 10. A one-way valve 11 is provided at the pressure port. It also includes a piston 12 slidably connected to the housing 8. The piston 12 is fixedly connected to the movable rod 9 and is disposed between the movable rod 9 and the pressure-bearing cavity 10. A first check tooth 13 is provided inside the housing 8, and a second check tooth 14 is provided on the piston 12 to abut against the first check tooth 13. The first check tooth 13 and the second check tooth 14 are used to prevent the movable rod 9 from retracting.

[0032] Pressurization is applied to the pressure chamber 10 through the pressurization port, which in turn pushes the moving rod 9 outward. This, in turn, opens the opening via the moving rods 9 at both ends of the housing 8, and then holds the internal ring 1 inside the speed tube by the contact slip 7. A one-way valve 11 is installed at the pressurization port. During operation, all the internal rings 1 to be installed are first fixed to the hydraulic control line 31. Then, the hydraulic control line 31 and the internal rings 1 are inserted into the speed tube, and the speed tube is then sealed and pressurized. The air pressure inside the speed tube enters the pressure chamber 10 of the outward expansion drive unit 6 through the one-way valve 11, thus fixing all the internal rings 1. The operation is convenient and quick. A pressure chamber 10 is formed between the piston 12 and the housing 8. Pressurizing the pressure chamber 10 pushes the piston 12, which in turn pushes the moving rod 9. The piston 12 is designed to enhance sealing performance; specifically, sealing rings 33 are provided between the piston 12 and the housing 8, and between the moving rod 9 and the housing 8. The first anti-reverse tooth 13 and the second anti-reverse tooth 14 are a one-way moving structure, which allows the piston 12 and the moving rod 9 to move only in one direction. After the moving rod 9 is extended, it can prevent the moving rod 9 from retracting, thereby improving the fastening effect of the inner ring 1.

[0033] like Figure 2As shown, a hollow sealing ring 32 is further provided on the fixing ring 4, and the fastener 5 is a screw. The hollow sealing ring 32 is located below the fastener 5. When the fastener 5 is tightened, it compresses the hollow sealing ring 32, causing the hollow sealing ring 32 to deform, thereby compressing and fixing the hydraulic control line 31. The hollow sealing ring 32 is preferably a hollow metal ring.

[0034] The remaining features and working principles of this embodiment are the same as those of Embodiment 1.

[0035] Example 3 Based on Example 1 or Example 2, Example 1 or Example 2 are further defined, with the following differences: like Figure 4-5 As shown, the outer ring 2 includes at least two fan blades 15 rotatably connected in sequence, a slot 16 on the fan blade 15, fastening buckles 17 on the sides of the fan blades 15, and anti-slip teeth 18 respectively on the inner side of the fan blades 15 and in the slots 16. All the fan blades 15 form a ring structure and are fastened and fixed by the fastening buckles 17. The slots 16 are used to hold the hydraulic control line 31. Anti-slip clips 19 are provided at the upper and lower ends of the fan blades 15, and the anti-slip clips 19 are used to abut against the speed tube.

[0036] All fan blades 15 are rotatably connected. The fan blades 15 are arc-shaped, forming a ring structure. They are secured to the outer wall of the speed tube by fastening buckles 17. At the same time, the slots 16 are used to secure the hydraulic control line 31. While the outer ring 2 is fixed to the speed tube, it also secures the hydraulic control line 31 to the speed tube. The anti-slip teeth 18 are designed to increase the friction between the fan blades 15 and the hydraulic control line 31 and the speed tube, improving the fixing effect. Specifically, the fastening buckles 17 are provided with one-way teeth similar to the first anti-reverse teeth 13 and the second anti-reverse teeth 14. After the two fastening buckles 17 are tightened, the one-way teeth prevent detachment and ensure the locking effect. The anti-slip card 19 is provided to further enhance the overall anti-slip effect of the outer ring 2. Specifically, the anti-slip card 19 has anti-slip teeth that abut against the speed tube, and the inner side or end extends towards the center of the fan blade 15, protruding from the inner side of the fan blade 15.

[0037] The remaining working principles and processes of this embodiment are the same as those of Embodiment 1 or Embodiment 2.

[0038] Example 4 like Figure 6 As shown, a method for pressure-driven installation of a velocity line in an offshore gas well, implemented using any of the aforementioned offshore gas well hydraulic control line 31 fixing components, includes the following steps: S1: Shut down the well, install the blowout preventer assembly 21 including the gate and the first annular blowout preventer 20, the lower slip 22 and the riser pipe 23, assemble the injector 24, perform functional tests on the blowout preventer assembly 21, the lower slip 22 and the injector 24, and after passing the tests, insert the velocity pipe into the injector 24. S2: Install the speed tube connector and perform a tensile test. After passing the test, connect the well cleaning tool string. S3: Install injector 24, and perform a pressure test on the blowout preventer assembly 21, lower slips 22, riser pipe 23, and injector 24 system. After passing the test, open the well access channel, traverse the well, and control the speed of the velocity pipe descent. Traverse the well to below the designed depth of the velocity pipe. S4: Retrieve the well cleaning tool string, close the well access channel, remove the injector 24 and the well cleaning tool string, and connect the speed pipe plugging tool. If the built-in hydraulic control line 31 downhole tool is used, proceed to step S5. If the external hydraulic control line 31 downhole tool is used, proceed to step S10. S5: Install injector 24, open the well access channel, lower the speed pipe to the downhole tool installation position, close the blowout preventer assembly 21 and the lower slip 22 and manually lock them; S6: Remove injector 24, cold cut the speed tube, and install the downhole tool with built-in hydraulic control line 31. S7: The injector 24 is re-inserted into the built-in hydraulic control line 31 and velocity tube. The hydraulic control line 31 and velocity tube are connected to the downhole tool and a tensile test is performed. After passing the test, the injector 24 is installed. S8: Test the hydraulic control line 31, speed pipe and injector 24 with pressure. After passing the test, open the lower slip 22 and blowout preventer assembly 21, lower the speed pipe to the hanger installation position, close the blowout preventer assembly 21 and lower slip 22 and manually lock them. S9: Disassemble the injector 24, cold cut the speed tube and hydraulic control line 31, connect the built-in hydraulic control line 31 hanger, hanger delivery tool and speed tube in sequence, install the injector 24, open the lower slip 22 and blowout preventer assembly 21, lower the hanger to the hanging position and test the pressure. After passing the test, proceed to step S17. S10: Install the second annular blowout preventer 25, blowout preventer box 26, visual operation window 27, upper slip 28, and injector 24 above the riser pipe 23. Perform functional tests and pressure tests on the second annular blowout preventer 25, blowout preventer box 26, upper slip 28, etc. After passing the tests, close the blowout preventer box 26. S11: Install injector 24, open the well access channel, lower the speed pipe to the downhole tool installation position, close the blowout preventer assembly 21 and the lower slip 22 and manually lock them; S12: Remove the injector 24, cold cut the velocity tube, install the external hydraulic control line 31 downhole tool and velocity tube, install the injector 24, open the lower slip 22 and blowout preventer assembly 21, close the second annular blowout preventer 25, lower the downhole tool to the visible operating window 27, connect the hydraulic control line 31, and use the external ring 2 to fix the hydraulic control line 31 to the velocity tube; S13: Close the first annular blowout preventer 20 in the blowout preventer assembly 21, open the blowout preventer box 26 and the second annular blowout preventer 25, lower the downhole tool through the second annular blowout preventer 25 and close it, open the first annular blowout preventer 20 in the blowout preventer assembly 21, continue to lower the velocity tube, and use the external ring 2 to fix the hydraulic control line 31 to the velocity tube every 8-10m. S14: Lower the speed pipe to the suspension installation position, close the first annular blowout preventer 20 in the blowout preventer assembly 21, close the upper slip 28 and manually lock it; S15: Remove injector 24, cold cut the speed tube, connect the external hydraulic control line 31 hanger, hanger insertion tool and speed tube in sequence, install injector 24, open upper slip 28, lower the hanger to the operation window, and connect hydraulic control line 31. S16: Open the second annular blowout preventer 25, lower the hanger through the second annular blowout preventer 25 and then close it, open the first annular blowout preventer 20 in the blowout preventer group 21, lower the hanger to the suspension position and test the pressure, if it passes the test, proceed to the next step. S17: Send the tool into the hand-release hanger and lift it into the riser pipe 23. Close the main valve 30 of the gas production tree and the wax removal valve 29. Dismantle the working equipment and restore the wellhead. S18: Open the main valve 30 of the gas production tree, pressurize the wing valve to break the speed pipe plugging tool, and put the well into production.

[0039] This method solves the problem that the velocity tube with liquid control line 31 cannot be run under pressure through conventional operation methods. It enables the liquid control line 31 to be run under pressure whether it is internal or external. Different fixing methods can be selected according to the actual site conditions, making it more applicable. It also solves the control problem of downhole tools in the continuous gas lift bubble discharge system of offshore velocity tube and the problem of operation under pressure, ensuring well control safety.

[0040] Example 5 Based on Example 4, Example 4 is further defined, with the following differences: Step S6, installing the downhole tool with the built-in hydraulic control line 31 includes the following steps: A1: Insert the hydraulic control line 31 into the fixing ring 4, use fasteners 5 to fix the hydraulic control line 31, and set an internal ring 1 every 8-10m on the hydraulic control line 31; A2: Insert the hydraulic control line 31 with the built-in ring 1 into the speed tube and straighten it, and seal both ends of the speed tube; A3: Pressurize inside the velocity string. The fluid enters the pressure-bearing cavity 10 through the check valve 11 and pushes the moving rod 9 to move towards both sides, causing the abutting slip 7 to tightly press against the inner wall of the velocity string, fixing the built-in ring 1 and the hydraulic control pipeline 31 inside the velocity string. A4: After pressure relief, conduct a tensile test on the hydraulic control pipeline 31. The test tensile force shall be not less than 30% and not greater than 50% of the tensile load of the hydraulic control pipeline 31.

[0041] Furthermore, in step S3, during system pressure testing, conduct pressure testing successively with a low pressure of 300 ± 20 psi / 5 min and a high pressure of 3000 ± 100 psi / 15 min. The wellhead pressure drop less than 2% is qualified. After qualification, open the well entry channel for well flushing. Lower it at a speed of 10 - 15 m / min at the normal position underground and at a speed of 5 m / min at the necking position underground. During this period, conduct a up-and-down test every 400 m - 1500 m. Lower the tubing to the designed depth and record the depth and hook load values.

[0042] Furthermore, the blowout preventer group 21 includes a full-closed ram 36, a half-closed ram 35, a shear ram 34, and a first annular blowout preventer 20 arranged in sequence, improving production safety.

[0043] The remaining working principle and working process of this embodiment are the same as those of Embodiment 4.

[0044] Embodiment 6 According to the method of Embodiment 4 or Embodiment 5, use the built-in ring 1 to fix the hydraulic control pipeline 31 for production: Figure 7 It is a schematic diagram of the pressure-bearing lowering of the velocity string with the built-in hydraulic control pipeline 31. Taking the actual Well A as an example, the tubing size of this well is 2.875 in, and the well depth is 1663 m. The formation pressure is 4 MPa, and the daily liquid production is lower than the critical liquid-carrying flow rate. The gas well has a risk of blowout. The original production string size is small and there are multiple neckings in the string. To ensure the safety of lowering, select the operation mode of the built-in hydraulic control pipeline 31, lower a 1.75-in velocity string to carry out continuous gas lift for liquid drainage, and the lowering depth is 1011 m. The specific implementation steps of this well are as follows: S1: Close the well entry channel (main valve 30, paraffin scraper valve 29), install the blowout preventer group 21 including the shear ram 34, half-closed ram 35, full-closed ram 36, and the first annular blowout preventer 20, the lower slip 22, and the extension pipe 23, assemble the injector 24, and conduct a function test on the blowout preventer group 21, the lower slip 22, and the injector 24 to ensure the normal opening and closing of the blowout preventer and the lower slip 22. After qualification, pass the velocity string through the injector 24. S2: Install a joint on the velocity string and conduct a tensile test (30000 lbs), connect the well flushing tool string; and zero the depth of the velocity string. S3: Install injector 24 and pressure test the blowout preventer assembly 21, lower slips 22, riser tubing 23, and injector 24 system. The low pressure is 300 psi / 5 min, and the high pressure is 3000 psi / 15 min. A wellhead pressure drop of less than 2% is acceptable. After passing the test, open the well access channel for well cleaning. Normally, run the tubing at a speed of 10-15 m / min, and at the reduced diameter position at a speed of 5 m / min. Perform a pull-up and drop test every 500 m. Run the tubing to the designed depth and record the depth weight. S4: Retrieve the wellbore cleaning tool string, close the well access channel, remove the injector 24 and the wellbore cleaning tool string, and connect the speed tube plugging tool (1.75in speed tube + plug). S5: Install injector 24, open the well access channel, and normally run it down at a speed of 12m / min. At the reduced diameter position, run the lower speed pipe down to the downhole tool installation position at a speed of 5m / min. Close the blowout preventer assembly 21 and the lower slip 22 and manually lock them. S6: Remove injector 24, cold cut the speed tube, and install the downhole tool with built-in hydraulic control line 31. S7: Reinsert the injector 24 into the built-in hydraulic control line 31 velocity tube, connect the hydraulic control line 31 and velocity tube to the downhole tool and perform a pull test (30000 lbs). After passing the test, install the injector 24. S8: Test the hydraulic control line 31, speed pipe and injector 24 with pressure. After passing the test, open the lower slip 22 and blowout preventer assembly 21, lower the speed pipe to the hanger installation position, close the blowout preventer assembly 21 and lower slip 22 and manually lock them. S9: Disassemble the injector 24, cold cut the speed tube and hydraulic control line 31, connect the built-in hydraulic control line 31 hanger, hanger delivery tool and speed tube in sequence, install the injector 24, open the lower slip 22 and blowout preventer assembly 21, lower the hanger to the hanging position and pressurize the set seal (1000psi×3mins, 2000psi×3mins, 3000psi×3mins, 3500psi×10mins), pressurize 6000lbs to test the slip, pressurize the annulus 1000psi×15mins to test the rubber, if qualified, proceed to the next step; S10: Pressurize the velocity tube to 5075psi, send in the tool and release it, lift it into the riser tube 23, close the main valve 30 of the gas production tree and the wax removal valve 29, dismantle the working equipment and restore the wellhead; S11: Open the main valve 30 of the gas production tree, use a nitrogen pump to pressurize to 7MPa to shear the plug pin, and hand over the well for production.

[0045] S12: Well opening and induced flow to resume production. Observe changes in wellhead pressure and production. If the wellhead pressure rises or there is a return flow, the channel is successfully connected.

[0046] Example 7 According to the method of Example 4 or Example 5, production is carried out using an external ring 2 to fix the hydraulic control line 31: Figure 8 This diagram illustrates the pressurized installation of an externally controlled hydraulic line 31 velocity tubing. Taking well B as an example, the well tubing size is 4.5 inches, and the well depth is 3443 m. The formation pressure coefficient is 0.53, and the pressure is 7 MPa. Due to the presence of accumulated fluid, there is no production. The externally controlled hydraulic line 31 operation method is selected, and continuous gas lift fluid removal is carried out by installing a 2.375-inch velocity tubing to a depth of 2213 m. The specific implementation steps for this well are as follows: S1: Close the well access passage (main valve 30, wax removal valve 29), install the blowout preventer assembly 21 including shear gate 34, semi-sealed gate 35, fully sealed gate 36 and first annular blowout preventer 20, lower slip 22 and riser pipe 23, assemble injector 24, perform functional tests on blowout preventer assembly 21, lower slip 22 and injector 24 to ensure that the blowout preventer and slips open and close normally, and after passing the test, insert the velocity pipe into injector 24; S2: Install the speed tube connector and perform a tensile test (not less than 20,000 lbs), connect the wellbore tool string, and zero the speed tube depth; S3: Install injector 24 and pressure test the blowout preventer assembly 21, lower slips 22, riser tubing 23, and injector 24 system. The low pressure is 300 psi / 5 min, and the high pressure is 5000 psi / 15 min. A wellhead pressure drop of less than 2% is acceptable. After passing the test, open the well access channel for well cleaning. Normally, run the tubing at a speed of 12 m / min, and at the reduced diameter position at a speed of 5 m / min. Perform a lifting and lowering test every 500 m. Run the tubing to the designed depth and record the depth weight. S4: Retrieve the wellbore cleaning tool string, close the well access channel, remove the injector 24 and the wellbore cleaning tool string, and connect the speed tube plugging tool (rupture disc + rivet joint + 2.375in speed tube). S5: Install the second annular blowout preventer, blowout preventer box 26, control window, upper slip 28, and injector 24. Perform functional tests and pressure tests on the second annular blowout preventer, blowout preventer box 26, and upper slip 28 (same as S3). After passing the tests, close the blowout preventer box 26. S6: Open the well access channel and run the pipe down at a normal speed of 12m / min. At the reduced diameter position, run the lower speed pipe down to the downhole tool installation position at a speed of 5m / min. Close the blowout preventer assembly 21 and the lower slip 22 and manually lock them. S7: Remove the injector 24, cold cut the velocity tube, install the external hydraulic control line 31 downhole tool, connect the velocity tube and perform a tensile test (not less than 20000 lbs), install the injector 24, open the lower slip 22 and blowout preventer assembly 21, close the second annular blowout preventer, lower the downhole tool to the visible operating window 27, connect the hydraulic control line 31, and use the external ring 2 to fix the hydraulic control line 31 to the velocity tube; S8: Close the annular blowout preventer in the blowout preventer group 21, open the blowout preventer box 26 and the second annular blowout preventer, lower the downhole tool through the second annular blowout preventer and close it, open the annular blowout preventer in the blowout preventer group 21, continue to lower the velocity tube, and every 8m, use the external ring 2 through the operation window to fix the hydraulic control line 31 to the velocity tube. S9: Lower the speed pipe to the suspension installation position, close the annular blowout preventer in the blowout preventer assembly 21, close the upper slip 28 and manually lock it; S10: Remove injector 24, cold cut the speed tube, connect the external hydraulic control line 31 hanger, hanger insertion tool, speed tube and plug in sequence, install injector 24, open upper slip 28, lower the hanger to the operation window, and connect hydraulic control line 31. S11: Open the second annular blowout preventer, lower the hanger through the second annular blowout preventer and close it, open the annular blowout preventer in blowout preventer group 21, lower the hanger to the hanging position, pressurize the speed pipe, set the tubing hanger: initial setting pressure 1100psi, full setting pressure 2500-3000psi, pressurize the annulus to 1000psi to verify the seal, if qualified, proceed to the next step. S12: Pressurize the speed tube to 3500psi, release the delivery tool, try to lift the tubing to determine if the delivery tool has been released, lift the speed tube to remove the delivery tool, close the gas tree main valve 30 and the wax removal valve 29, dismantle the work equipment and restore the wellhead. S13: Open the main valve 30 of the gas production tree, pressurize the wing valve to break the speed pipe blockage tool, and stop the pump to release pressure; S14: Well opening and induced blowout to resume production. Observe the changes in wellhead pressure and production. If the wellhead pressure rises or there is a return, the fractured plate has been successfully broken.

[0047] In the specific implementation of the above embodiments, the technical features can be combined in any non-contradictory way. For the sake of brevity, not all possible combinations of the above technical features are described. However, as long as the combination of these technical features is not contradictory, it should be considered to be within the scope of this specification.

[0048] Obviously, the above embodiments of the present invention are merely examples for clearly illustrating the present invention, and are not intended to limit the implementation of the present invention. Those skilled in the art can make other variations or modifications based on the above description. It is neither necessary nor possible to exhaustively describe all embodiments here. Any modifications, equivalent substitutions, and improvements made within the spirit and principles of the present invention should be included within the scope of protection of the claims of the present invention.

Claims

1. An offshore gas well hydraulic control line fixation assembly, characterized by The application relates to a built-in ring (1) for fixing a hydraulic control pipeline (31) in a velocity tube and an external ring (2) for fixing the hydraulic control pipeline (31) outside the velocity tube, wherein the built-in ring (1) comprises a body (3), a fixing ring (4) arranged on the inner side of the body (3), a fastener (5) connected with the fixing ring (4), an external expansion driving part (6) connected with the body (3), and a plurality of abutting slips (7) arranged on the body (3), the body (3) is annular and is provided with an opening part, the external expansion driving part (6) is connected with the opening part on both sides and is used for expanding the opening part, the fastener (5) is used for fixing the hydraulic control pipeline (31) on the fixing ring (4), and the abutting slips (7) are used for clamping the inner wall of the velocity tube. The external expansion driving part (6) comprises a shell (8), moving rods (9) slidingly arranged on both ends of the shell (8), and a pressurizing port arranged on the shell (8), pressure cavities (10) are arranged between the ends of the moving rods (9) and the shell (8), the moving rods (9) are rotationally connected with the body (3), and the pressurizing port is in communication with the pressure cavities (10).

2. A subsea gas well hydraulic control line fixation assembly according to claim 1, characterized in that: A one-way valve (11) is arranged at the pressurizing port.

3. A subsea gas well hydraulic control line fixation assembly according to claim 2, characterized in that: A piston piece (12) is further arranged and connected with the shell (8) in a sliding mode, the piston piece (12) is fixedly connected with the moving rods (9) and is arranged between the moving rods (9) and the pressure cavities (10).

4. A subsea gas well fluid control line fixation assembly according to claim 3, characterized in that: First reverse-stopping teeth (13) are arranged in the shell (8), second reverse-stopping teeth (14) are arranged on the piston piece (12) and abut against the first reverse-stopping teeth (13), and the first reverse-stopping teeth (13) and the second reverse-stopping teeth (14) are used for preventing the moving rods (9) from retracting.

5. A subsea gas well fluid control line fixation assembly according to claim 4, characterized in that: The external ring (2) comprises at least two fan-shaped pieces (15) rotationally connected in sequence, a clamping groove (16) arranged on the fan-shaped pieces (15), fastening buckles (17) arranged on the side parts of the fan-shaped pieces (15) on both sides, and anti-skid teeth (18) arranged in the fan-shaped pieces (15) and the clamping grooves (16) respectively, all the fan-shaped pieces (15) are annularly arranged to form an annular structure and are fixed through the fastening buckles (17), and the clamping grooves (16) are used for clamping the hydraulic control pipeline (31).

6. A subsea gas well hydraulic control line fixation assembly according to claim 1, characterized in that: Anti-skid cards (19) are arranged on the upper and lower ends of the fan-shaped pieces (15) respectively, and the anti-skid cards (19) are used for abutting against the velocity tube.

7. A subsea gas well hydraulic control line fixation assembly according to claim 6, characterized in that: The application further relates to a method for installing a hydraulic control pipeline (31) in a velocity tube, and the method comprises the following steps:

8. A method of offshore gas well velocity string snubbing, implemented using the offshore gas well hydraulic control line (31) fixation assembly of any of claims 3-6, characterized in that, S1: closing the well, installing a blowout preventer group (21) comprising a blind plate and a first annular blowout preventer (20), a lower slip (22) and a riser (23), assembling an injector (24), and testing the functions of the blowout preventer group (21), the lower slip (22) and the injector (24), and then penetrating the velocity tube into the injector (24) after the test is qualified; S2: installing a joint on the velocity tube and testing the tension of the joint, and then connecting a well penetrating tool string after the test is qualified; ​ S3: install the injector (24), pressure test the blowout preventer group (21), lower slips (22), riser (23), injector (24) system, open the well access after passing the test, run the well and control the running speed of the velocity pipe, run the well to the design depth of the velocity pipe; S4: recover the running tool string, close the well access, disassemble the injector (24) and the running tool string, connect the velocity pipe blocking tool, if the downhole tool with built-in hydraulic control line (31) is used, execute step S5, if the downhole tool with external hydraulic control line (31) is used, execute step S10; S5: install the injector (24), open the well access, lower the velocity pipe to the installation position of the downhole tool, close the blowout preventer group (21) and the lower slips (22) and manually lock them; S6: disassemble the injector (24), cold cut the velocity pipe, install the downhole tool with built-in hydraulic control line (31); S7: re-thread the injector (24) into the velocity pipe with built-in hydraulic control line (31), connect the hydraulic control line (31) and the velocity pipe to the downhole tool and perform a tension test, install the injector (24) after passing the test; S8: pressure test the hydraulic control line (31), the velocity pipe and the injector (24), open the lower slips (22) and the blowout preventer group (21) after passing the test, lower the velocity pipe to the hanger installation position, close the blowout preventer group (21) and the lower slips (22) and manually lock them; S9: disassemble the injector (24), cold cut the velocity pipe and the hydraulic control line (31), connect the hanger with built-in hydraulic control line (31), the hanger running-in tool and the velocity pipe in sequence, install the injector (24), open the lower slips (22) and the blowout preventer group (21), lower the hanger to the hanger position and perform a pressure test, execute step S17 after passing the test; S10: install the second annular blowout preventer (25), blowout preventer box (26), visual operation window (27), upper slips (28), injector (24) above the riser (23), perform a function test and pressure test on the second annular blowout preventer (25), blowout preventer box (26), upper slips (28) and the like, close the blowout preventer box (26) after passing the test; S11: install the injector (24), open the well access, lower the velocity pipe to the installation position of the downhole tool, close the blowout preventer group (21) and the lower slips (22) and manually lock them; S12: disassemble the injector (24), cold cut the velocity pipe, install the downhole tool with external hydraulic control line (31), the velocity pipe, install the injector (24), open the lower slips (22) and the blowout preventer group (21), close the second annular blowout preventer (25), lower the downhole tool to the visual operation window (27), connect the hydraulic control line (31), and use the external ring (2) to fix the hydraulic control line (31) on the velocity pipe; S13: close the first annular blowout preventer (20) in the blowout preventer group (21), open the blowout preventer box (26) and the second annular blowout preventer (25), lower the downhole tool through the second annular blowout preventer (25) and close it, open the first annular blowout preventer (20) in the blowout preventer group (21), continue to lower the velocity pipe, and fix the hydraulic control line (31) on the velocity pipe with the external ring (2) every 8-10m. S14: Lower the velocity pipe to the hanger installation position, close the first annular blowout preventer (20) in the blowout preventer group (21), close the upper slips (28) and manually lock them; S15: Remove the injector (24), cold cut the velocity pipe, connect the external hydraulic control line (31) hanger, hanger running tool and velocity pipe in sequence, install the injector (24), open the upper slips (28), lower the hanger to the operating window, and connect the hydraulic control line (31); S16: Open the second annular blowout preventer (25), lower the hanger through the second annular blowout preventer (25), then close it, open the first annular blowout preventer (20) in the blowout preventer group (21), lower the hanger to the hanger position and test pressure, and if qualified, proceed to the next step; S17: Remove the hanger running tool, raise it to the riser (23), close the gas tree master valve (30) and the wax removal valve (29), remove the operating equipment, and restore the wellhead; S18: Open the gas tree master valve (30), press the wing valve to break the velocity pipe blocking tool, and put the well into production.

9. A method of running a marine gas well velocity string with pressure according to claim 8, characterized in that: In step S6, installing the downhole tool with the built-in hydraulic control line (31) includes the following steps: A1: Pass the hydraulic control line (31) through the fixing ring (4), fix the hydraulic control line (31) with the fastener (5), and set an internal ring (1) every 8-10 m on the hydraulic control line (31); A2: Pass the hydraulic control line (31) with the internal ring (1) through the velocity pipe and straighten it, and seal both ends of the velocity pipe; A3: Pressurize the inside of the velocity pipe, fluid enters the pressure-bearing cavity (10) through the one-way valve (11) and pushes the moving rod (9) to move to both sides, causing the abutting slips (7) to compress the inner wall of the velocity pipe to fix the internal ring (1) and the hydraulic control line (31) in the velocity pipe; A4: After depressurization, test the tension of the hydraulic control line (31), the test tension should not be less than 30% of the tension load of the hydraulic control line (31) and not more than 50% of the tension load of the hydraulic control line (31).

10. A method of running a velocity string with pressure in an offshore gas well according to claim 8, characterized in that: In step S3, when the system is pressure tested, low pressure 300±20psi / 5min and high pressure 3000±100psi / 15min are used in sequence, and the wellhead pressure drop is less than 2% for qualification. After qualification, open the well entry channel for wellbore testing, and lower the tubing to the designed depth at a speed of 10-15 m / min in normal downhole position and 5 m / min in downhole reduced diameter position. During the test, test the tension every 400-1500 m, record the depth and hanging weight.

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