Two times blowout preventer two times opening with pressure down pipe blowout preventer and operation method

Abstract

The application provides a twice-safety-valve twice-opening pressure-lowering pipe-safety-valve and swabbing combined pipe column and operation method, which comprises, from top to bottom, a rod pump supporting cylinder, a double-layer sliding sleeve switch, a controllable inner safety valve, a pump lower plug, and a screen pipe. A communication hole is arranged on the upper connector side of the double-layer sliding sleeve switch. An inner sliding sleeve and an outer sliding sleeve are respectively arranged on the inner side and the outer side of the communication hole on the upper connector of the double-layer sliding sleeve switch. The lower end of the safety valve upper connector is provided with a cover valve. A shear pin seat is arranged in the lower end of the outer sleeve. A core is arranged in the hole of the safety valve upper connector and the shear pin seat. The core supports the cover valve to open and turn on one side of the outer sleeve. The core is limited by a limiting piece on the shear pin seat. The rod pump supporting cylinder is provided with a rod pump. The application can shorten the well occupation time, improve the workover operation efficiency, reduce or even avoid the use of well killing fluid, reduce the construction cost and labor intensity, and avoid the risk of reservoir pollution damage.

Description

Technical Field

[0001] This invention relates to the field of oil and gas extraction technology, and in particular to a two-stage blowout prevention and two-stage opening pressurized pipe-down blowout prevention and extraction combined operation string and operation method. Background Technology

[0002] Oil and gas wells in oil and gas fields often have a certain formation pressure, and during operations, they possess a so-called self-flowing capability, capable of expelling fluids such as oil, gas, and water from the wellbore to the wellhead. For example, even if the formation pressure remains low, if foam fluid is used for sand flushing during operations, the fluid density in the wellbore will decrease significantly due to the rapid replacement of the fluid with foam fluid, often resulting in intermittent gushing of oil, gas, and water from the wellhead. According to current well control safety requirements for oil and gas wells, it is prohibited to run or pull tubing when gushing occurs at the wellhead. Traditional operations either involve prolonged periods of waiting for the formation oil, gas, and water density to gradually increase and the foam fluid in the wellbore to be released before proceeding with the next step of running or pulling tubing, or the use of a larger density kill fluid for wellbore circulation to control the well until the foam fluid stops gushing before proceeding with the next step of running or pulling tubing. This approach has two main drawbacks: first, it prolongs the well workover time, significantly reducing the efficiency of well workover operations; second, it increases the amount of fluid used in the well, raising construction costs and labor intensity, and further increasing the risk of reservoir contamination and damage from the fluid, ultimately leading to a decrease in oil and gas well production. For gas wells, due to the higher formation pressure and the more pronounced pressurized blowout potential of the wellbore fluid, these problems are even more pronounced. Summary of the Invention

[0003] The technical problem to be solved by the present invention is to provide a two-stage blowout prevention and two-stage opening pressurized tubing for blowout prevention and pumping operation, and a method for improving operational efficiency and avoiding reservoir contamination risks, in order to address the shortcomings of the prior art.

[0004] This invention is implemented as follows:

[0005] This invention provides a two-stage blowout preventer, two-stage opening, pressurized downpipe blowout preventer-to-extraction combined tubing string, characterized in that it comprises, from top to bottom, a rod-type pump support cylinder, a double-layer sliding sleeve switch, a controllable internal blowout preventer, a pump downblocker, and a screen pipe. The double-layer sliding sleeve switch includes an upper connector and a lower connector. A connecting hole is provided on the side of the upper connector of the double-layer sliding sleeve switch. An inner sliding sleeve and an outer sliding sleeve are respectively sealed on the inner and outer sides of the connecting hole on the upper connector of the double-layer sliding sleeve switch. The inner and outer sliding sleeves are respectively connected by an inner shear pin and an outer shear pin. The shear pin is connected to the upper connector of the double-layer sliding sleeve switch. A conical surface configured with a sealing ball is provided at the upper end of the inner sliding sleeve. The controllable inner blowout preventer includes an upper connector, an outer sleeve, and a lower connector connected sequentially from top to bottom. A cover valve is provided at the lower end of the upper connector. A shear pin seat is sealed inside the lower end of the outer sleeve. A core is sealed inside the holes of the upper connector and the shear pin seat. The core opens the cover valve and flips it onto one side of the outer sleeve. The core is limited by a limiting element on the shear pin seat. A rod pump is configured in the rod pump support cylinder.

[0006] In some alternative implementations, an inner bore step chamfer is provided on the inner side of the lower end of the upper connector of the double-sleeve switch, and the inner diameter of the inner bore step chamfer is smaller than the outer diameter of the inner sleeve.

[0007] In some optional implementations, the upper and lower ends of the inner sleeve are respectively sealed to the inner wall of the upper connector of the double-layer sliding sleeve switch by sealing rings to seal the inner side of the connecting hole. The sealing rings at the upper and lower ends of the inner sleeve correspond to the upper sealing surface and the lower sealing surface of the inner wall of the double-layer sliding sleeve switch, respectively. The distance from the chamfer of the inner hole step to the lower sealing surface of the inner wall of the double-layer sliding sleeve switch is equal to the distance between the upper sealing surface and the lower sealing surface of the inner wall of the double-layer sliding sleeve switch. This ensures that after the inner sleeve falls, its upper sealing surface is exactly on the inner sealing surface of the double-layer sliding sleeve switch where the lower sealing ring was located before the inner sleeve was knocked off, thus forming a secondary sealing surface.

[0008] In some alternative implementations, a gap is provided between the outer sliding sleeve and the outer side of the upper connector of the double-layer sliding sleeve switch to form an annular space, and a stepped surface is provided on the inner side of the lower end of the outer sliding sleeve.

[0009] In some alternative implementations, the connecting hole adopts an elongated oval hole structure or a multi-set elongated slit screen filter structure.

[0010] In some alternative implementations, the cover valve includes a front support, a rear support, and a cover plate hinged to the front support via cover plate legs, symmetrically arranged at the lower end of the blowout preventer's upper connector. A torsion spring is provided at the hinge, with one end of the torsion spring fixedly connected to the cover plate legs and the other end fixedly connected to the rear support.

[0011] In some alternative implementations, a spring-loaded rack and pinion fitting is installed at one end of the upper connector of the blowout preventer, and a gear-type connector is provided on the cover plate. One end of the gear-type connector is hinged to the cover plate, and the other end is hinged to one end of the upper connector of the blowout preventer. The gear portion of the gear-type connector meshes with the rack portion of the spring-loaded rack and pinion fitting, so that the gear-type connector and the cover plate form a small-angle hinge mechanism.

[0012] In some alternative embodiments, the spring-loaded rack press-fit is inserted into a side hole of the blowout preventer upper connector. The spring-loaded rack press-fit includes a rack rod with a rack portion at the outer end and a spring connected to the inner end. The gear-type connector includes a gear connecting rod with a gear hinge portion at one end and a cover plate hinge portion at the other end. The gear hinge portion has a hinge hole for hinged with the blowout preventer upper connector and gear teeth for meshing with the rack portion.

[0013] In some alternative implementations, the core is provided with a balancing hole that communicates with the annular space between the core and the outer sleeve, and the inner end of the rack pressure bar is provided with a breather hole along the axis to balance the pressure inside and outside the spring mounting hole on the connector side of the blowout preventer.

[0014] A method for operating a blowout preventer with two separate openings and pressurized downpipes, followed by a pumping-out process, characterized by the following steps:

[0015] S1. As described above, the blowout preventer is lowered twice and the pressurized tubing is opened twice to achieve the blowout preventer and pumping operation to the predetermined depth in the well. At this time, during the process of lowering the tool string into the well, the plug achieves the first closure and sealing of the tubing to prevent blowout, until the tubing string is lowered to the predetermined depth in the well.

[0016] S2. After the two blowout prevention and two opening operations with pressure are completed and the blowout prevention and pumping connection string is in place, hydraulic pressure is applied to the tubing. When the opening pressure value of the pump stopper is reached, the pump stopper core falls down and the central flow passage is opened, realizing the first opening flow in the tubing. At this time, the blowout production or sand flushing and well washing can be carried out in the tubing.

[0017] S3. When the blowout production or sand flushing in the tubing is completed, and the wellbore is still in a low-pressure blowout state, a small steel ball is dropped into the tubing at the wellhead. After the steel ball sits on the controllable internal blowout preventer, hydraulic pressure is applied at the wellhead. When the controllable internal blowout preventer closes at the pressure value, its internal core shears the pin, and the steel ball and the controllable internal blowout preventer core fall together. Under the combined action of the spring force and the upward blowout pressure at the bottom of the well, the cover valve flips up and closes the fluid inlet channel. At this time, the controllable internal blowout preventer achieves a second sealing and blowout prevention in the tubing.

[0018] S4. Before lowering the rod pump, insert a large steel ball again. This steel ball will sit on the double-layer sliding sleeve switch, but hydraulic pressure is not applied yet. After achieving a second seal and anti-blowout state in the oil pipe, lower the rod pump to the design position. Do not set the rod pump immediately. At this time, apply hydraulic pressure in the oil pipe. The hydraulic pressure is transmitted to the steel ball of the double-layer sliding sleeve switch through the gap between the rod pump and the oil pipe annular space until the hydraulic pressure knocks off its sliding sleeve core, exposing the side hole of the double-layer sliding sleeve switch. This achieves the second opening and flow passage in the oil pipe, and finally completes the rod pump switching function.

[0019] The beneficial effects of this invention are:

[0020] 1. This invention, through the installation of a rod-type pump support cylinder, a double-layer sliding sleeve switch, a controllable internal blowout preventer (BOP), a pump stopper, and a screen pipe, achieves the first sealing and blowout prevention within the tubing during downhole operation. After removing the pump stopper core, the central flow channel is fully opened. At this point, the pump stopper enables the first flow opening within the tubing, achieving complete flow throughout the entire tubing string. Blowout production or sand flushing can then be performed within the tubing. After the blowout production or sand flushing is completed, the wellbore remains in a low-pressure blowout state. Small steel balls are inserted into the tubing at the wellhead. Once the steel balls settle on the controllable internal BOP, hydraulic pressure is applied at the wellhead. When the controllable internal BOP's closing pressure value is reached, its internal core shears off the pin, steel balls, and the controllable internal BOP. As the core of the device falls together, the cover valve flips up and closes the fluid inlet channel under the combined action of spring force and upward blowout pressure from the bottom of the well. At this point, the controllable internal blowout preventer achieves a second seal for blowout prevention within the tubing. Before lowering the rod pump, a large steel ball is placed in again. This ball will sit on the double-sleeve switch, but hydraulic pressure is not applied immediately. After achieving a second seal for blowout prevention within the tubing, the rod pump is lowered to the designed position. The rod pump is not set immediately. Hydraulic pressure is applied through the tubing, and the hydraulic pressure is transmitted through the annular space between the rod pump and the tubing to the steel ball on the double-sleeve switch until the hydraulic pressure knocks off the sleeve core, exposing the side hole of the double-sleeve switch. This achieves a second opening for flow within the tubing, ultimately completing the rod pump switching function. This shortens the well occupation time, improves well workover efficiency, reduces or even eliminates the use of kill fluid, lowers construction costs and labor intensity, and avoids the risk of reservoir contamination.

[0021] 2. The double-layer sliding sleeve switch provided in this application not only performs the function of a traditional sliding sleeve switch, such as pressure testing and leak detection of the upper tubing string and opening the oil sleeve connection for flow, but also adds a new function: before opening the sliding sleeve, the connecting hole on the side of the upper connector of the double-layer sliding sleeve switch is kept closed to prevent scaling and prevent impurities from adhering and entering, so as to meet the requirements of normal opening even after long-term immersion in well fluid and after the inner central cavity has been used for production.

[0022] 3. In this invention, a core is installed inside the controllable internal blowout preventer (BOP). This core opens the cover valve, causing it to flip over to one side of the outer casing. This opens the central flow channel inside the downhole controllable internal BOP, allowing pressurized fluid to flow normally out of the wellhead through the downhole tubing, ensuring normal production. When it is necessary to close the flow channel, a steel ball or rod is dropped. After the steel ball or rod sits on the downhole controllable internal BOP, a certain amount of hydraulic pressure is applied at the wellhead. The steel ball or rod, along with the core, falls from inside the downhole controllable internal BOP and lands on the tubing retainer at the bottom of the tubing string. The downhole controllable internal BOP closes instantly upon the core falling. This significantly reduces the waiting time for blowouts in pressurized or fractured wells, shortens the well occupation time, improves well workover efficiency, reduces or even eliminates the use of kill fluid, lowers construction costs and labor intensity, and avoids the risk of reservoir contamination.

[0023] 4. The cover valve with an automatic fine-tuning sealing angle rack and pinion mechanism has a more compact structure and more flexible movement. It not only adds the function of "automatic fine-tuning of the sealing angle, which can achieve complete sealing of the cover valve by relying on the spring force", but also allows the width and thickness of the rack and pinion mechanism to be smaller and more compact. It is also easier to ensure both sufficient flow channel size and a smaller maximum outer diameter of the tool. This is very important for its use as a flow valve or blowout preventer in various small-specification sleeves. In other words, the new invention tool has greater versatility and adaptability. Attached Figure Description

[0024] To more clearly illustrate the technical solutions of the embodiments of the present invention, the accompanying drawings used in the embodiments will be briefly introduced below. It should be understood that the following drawings only show some embodiments of the present invention and should not be regarded as a limitation on the scope. For those skilled in the art, other related drawings can be obtained based on these drawings without creative effort.

[0025] Figure 1 This is a schematic diagram of the blowout prevention and blowout switching combined operation pipe column structure provided in an embodiment of the present invention (in the first closed state).

[0026] Figure 2 This is a schematic diagram of the blowout prevention and extraction coupling system provided in an embodiment of the present invention, showing the system in a single-open state.

[0027] Figure 3 This is a schematic diagram of the state of the rod pump with two blowout prevention and two opening operations under pressure in an embodiment of the present invention (secondary shutdown state).

[0028] Figure 4This is a schematic diagram of the state of the rod pump with two blowout prevention and two opening operations under pressure in an embodiment of the present invention (secondary opening state).

[0029] Figure 5 The diagram shows the combined blowout prevention and extraction system provided in this embodiment of the invention – setting and extraction (secondary opening state).

[0030] Figure 6 A schematic diagram of a double-layer sliding sleeve switch structure in full-bore flow state provided in an embodiment of this application.

[0031] Figure 7 A schematic diagram of a double-layer sliding sleeve switch structure for opening the side overcurrent state provided in an embodiment of this application.

[0032] Figure 8 A three-dimensional sectional view (fully open state) of a downhole controllable internal blowout preventer provided in an embodiment of the present invention;

[0033] Figure 9 for Figure 8 AA sectional view.

[0034] Figure 10 for Figure 8 BB cross-sectional view.

[0035] Figure 11 A schematic diagram of the cover valve is provided for an embodiment of the present invention.

[0036] Figure 12 A half-sectional view (start-up and shut-down state) of a downhole controllable internal blowout preventer provided in an embodiment of the present invention.

[0037] Figures 13a-13e This is a schematic diagram showing the various dimensions of the cover valve provided in an embodiment of the present invention.

[0038] Figure 14 This is a cross-sectional view of a rack and pinion mechanism cover valve with automatic fine-tuning sealing angle provided in Embodiment 2 of the present invention.

[0039] Figure 15 This is a schematic diagram of the open state of the cover valve in Embodiment 2 of the present invention.

[0040] Figure 16 This is a schematic diagram of the rack and pinion linkage in Embodiment 2 of the present invention.

[0041] Figures 17-18 This is a schematic diagram illustrating the automatic fine-tuning sealing angle principle of the rack and pinion type cover valve in Embodiment 2 of the present invention.

[0042] In the diagram: 1—Upper connector; 1-1—Front bracket; 1-2—Rear bracket; 1-3—Upper connector sealing ring; 1-4—Sealing steel ring; 2—Outer sleeve; 3—Core; 3-1—Balance hole; 3-2—Core sealing ring; 4—Cover valve; 4-1—Cover valve support leg; 5—Pin; 6—Torsion spring; 7—Sealing gasket; 8—Shear pin seat; 9—Shear pin; 10—Lower connector; 10-1—Lower connector sealing ring; 11—Steel ball; 12—Cotter pin; 13—Rack and pinion rod; 14—Gear connecting rod; 15—Pin; 16—Support leg; 17—Compression spring; 18— 19—Cotter pin; 20—Cover plate; 20-1—Bracket; 21—Sealing ring; 22—Valve body; 23—Breath hole; 24—Upper connector; 24-1—Connecting hole; 25—Inner sliding sleeve; 26—Outer sliding sleeve; 27—Inner shear pin; 28—Outer shear pin; 29—Inner rubber ring; 30—Outer rubber ring; 31—Lower connector; 32—Steel ball; 33—Inner bore step chamfer; Ⅰ—Oil pipe string; Ⅱ—Rod pump support cylinder; Ⅲ—Anti-sand and scale double-layer sliding sleeve switch; Ⅳ—Controllable internal blowout preventer; Ⅴ—Pump lower plug; Ⅵ—Screw tube; Ⅶ—Sucker rod string; Ⅷ—Rod pump. Detailed Implementation

[0043] To make the objectives, technical solutions, and advantages of the embodiments of the present invention clearer, the technical solutions of the embodiments of the present invention will be clearly and completely described below with reference to the accompanying drawings. Obviously, the described embodiments are only some embodiments of the present invention, and not all embodiments. The components of the embodiments of the present invention described and shown in the accompanying drawings can generally be arranged and designed in various different configurations.

[0044] Therefore, the following detailed description of the embodiments of the invention provided in the accompanying drawings is not intended to limit the scope of the claimed invention, but merely to illustrate selected embodiments of the invention. All other embodiments obtained by those skilled in the art based on the embodiments of the invention without inventive effort are within the scope of protection of the invention.

[0045] The features and performance of the present invention will be further described in detail below with reference to embodiments.

[0046] Example 1:

[0047] like Figure 1-5 As shown, this embodiment provides a two-stage blowout preventer, two-stage opening, pressurized run-in blowout preventer-to-pump connection string, including, from top to bottom, a rod-type pump support cylinder II, a double-sleeve switch III, a controllable internal blowout preventer IV, a pump stopper V, and a screen pipe VI. All tools are connected via a tubing string I. The run-in tubing string is as follows... Figure 1 — Figure 5As shown, the tools are connected by a single continuous tubing or a tubing section. The tubing section refers to a shorter tubing length than a single continuous tubing. In the oil and gas industry, the length of a typical continuous tubing is 9.4–9.6 meters; therefore, the tubing section referred to here is generally ≤6.0 meters long. In the technical solution adopted in the above invention, the tubing section typically has a length of 0.5–2 meters. The screen pipe VI in the above invention, also known as an internal tubing catcher, is a simple downhole tool with an open sidewall and a sealed bottom. Its main function is to allow flow through the side and catch any debris falling into the tubing at the bottom.

[0048] In this embodiment, the rod pump support cylinder II is equipped with a rod pump VIII, and the upper end of the rod pump VIII is connected to a sucker rod string VII. The rod pump adopts a structure in the prior art, which will not be described in detail here.

[0049] like Figure 6 , Figure 7 The double-layer sliding sleeve switch shown includes an upper connector 24 and a lower connector 31. The upper connector has a connecting hole 24-1 that connects the inner and outer sides of the upper connector. An inner sliding sleeve 25 and an outer sliding sleeve 26 are respectively sealed to the inner and outer sides of the connecting hole 24-1 on the upper connector 24. The upper and lower ends of the inner sliding sleeve 25 are sealed to the inner wall of the upper connector via sealing rings 29 to close the inner side of the connecting hole. The upper and lower ends of the outer sliding sleeve 26 are sealed to the outer wall of the upper connector via sealing rings 30 to close the outer side of the connecting hole. The inner sliding sleeve 25 and the outer sliding sleeve 26 are connected to the upper connector 24 of the double-layer sliding sleeve switch via the inner shear pin 27 and the outer shear pin 28, respectively. The upper end of the inner sliding sleeve 25 is provided with a conical surface that is configured with the sealing ball. The outer diameter of the lower connector of the double-layer sliding sleeve switch is larger than the outer diameter of the outer sliding sleeve 26, so that the outer sliding sleeve 26 is limited by the lower connector 31 of the double-layer sliding sleeve switch when it slides down.

[0050] In this embodiment, a gap is provided between the outer sliding sleeve 26 and the outer side of the upper connector 24 of the double-layer sliding sleeve switch, forming an annular space. A stepped surface is provided on the inner side of the lower end of the outer sliding sleeve 26. An inner hole step chamfer 33 is provided on the inner side of the lower end of the upper connector 24 of the double-layer sliding sleeve switch. The inner diameter of the inner hole step chamfer 33 is smaller than the outer diameter of the inner sliding sleeve 25, so that when the inner sliding sleeve 25 falls to this point, it can be supported, forming a rigid hard seal. The sealing rings 29 at the upper and lower ends of the inner sliding sleeve 25 correspond to the upper sealing surface and lower sealing surface of the inner wall of the double-layer sliding sleeve switch upper connector 24, respectively. The distance from the chamfer 33 of the inner hole step to the lower sealing surface of the inner wall of the double-layer sliding sleeve switch upper connector is equal to the distance between the upper and lower sealing surfaces of the inner wall of the double-layer sliding sleeve switch upper connector. This ensures that after the inner sliding sleeve 25 falls, its upper sealing surface is exactly on the inner wall sealing surface of the double-layer sliding sleeve switch upper connector where the lower sealing ring was located before the inner sliding sleeve was knocked off, thus forming a secondary sealing surface. Figure 7 As shown.

[0051] like Figure 7 As shown, when the double-layer sliding sleeve switch needs to be opened, a sealing ball 32 (steel ball or ball rod) of the corresponding specification is inserted into the wellhead. The sealing ball 32 sits on the inner sliding sleeve 25. Hydraulic pressure is applied to the wellhead to form a pressure shear that cuts the inner shear pin 27, and then the inner sliding sleeve 25 is knocked off. After the inner sliding sleeve 25 falls off, the outer circle of its bottom end forms a rigid hard seal with the chamfered surface 33 of the inner hole step of the upper connector of the double-layer sliding sleeve switch. At the same time, the upper inner sealing ring of the inner sliding sleeve 25 is exactly on the sealing surface of the inner wall of the upper connector of the double-layer sliding sleeve switch where the lower inner sealing ring is located before the core is knocked off, thus forming a sealing ring seal, and the sealing ball 32 is always seated on the inner sliding sleeve 25. That is, the moment the sealing ball 32 sits on the inner sliding sleeve 25 and is knocked off, a secondary seal is formed, and a secondary pressure is also formed inside the upper connector 24 of the double-layer sliding sleeve switch. Hydraulic pressure is transmitted to the outer sleeve 26 through the side connecting hole 24-1 of the upper connector 24 of the double-sleeve switch. Under the pressure difference between the inside and outside of the tubing, the outer shear pin 28 is sheared again, causing the outer sleeve 26 to be knocked off and fall onto the lower connector 31 of the double-sleeve switch, preventing it from falling into the well. Ultimately, the side connecting hole 24-1 of the upper connector of the double-sleeve switch is fully exposed, enabling fluid flow through the tubing. Because the inner and outer sleeves completely seal and enclose the side connecting hole 24-1 of the upper connector 24 of the double-sleeve switch, the connecting hole 24-1 is protected from well fluid corrosion until the sleeves open, thus fulfilling the performance requirements of preventing scaling or the entry of impurities.

[0052] In this embodiment, before cutting the inner shear pin 27 and removing the inner sliding sleeve 25, the sealing performance of the tubing above the double-sleeve switch can be verified by pressure testing.

[0053] In this embodiment, besides as Figure 6 , Figure 7As shown, the outer shear pin 28 is placed at the upper end of the outer sliding sleeve 26. Alternatively, the outer shear pin 28 can be placed below the lower sealing ring 30 of the outer sliding sleeve 26. When the outer sliding sleeve 26 is knocked off and falls and is limited to the lower connector 31 of the double-layer sliding sleeve switch, the top opening end of the outer sliding sleeve 26 is still slightly higher than the position of the outer shear pin hole. This ensures that the broken end of the outer shear pin 28 falls into the inner part of the outer sliding sleeve 26 and will not fall into the wellbore, thus preventing the problem of tools getting stuck in the well.

[0054] In this embodiment, the maximum outer diameter of the outer sliding sleeve 26 is smaller than the maximum outer diameter of the upper connector 24 of the double-layer sliding sleeve switch and also smaller than the maximum outer diameter of the lower connector 31 of the double-layer sliding sleeve switch, so as to avoid the outer sliding sleeve 26 being bumped during the hoisting and lowering of the well.

[0055] In this embodiment, the connecting hole 24-1 on the connector 24 of the double-layer sliding sleeve switch can adopt a long oval large channel flow hole structure, or it can adopt a multi-set long strip slotted screen filter structure. The multi-set long strip slotted screen filter structure can effectively filter impurities such as broken rubber and solid fragments remaining in the wellbore, and prevent impurities from being drawn into the production tubing and causing problems such as pump blockage.

[0056] like Figure 8-12 As shown, the controllable internal blowout preventer IV includes a blowout preventer upper connector 1, an outer casing 2, and a blowout preventer lower connector 10 connected sequentially from top to bottom. The lower end of the blowout preventer upper connector 1 is provided with a cover valve 4, and a shear pin seat 8 is sealed inside the lower end of the outer casing 2. A core 3 is sealed inside the holes of the blowout preventer upper connector 1 and the shear pin seat 8. The core 3 opens the cover valve 4 so that it flips over to one side of the outer casing. The core 3 is limited by the limiting member on the shear pin seat 8.

[0057] In this embodiment, a positioning shoulder is provided inside the outer sleeve 2. The upper and lower ends of the shear pin seat 8 abut against the positioning shoulder and the lower connector end face of the blowout preventer, respectively. A sealing gasket is provided at the upper end of the shear pin seat 8. The core 3, with a sealing ring, passes through the upper connector 1, outer sleeve 2, and shear pin seat 8 of the blowout preventer, and achieves sealing with the inner wall of the contact steel body through the upper and lower sealing rings. The limiting component is a shear pin 9, which is located at the bottom end of the core or passes through the side of the core. The bottom end face of the core 3 abuts against the shear pin 9 or is passed through by the shear pin 9 from the side, thereby limiting and fixing the core 3.

[0058] like Figure 8 , Figure 11 , Figure 12As shown, the cover valve includes a front support 1-1 and a rear support 1-2 symmetrically arranged at the lower end of the upper connector of the blowout preventer, and a cover plate 4 hinged to the front support 1-1 via cover plate legs 4-1. The cover plate legs 4-1 are hinged to the two front supports 1-1 via pins 5. A torsion spring 6 is provided at the hinge, with one end of the torsion spring 6 fixed to the cover plate legs 4-1 and the other end fixed to the rear support 1-2. A rubber flat washer is fixed on the flat surface of the cover valve to enhance the sealing effect, and a cotter pin 12 is inserted into the thin end of the pin to prevent detachment. In its natural state, the cover valve, under the elastic force of the torsion spring 6, presses against the sealing steel ring embedded in the inner end face of the upper connector of the blowout preventer, thereby cutting off the upward blowout pressure of the wellbore fluid. Under this upward supporting pressure, the cover valve seal is more reliable. Since the front bracket 1-1 and the rear bracket 1-2 are fixed to one side of the end face of the upper connector 1 of the blowout preventer, the center of the cover plate of the cover valve is eccentric to the axis of the upper connector of the blowout preventer. Furthermore, the inner hole of the upper connector of the blowout preventer is coaxial with the center of the valve plate of the cover valve; that is, the inner hole of the upper connector of the blowout preventer is also an eccentric structure. Figure 8 , Figure 10 As shown.

[0059] The inner hole of the shear pin holder 8 is coaxial with the inner hole of the core 3 and the upper connector 1 of the blowout preventer, therefore the inner hole of the shear pin holder 8 is also an eccentric structure, such as... Figure 8 , Figure 9 As shown. After the core 3 is inserted into the shear pin seat 8 and fixed in place by the upper connector 1 of the blowout preventer, the core 3 opens the cover valve, causing it to fully open and flip over to one side of the cavity. The downhole controllable internal blowout preventer is in a fully open state, and its inner hole channel fully meets the flow requirements of oil, gas, and water production media, and can also meet the injection requirements of fracturing fluid and other injection fluids into the wellbore. The core is equipped with a balance hole 3-1, which allows high pressure to be released into the cavity during fracturing, enabling the downhole controllable internal blowout preventer to achieve high pressure bearing capacity.

[0060] When the wellhead is in a low-pressure overflow state, a steel ball of the appropriate size is dropped into the wellhead. The steel ball sits on the sealing cone surface at the top of the core, and then downward hydraulic pressure is applied from the wellhead. When the downward hydraulic pressure overcomes the upward overflow force and finally reaches the shearing force of the shear pin 9, the pin 9 is sheared off, and the steel ball 11 and the core 3 instantly fall from the upper connector 1 and the inner hole of the shear pin seat 8 of the blowout preventer, falling into the ball receiving basket at the bottom of the tubing string. At this time, the cover valve loses the support of the core and, under the action of the spring force, instantly flips up and presses flat against the sealing steel ring embedded in the end face of the inner hole of the upper connector of the blowout preventer, thereby closing and cutting off the overflow pressure of the downhole fluid, realizing a depressurized state in the wellhead tubing, such as... Figure 12 As shown.

[0061] The pump blocker V includes a housing, and a blocking device is sealed inside the housing. The blocking device is fixed to the housing by a pin.

[0062] When the fluid in the oil and gas wellbore carries a certain pressure, within the wellhead pressure control range for safe well control operations—that is, within the pressure range of the tubing self-sealing sealer (sealing cup) of the wellhead blowout preventer—the casing is connected to a long pipeline and a blowout control valve device at a safe distance to a blowout pool or blowout tank. The downhole tool string of this invention is sequentially connected to and passes through the tubing self-sealing sealer (sealing cup) of the wellhead blowout preventer. Under continuous controlled blowout control of the blowout pipeline at the far end of the casing, the pressure at the tubing self-sealing sealer (sealing cup) is low, achieving complete sealing during the dynamic tubing run-in process.

[0063] This embodiment also provides a method for operating a blowout preventer with two separate openings and pressurized downpipes, including the following steps:

[0064] S1. Lower the tubing string, as described in any one of claims 1-9, to a predetermined depth in the well, using a two-stage blowout preventer and two-stage opening operation with pressurized tubing for blowout prevention and pumping. During this process, the pump-operated plug during the tool string lowering process achieves the first sealing and blowout prevention within the tubing, until the tubing string reaches the predetermined depth in the well. Figure 1 As shown;

[0065] S2. After the blowout preventer has been lowered twice and the pressurized tubing has been used for both blowout prevention and pumping operations, hydraulic pressure is applied to the tubing. When the pressure reaches the opening pressure of the pump stopper, the pump stopper core drops, and the central flow passage is fully opened. At this point, the pump stopper achieves the first flow opening in the tubing, and the entire tubing string achieves complete flow. At this point, blowout prevention production or sand flushing can be performed within the tubing. Figure 2 As shown;

[0066] S3. When the wellbore is still in a low-pressure gushing state after the tubing blowout production or sand flushing is completed, and oil, gas, and water are gushing from the wellhead tubing, it is impossible to lower a rod pump for self-flowing to pumping operations. In this case, there is no need to move the tubing. Simply insert a steel ball of the appropriate size from the wellhead tubing. After the steel ball settles on the controllable internal blowout preventer (BOP), apply hydraulic pressure to the wellhead. When the controllable internal BOP's closing pressure is reached, its internal core shears off the pin, and the steel ball and the controllable internal BOP core fall together. The controllable internal BOP's cover-type BOP valve then flips up and closes the fluid inlet channel under the combined action of spring force and upward gushing pressure from the bottom of the well. At this point, the controllable internal BOP achieves a second sealing and blowout prevention within the tubing. Figure 3 As shown;

[0067] S4. Next, before lowering the rod pump, insert a larger steel ball of the corresponding size. This steel ball will settle on the anti-sand and scale double-layer sliding sleeve switch, but hydraulic pressure will not be applied yet. Afterwards, with the oil pipe in a second sealed anti-blowout state, begin lowering the rod pump (e.g., ...). Figure 3(As shown), until the rod pump is lowered to a depth of about 10 meters above the support cylinder, without setting the rod pump, apply hydraulic pressure through the oil pipe. The hydraulic pressure is transmitted through the gap between the rod pump and the oil pipe annular space to the steel ball of the anti-sand and scale double-layer sliding sleeve switch, until the hydraulic pressure knocks off its sliding sleeve core, exposing the side hole of the anti-sand and scale double-layer sliding sleeve switch, thus realizing the second opening and flow passage in the oil pipe. Figure 4 As shown. Next, the rod pump is seated inside the support cylinder, realizing the rod pump's pumping function, as... Figure 5 As shown.

[0068] In this way, the first run of tubing is pressurized and sealed to prevent blowout. After opening the pump stopper, the tubing is opened for production or sand flushing. Then, the tubing is not raised, and the controllable internal blowout preventer is closed in advance when the rod pump is running the sucker rod. This achieves pressurized and sealed blowout prevention during the second run of the rod pump. Before the rod pump is set and pumped, the anti-sand and scale double-layer sliding sleeve switch is opened to achieve the second opening and flow in the tubing, thus successfully completing the pressurized blowout prevention and rod pumping well completion.

[0069] Example 2:

[0070] This embodiment is basically the same in structure as Embodiment 1, except for the structure of the cover valve of the controllable internal blowout preventer. The reason for improving the cover valve is as follows: Compared with ball valve type single-flow valve or blowout preventer, the cover valve used in the above embodiment has the advantages of flexible opening and closing and a large flow channel after full opening. However, its own structural design also has the following three disadvantages. First, in order to ensure sufficient torsion spring force, the total width t and total thickness h of the cover valve's upper bracket and legs are relatively large, and the lateral thickness h' of the cover in the vertical state after full opening is also relatively large. This means that if the inner diameter D2 of the cover valve connecting housing is constant (the maximum outer diameter of the housing is also constant), the size of its flow path D1 must be reduced, that is, the flow path must be reduced; if the size of the flow path D1 is large enough, the inner diameter D2 of the cover valve connecting housing must be increased accordingly, that is, the maximum outer diameter of the housing must also be increased accordingly (in order to ensure the strength of the steel body, the wall thickness of the housing is relatively fixed). Figures 13a to 13eAs shown. However, for well casings with smaller inner diameters, the maximum outer diameter of the tool is limited. In other words, this traditional bracket-type cover valve is structurally difficult to design to ensure sufficient flow passage while simultaneously maintaining a small maximum outer diameter of the tool. On the other hand, the cover plate, bracket, and legs are all welded or integrally machined, forming a rigid connection. When the cover valve is closed, its contact size with the sealing opening of the flow passage is relatively fixed. Once assembled and fixed, it cannot be adjusted, making overall assembly difficult and resulting in a sealing gap after the cover plate is closed. That is, it is not fully closed under the natural elasticity of the torsion spring. Only when a certain high hydraulic pressure is applied to the cover plate can a complete seal be achieved. Thirdly, to achieve a complete seal under the natural elasticity of the torsion spring, it is necessary to design a larger diameter of the torsion spring wire and increase its stiffness. This makes the torsion spring prone to breakage or shorten its service life when the cover plate opens or closes at an angle of about 90°. At the same time, increasing the size of the torsion spring structure will also lead to an increase in the size of the bracket and legs, which in turn will affect the dimensions of D1, D2, h, h', t, etc. Ultimately, this makes it more difficult for this traditional bracket-type cover valve to ensure both a sufficient flow channel size and a smaller maximum outer diameter of the tool in its structural design.

[0071] Therefore, this embodiment provides a rack and pinion mechanism cover valve that can automatically adjust the sealing angle when the cover valve is closed, ensuring a tight seal under the action of spring force. This design can guarantee sufficient flow channels, a small maximum outer diameter of the tool, and reduce the overall assembly difficulty.

[0072] like Figure 14 , Figure 15 As shown, it includes a valve body 22 (equivalent to the upper connector of the blowout preventer in Embodiment 1) and a cover plate 20 hinged to the valve body 22. A sealing ring 21 is provided at the end of the cover plate that mates with the valve body. A spring-loaded rack and pinion fitting is installed at one end of the valve body 22. A gear-type connector is provided on the cover plate 20. One end of the gear-type connector is hinged to the cover plate 8, and the other end is hinged to one end of the valve body 22. The gear part of the gear-type connector meshes with the rack part of the spring-loaded rack and pinion fitting, so that the gear-type connector and the cover plate form a small-angle hinge mechanism.

[0073] In this embodiment, the spring-loaded rack and pinion fitting is inserted into a hole on one side of the valve body. The spring-loaded rack and pinion fitting includes a rack rod 13, with a rack portion at the outer end and a spring 17 connected to the inner end. The bottom end of the rack rod 13 passes through the spring 17 and is integrally installed into a hole on one side of the valve body. The teeth at the upper end of the rack rod mesh with the teeth of the gear connecting rod to form a gear and rack mechanism.

[0074] The gear-type connector includes a gear link 14, with a gear hinge at one end and a cover plate hinge at the other end. The gear hinge has a hinge hole and gear teeth for meshing with the rack. These gear teeth are sector-shaped, but in this embodiment, they are semi-circular. These semi-circular gear teeth mesh with the rack teeth on the rack pressure rod. A support leg 16 is provided on the valve body 22. A pin 19 passes through the gear tooth hinge hole and then through two symmetrical bushings 18 and the cover plate support leg 16, forming a rotating mechanism. The cover plate hinge and the bracket 20-1 located at the center of the cover plate are hinged by a pin 15, forming a small-angle hinge mechanism. Thus, in this embodiment, the compression spring, rack pressure rod, gear link, support leg hinge, and cover plate bracket hinge constitute a rack and pinion mechanism cover valve capable of automatically fine-tuning the sealing angle.

[0075] The compression spring 17 is always in a compressed state. At the top dead center of the spring, the gear connecting rod is almost horizontal, forcing the cover valve to close and seal against the sealing ring 21, thus closing the flow passage of the valve body 22. Since the gear connecting rod passes through the cover plate bracket 20-1 via the pin 15, forming a small-angle hinge mechanism with the cover plate, the planes of the gear connecting rod and the cover plate have a small angle of movement of 0-α. At the instant the cover plate presses against the sealing ring, under the prying action of the spring force, the cover plate can automatically level and seal. Figure 17 , Figure 18 As shown, when the gear connecting rod rises until the cover is fully open, the compression stroke of the compression spring reaches its maximum.

[0076] To ensure the accuracy of the rack and pinion's vertical movement within the spring hole, the clearance between the lower cylindrical part of the rack and pinion and the spring hole is very small. Therefore, a breather hole 23 with a certain cross-sectional area is provided along the axis of the lower cylindrical part of the rack and pinion (e.g., a small hole). Figure 17 (As shown), this ensures that the pressure in the upper and lower spring holes of the lower cylinder of the rack and pinion is connected and balanced, ensuring that the rack and pinion can move freely up and down under the action of the compression spring, as shown. Figure 14 , Figure 15 As shown.

[0077] The rack and pinion mechanism cover valve of this invention, which automatically adjusts the sealing angle, is more compact and flexible in operation compared to the traditional bracket-type cover valve described in "Example 1". It not only adds the function of "automatically adjusting the sealing angle, achieving complete sealing of the cover valve with just the spring force", but also, under the condition that D1 and D2 dimensions are constant, when the gear linkage rises to fully open the cover, the width and thickness of the rack and pinion mechanism (equivalent to the aforementioned h, h', and t dimensions) can be smaller and more compact. In other words, compared to the traditional bracket-type cover valve, this rack and pinion mechanism cover valve with automatic sealing angle adjustment can more easily ensure both sufficient flow channel size and a smaller maximum tool outer diameter in its structural design. This is crucial for its wider applicability as a single-flow valve or blowout preventer in various small-specification sleeves, meaning that this new invention has greater versatility and adaptability.

[0078] The rack and pinion mechanism cover valve with automatic micro-adjustment of sealing angle invented in this embodiment uses a compression spring, which can be adjusted to a greater force than the traditional torsion spring, and has a longer service life.

[0079] The embodiments described above are some, but not all, embodiments of the present invention. The detailed description of the embodiments of the present invention is not intended to limit the scope of the claimed invention, but merely to illustrate selected embodiments. All other embodiments obtained by those skilled in the art based on the embodiments of the present invention without inventive effort are within the scope of protection of the present invention.

Claims

1. A blowout preventer with two opening and pressurized downpipe, operated by a combined blowout preventer and extraction system, characterized in that: The system includes, from top to bottom, a rod-type pump support cylinder, a double-layer sliding sleeve switch, a controllable internal blowout preventer, a pump underblocker, and a screen pipe. The double-layer sliding sleeve switch includes an upper connector and a lower connector. A connecting hole is provided on the side of the upper connector. An inner sliding sleeve and an outer sliding sleeve are respectively sealed on the inner and outer sides of the connecting hole on the upper connector. The inner and outer sliding sleeves are connected to the upper connector via inner and outer shear pins, respectively. The upper end of the inner sleeve is provided with a conical surface configured with the sealing ball; the controllable inner blowout preventer includes a blowout preventer upper connector, an outer sleeve, and a blowout preventer lower connector connected sequentially from top to bottom. The lower end of the blowout preventer upper connector is provided with a cover valve. A shear pin seat is sealed inside the lower end of the outer sleeve. A core is sealed inside the holes of the blowout preventer upper connector and the shear pin seat. The core opens the cover valve so that it flips onto one side of the outer sleeve. The core is limited by a limiting member on the shear pin seat. The rod pump support cylinder is equipped with a rod pump.

2. The double-blowout, double-opening, pressurized pipe blowout prevention and extraction combined operation string according to claim 1, characterized in that, The lower inner side of the connector of the double-layer sliding sleeve switch is provided with an inner hole step chamfer, and the inner diameter of the inner hole step chamfer is smaller than the outer diameter of the inner sliding sleeve.

3. The double-blowout, double-opening, pressurized pipe blowout prevention and extraction combined operation string according to claim 2, characterized in that, The upper and lower ends of the inner sleeve are respectively sealed to the inner wall of the upper connector of the double-layer sliding sleeve switch by sealing rings, which are used to seal the inner side of the connecting hole. The sealing rings at the upper and lower ends of the inner sleeve correspond to the upper sealing surface and the lower sealing surface of the inner wall of the double-layer sliding sleeve switch, respectively. The distance from the chamfer of the inner hole step to the lower sealing surface of the inner wall of the double-layer sliding sleeve switch is equal to the distance between the upper sealing surface and the lower sealing surface of the inner wall of the double-layer sliding sleeve switch. This ensures that after the inner sleeve falls, its upper sealing surface is exactly on the inner sealing surface of the double-layer sliding sleeve switch where the lower sealing ring was before the inner sleeve was knocked off, thus forming a secondary sealing surface.

4. The double-blowout, double-opening, pressurized pipe blowout prevention and extraction combined operation string according to claim 3, characterized in that, There is a gap between the outer sliding sleeve and the outer side of the upper connector of the double-layer sliding sleeve switch, forming an annular space, and a stepped surface is provided on the inner side of the lower end of the outer sliding sleeve.

5. The double-blowout, double-opening, pressurized pipe blowout prevention and extraction combined operation string according to claim 1 or 2, characterized in that, The connecting hole adopts an elongated oval hole structure or a multi-set elongated slit screen filter structure.

6. The double-blowout, double-opening, pressurized pipe blowout prevention and extraction combined operation string according to claim 1 or 2, characterized in that, The cover valve includes a front support, a rear support, and a cover plate hinged to the front support via cover plate legs, which are symmetrically arranged at the lower end of the upper connector of the blowout preventer. A torsion spring is provided at the hinge, with one end of the torsion spring fixedly connected to the cover plate legs and the other end fixedly connected to the rear support.

7. The double-blowout, double-opening, pressurized pipe blowout prevention and extraction combined operation string according to claim 1 or 2, characterized in that, A spring-loaded rack and pinion fitting is installed at one end of the connector on the blowout preventer. A gear-type connector is provided on the cover plate. One end of the gear-type connector is hinged to the cover plate, and the other end is hinged to one end of the connector on the blowout preventer. The gear part of the gear-type connector meshes with the rack part of the spring-loaded rack and pinion fitting, so that the gear-type connector and the cover plate form a small-angle hinge mechanism.

8. The double-blowout, double-opening, pressurized pipe blowout prevention and extraction combined operation string according to claim 7, characterized in that, The spring-loaded rack and pinion fitting is inserted into a hole on one side of the upper connector of the blowout preventer. The spring-loaded rack and pinion fitting includes a rack rod with a rack portion at the outer end and a spring connected to the inner end. The gear-type connector includes a gear connecting rod with a gear hinge portion at one end and a cover plate hinge portion at the other end. The gear hinge portion has a hinge hole for hinged with the upper connector of the blowout preventer, and the gear hinge portion has gear teeth for meshing with the rack portion.

9. The double-blowout, double-opening, pressurized pipe blowout prevention and extraction combined operation string according to claim 8, characterized in that, The core is provided with a balance hole, which is connected to the annular space between the core and the outer sleeve. The inner end of the rack pressure rod is provided with a breather hole along the axis, so that the pressure inside and outside the compression spring mounting hole on the upper connector side of the blowout preventer is balanced.

10. A method for operating a blowout preventer with two separate openings and pressurized downpipes, followed by a pumping-out operation, characterized by: Includes the following steps: S1. The two-stage blowout prevention and two-stage opening of the pressurized tubing blowout prevention and pumping operation string as described in any one of claims 1-9 is lowered to the predetermined depth in the well. At this time, during the process of lowering the tool string into the well, the plug achieves the first closure and sealing of the tubing to prevent blowout, until the tubing string is lowered to the predetermined depth in the well. S2. After the two blowout prevention and two opening operations with pressure are completed and the blowout prevention and pumping connection string is in place, hydraulic pressure is applied to the tubing. When the opening pressure value of the pump stopper is reached, the pump stopper core falls down and the central flow passage is opened, realizing the first opening flow in the tubing. At this time, the blowout production or sand flushing and well washing can be carried out in the tubing. S3. When the blowout production or sand flushing in the tubing is completed, and the wellbore is still in a low-pressure blowout state, a small steel ball is dropped into the tubing at the wellhead. After the steel ball sits on the controllable internal blowout preventer, hydraulic pressure is applied at the wellhead. When the controllable internal blowout preventer closes at the pressure value, its internal core shears the pin, and the steel ball and the controllable internal blowout preventer core fall together. Under the combined action of the spring force and the upward blowout pressure at the bottom of the well, the cover valve flips up and closes the fluid inlet channel. At this time, the controllable internal blowout preventer achieves a second sealing and blowout prevention in the tubing. S4. Before lowering the rod pump, insert a large steel ball again. This steel ball will sit on the double-layer sliding sleeve switch, but hydraulic pressure is not applied yet. After achieving a second seal and anti-blowout state in the oil pipe, lower the rod pump to the design position. Do not set the rod pump immediately. At this time, apply hydraulic pressure in the oil pipe. The hydraulic pressure is transmitted to the steel ball of the double-layer sliding sleeve switch through the gap between the rod pump and the oil pipe annular space until the hydraulic pressure knocks off the inner sliding sleeve, exposing the connecting hole of the double-layer sliding sleeve switch. This achieves the second opening and flow passage in the oil pipe, and finally completes the rod pump switching function.

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