Well cementing system and method for offshore natural gas hydrate production wells

Abstract

The application belongs to the technical field of oil and gas fields, and discloses a cementing system and method for a marine natural gas hydrate exploitation well. The cementing system comprises a casing, a drill pipe and a recovery device. The casing is arranged in a wellbore, and a cementing annulus is formed between the casing and the well wall. The drill pipe is used for injecting working fluid and cement slurry into the wellbore. The recovery device comprises a suction module, a backflow pipeline and a lifting pump. The suction module is arranged on a wellhead, the drill pipe penetrates the suction module and extends into the casing, a heat exchange annulus is formed between the drill pipe and the casing, a water injection sub is arranged above the suction module on the drill pipe, and a closable water inlet is arranged on the side wall of the water injection sub. The suction module is used for containing the fluid returned from the cementing annulus and the heat exchange annulus. The cementing system for the marine natural gas hydrate exploitation well can reduce the cementing cost, protect the marine environment, and improve the cementing quality.

Description

Technical Field

[0001] This invention relates to the field of oil and gas field technology, and in particular to a cementing system and cementing method for marine natural gas hydrate production wells. Background Technology

[0002] The current technology for extracting natural gas hydrates in offshore areas is basically similar to that for extracting oil and gas fields in the ocean. Both involve drilling wells to establish gas flow channels and then cementing the well to seal the annulus between the casing and the formation. This isolates different pressure layers, increases the safety barrier of the wellbore, and improves the integrity of the wellbore, preventing oil and gas from escaping through the cement sheath and the cemented surface of the formation, thus avoiding safety and environmental accidents.

[0003] However, conventional offshore oil and gas cementing technology has the following two problems: 1. During the cementing process, the heat released by cement hydration causes the hydrates in the natural gas hydrate reservoir to decompose, causing the decomposed gas to accumulate at the cement sheath and formation cementation surface, creating gas channeling channels, thereby damaging the integrity of the wellbore; 2. When drilling using the riserless drilling method, the drilling fluid is directly discharged into the surrounding seawater after returning from the wellbore, increasing drilling costs and causing serious pollution to the marine environment. Summary of the Invention

[0004] The purpose of this invention is to provide a cementing system and method for marine natural gas hydrate production wells, which can reduce cementing costs, protect the marine environment, and improve cementing quality.

[0005] To achieve this objective, the present invention adopts the following technical solution:

[0006] Cementing systems for offshore natural gas hydrate production wells include:

[0007] The casing is installed in the wellbore, and a cemented annulus is formed between the casing and the well wall;

[0008] A drill pipe, one end of which is mounted on a drilling vessel, is used to inject working fluid and cement slurry into the wellbore.

[0009] The recovery equipment includes a suction module, a return pipeline, and a lift pump. The suction module is installed at the wellhead, and the drill pipe extends through the suction module into the casing, forming a heat exchange annulus between the drill pipe and the casing. A water injection sub is installed on the drill pipe above the suction module, and the side wall of the water injection sub has an openable and closable water inlet. The bottom end of the drill pipe can selectively communicate with the cementing annulus and the heat exchange annulus. The suction module is used to contain the fluid returning upward from the cementing annulus and the heat exchange annulus. One end of the return pipeline is connected to the suction module, and the other end of the return pipeline is connected to the processing equipment on the drilling vessel. The lift pump is installed on the return pipeline.

[0010] The drill pipe has a cementing position and a heat exchange position. In the cementing position, the bottom end of the drill pipe is connected to the cementing annulus, the water inlet is closed, and the working fluid or the cement slurry flows sequentially through the drill pipe and the cementing annulus back to the suction module. In the heat exchange position, the bottom end of the drill pipe is connected to the heat exchange annulus, and the water injection sub is located above the water inlet to form a sealing structure, thereby dividing the interior of the drill pipe into an upper cavity and a lower cavity connected to the water inlet. The water inlet is open, and the lifting pump generates negative pressure in the lower cavity through the heat exchange annulus.

[0011] Preferably, the inner wall of the water injection sub is provided with a sleeve that can move axially. When the drill pipe is in the cementing position, the outer wall of the sleeve is sealed on the water inlet; when the drill pipe is in the heat exchange position, the sleeve slides downward away from the water inlet.

[0012] Preferably, the inner wall of the water injection section is provided with a ball seat for supporting the pressure ball, and the sleeve is disposed below the ball seat along the axial direction of the water injection section and abutting against the ball seat;

[0013] The ball seat can move axially downward under the action of external force to squeeze the sleeve, so that the sleeve slides downward to open the water inlet.

[0014] Preferably, a stop block is provided on the inner wall of the water injection section, and when the drill rod is located at the heat exchange position, the sleeve abuts against the stop block axially.

[0015] Preferably, the bottom end of the sleeve is provided with a single-flow float collar for allowing fluid to pass through in one direction;

[0016] When the drill pipe is in the cementing position, the drill pipe is connected to the single-flow float, and the single-flow float is open; when the drill pipe is in the heat exchange position, the drill pipe is disengaged from the single-flow float, and the single-flow float is closed.

[0017] A cementing method for offshore natural gas hydrate production wells, using the aforementioned offshore natural gas hydrate production well cementing system, includes the following steps:

[0018] S1. Move the drill pipe to the cementing position, start the lifting pump and inject the working fluid into the drill pipe for circulation and well washing;

[0019] S2. Stop injecting the working fluid, inject the isolation fluid and cement slurry into the drill pipe in sequence, and use the displacement fluid to displace the cement slurry to the designed height in the cementing annulus;

[0020] S3. Move the drill rod to the heat exchange position and open the water inlet. The lifting pump generates negative pressure in the lower cavity, causing seawater to flow into the lower cavity through the water inlet. Then, the seawater returns to the suction module through the heat exchange ring cavity and flows out through the return pipeline until the cement slurry solidifies.

[0021] Preferably, step S1, which involves injecting the working fluid into the drill pipe for circulating well washing, includes:

[0022] Completement fluid is injected into the drill pipe and circulated between the drill pipe, the cementing annulus, and the return line.

[0023] Pre-fluid is injected into the drill pipe and circulated between the drill pipe, the cementing annulus, and the return line.

[0024] Preferably, the completion fluid contains a natural gas hydrate decomposition inhibitor.

[0025] Preferably, the pre-fluid contains heat-resistant particles that can be adsorbed onto the well wall.

[0026] Preferably, the cement slurry contains an endothermic phase change material.

[0027] The beneficial effects of this invention are as follows:

[0028] The cementing system for offshore natural gas hydrate production wells provided by this invention features a cementing annulus between the drill pipe and casing. A suction module for containing the upward-flowing fluid is installed at the wellhead. This suction module is connected to processing equipment on the drilling vessel via a return pipeline. When the drill pipe is in the cementing position, its bottom end communicates with the cementing annulus. At this time, the inlet on the water injection sub is closed, and working fluid or cement slurry is injected into the drill pipe and flows into the cementing annulus for cementing operations. Because the suction module can contain the working fluid or cement slurry flowing upward from the cementing annulus during cementing, and a lift pump transports the temporarily stored working fluid or cement slurry from the suction module to the processing equipment on the drilling vessel, the working fluid or cement slurry can be processed and then injected back into the cementing annulus through the drill pipe. This achieves the recycling of the working fluid and cement slurry, reducing the amount of working fluid and cement slurry used and thus lowering cementing costs. Furthermore, the recovery equipment can return the fluid to the wellhead. The working fluid and cement slurry are recycled to prevent them from being directly discharged into the seawater, effectively avoiding pollution to the marine environment. When the drill pipe is in the heat exchange position, the bottom end of the drill pipe is connected to the heat exchange annulus. At this time, the inlet is open. Due to the negative pressure generated in the lower cavity by the lifting pump, the low-temperature seawater outside the drill pipe can flow into the lower cavity of the drill pipe through the inlet under the action of the internal and external pressure difference. It then flows from bottom to top through the heat exchange annulus and enters the suction module. After that, it flows to the drilling ship or is discharged into the seawater through the return pipeline. This allows the low-temperature seawater to circulate in the drill pipe and the heat exchange annulus, so that the low-temperature seawater can continuously convect and exchange heat with the cement slurry in the cementing annulus through the side wall of the casing. This removes most of the heat generated during the hydration of the cement slurry, ensuring that the natural gas hydrate will not be decomposed by heat during the cementing process and generate gas channeling. This ensures the integrity of the wellbore and improves the cementing quality.

[0029] Using this cementing method for marine natural gas hydrate production wells, low-temperature seawater is injected into the heat exchange annulus between the drill pipe and the casing. During the solidification process, the cement slurry in the cementing annulus exchanges heat with the low-temperature seawater through the casing. The low-temperature seawater can carry away most of the heat generated during the hydration of the cement slurry, ensuring that the natural gas hydrate will not decompose due to heat during cementing and thus prevent gas channeling, thereby ensuring the integrity of the production wellbore. In addition, due to the presence of a recovery device, the working fluid and cement slurry can be continuously circulated and injected during cementing, avoiding direct discharge into the seawater, reducing the amount of working fluid and cement slurry used, and protecting the marine environment. Attached Figure Description

[0030] Figure 1 This is a schematic diagram of the cementing system for a marine natural gas hydrate production well when the drill pipe is in the cementing position, according to a specific embodiment of the present invention.

[0031] Figure 2This is a schematic diagram of the cementing system for a marine natural gas hydrate production well when the drill pipe is located in the heat exchange position, according to a specific embodiment of the present invention.

[0032] Figure 3 This is a cross-sectional view of the water injection section when the inlet is closed, provided in a specific embodiment of the present invention;

[0033] Figure 4 This is a cross-sectional view of the water injection section when the inlet is open, provided in a specific embodiment of the present invention;

[0034] Figure 5 This is a schematic diagram of the installation structure of the inhalation module and the sleeve provided in a specific embodiment of the present invention.

[0035] In the picture:

[0036] 100-Cementing annulus;

[0037] 200-Pressure Ball;

[0038] 300 - Drilling vessel;

[0039] 1-Shell; 11-Heat exchange annulus;

[0040] 2-Drill pipe; 21-Water inlet; 22-Sleeve; 23-Ball seat; 24-Upper cavity; 25-Lower cavity; 26-Stop block; 27-Water-proof rubber plug;

[0041] 3-Recovery equipment; 31-Suction module; 32-Return pipeline; 33-Lifting pump. Detailed Implementation

[0042] The present invention will now be described in further detail with reference to the accompanying drawings and embodiments. It should be understood that the specific embodiments described herein are merely illustrative of the invention and not intended to limit it. Furthermore, it should be noted that, for ease of description, the accompanying drawings show only the parts relevant to the present invention, and not all of the structures.

[0043] In the description of this invention, unless otherwise explicitly specified and limited, the terms "connected," "linked," and "fixed" should be interpreted broadly. For example, they can refer to a fixed connection, a detachable connection, or an integral part; they can refer to a mechanical connection or an electrical connection; they can refer to a direct connection or an indirect connection through an intermediate medium; they can refer to the internal communication of two components or the interaction between two components. Those skilled in the art can understand the specific meaning of the above terms in this invention based on the specific circumstances.

[0044] In this invention, unless otherwise explicitly specified and limited, "above" or "below" the second feature can include direct contact between the first and second features, or contact between the first and second features through another feature between them. Furthermore, "above," "over," and "on top" of the second feature includes the first feature directly above or diagonally above the second feature, or simply indicates that the first feature is at a higher horizontal level than the second feature. "Below," "below," and "under" the second feature includes the first feature directly below or diagonally below the second feature, or simply indicates that the first feature is at a lower horizontal level than the second feature.

[0045] In the description of this embodiment, the terms "upper," "lower," "right," and "left," etc., refer to the orientation or positional relationship shown in the accompanying drawings. They are used only for ease of description and simplification of operation, 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, they should not be construed as limitations on the present invention. In addition, the terms "first" and "second" are used only for distinction in description and have no special meaning.

[0046] like Figures 1 to 5As shown, this invention provides a cementing system for marine natural gas hydrate production wells. The system includes a casing 1, a drill pipe 2, and a recovery device 3. The casing 1 is installed in the wellbore, forming a cementing annulus 100 between the casing 1 and the wellbore wall. One end of the drill pipe 2 is mounted on a drilling vessel 300 and is used to inject working fluid and cement slurry into the wellbore. The recovery device 3 includes a suction module 31, a return pipeline 32, and a lift pump 33. The suction module 31 is installed at the wellhead, and the drill pipe 2 extends through the suction module 31 into the casing 1, forming a heat exchange annulus 11 between the drill pipe 2 and the casing 1. A water injection sub is installed on the drill pipe 2 above the suction module 31, and an openable / closable water inlet 21 is provided on the side wall of the water injection sub. The bottom end of the drill pipe 2 can selectively communicate with the cementing annulus 100 and the heat exchange annulus 11. Block 31 is used to contain the fluid returning from the cementing annulus 100 and the heat exchange annulus 11. One end of the return pipeline 32 is connected to the suction module 31, and the other end of the return pipeline 32 is connected to the processing equipment on the drilling vessel 300. The lift pump 33 is installed on the return pipeline 32. The drill pipe 2 has a cementing position and a heat exchange position. In the cementing position, the bottom end of the drill pipe 2 is connected to the cementing annulus 100, the inlet 21 is closed, and the working fluid or cement slurry flows through the drill pipe 2 and the cementing annulus 100 and returns to the suction module 31. In the heat exchange position, the bottom end of the drill pipe 2 is connected to the heat exchange annulus 11. The water injection sub is located above the inlet 21 to form a sealing structure to divide the inside of the drill pipe 2 into an upper cavity 24 and a lower cavity 25 connected to the inlet 21. The inlet 21 is opened, and the lift pump 33 generates negative pressure in the lower cavity 25 through the heat exchange annulus 11.In this embodiment, a water injection sub is installed between two drill pipe sections 2 and connected by threads. When the drill pipe 2 is in the heat exchange position, the water inlet 21 on the water injection sub is located above the suction module 31. A cementing annulus 100 exists between the drill pipe 2 and the casing 1. The wellhead is equipped with a suction module 31 for accommodating the upward-flowing fluid. The suction module 31 is connected to the processing equipment on the drilling vessel 300 via a return pipeline 32. When the drill pipe 2 is in the cementing position, the bottom end of the drill pipe 2 communicates with the cementing annulus 100. At this time, the water inlet 21 is closed, and the working fluid or cement... The slurry is injected into the drill pipe 2 and flows into the cementing annulus 100 for cementing operations. Since the suction module 31 is connected to the cementing annulus 100, it can temporarily store the working fluid or cement slurry returning from the annulus 100 during the cementing process. The suction module 31 then transports the temporarily stored working fluid or cement slurry to the processing equipment on the drilling vessel 300 via the lift pump 33. After processing, the working fluid or cement slurry can be injected back into the cementing annulus 100 through the drill pipe 2, thus achieving the recycling of the working fluid and cement slurry and reducing the need for further processing. The amount of working fluid and cement slurry used is reduced, thereby lowering cementing costs. Furthermore, since the recovery device 3 can recover the working fluid and cement slurry returned to the wellhead, it prevents the cementing fluid and cement slurry from being directly discharged into seawater, effectively avoiding pollution to the marine environment. When the drill pipe 2 is in the heat exchange position, the bottom end of the drill pipe 2 is connected to the heat exchange annulus 11. At this time, the inlet 21 is open. Because the lifting pump 33 generates negative pressure in the lower cavity 25, the low-temperature seawater outside the drill pipe 2 can flow into the lower cavity 25 of the drill pipe 2 through the inlet 21. The seawater flows from bottom to top through the heat exchange annulus 11 and then into the suction module 31. After that, it flows through the return pipeline 32 to the drilling vessel 300 or is discharged into the seawater, thereby circulating the low-temperature seawater in the drill pipe 2 and the heat exchange annulus 11. This allows the low-temperature seawater to continuously convect and exchange heat with the cement slurry in the cementing annulus 100 through the side wall of the casing 1, carrying away most of the heat generated during the hydration of the cement slurry. This ensures that the natural gas hydrate will not be thermally decomposed during the cementing process, thus preventing gas channeling and ensuring the integrity of the wellbore and the quality of the cementing.

[0047] Specifically, the suction module 31 is a piece of equipment in the commonly used watertight drilling fluid recovery technology in this field. The suction module 31 has a funnel-shaped structure and is installed at the wellhead, communicating with the cementing annulus 100 and the heat exchange annulus 11 respectively. The function of the suction module 31 is to temporarily store the working fluid or cement slurry returning upwards. Its specific structure and working principle will not be described in detail here. A watertight rubber plug 27 is provided between the suction module 31 and the drill pipe 2. The watertight rubber plug 27 is installed on the drill pipe 2 and is lowered into the suction module 31 along with the drill pipe 2, thereby sealing the wellbore and the seawater environment. This prevents the seawater outside the wellhead from flowing directly into the return pipeline 32 through the suction module 31 when the subsequent lift pump 33 generates negative pressure through the return pipeline 32. The inlet 21 is located on the water injection sub near the wellhead and above the suction module 31. This location is close to the seabed, where the seawater temperature is lower than the sea surface temperature, approximately 0-5°C. When the drill pipe 2 is in the heat exchange position, the seawater in the area near the wellhead will enter the lower cavity 25 through the inlet 21. The low-temperature seawater can absorb a large amount of heat released by the cement slurry in the cementing annulus 100.

[0048] Furthermore, such as Figure 3 and Figure 4 As shown, a sleeve 22 that can move axially is provided on the inner wall of the water injection sub. When the drill pipe 2 is in the cementing position, the outer wall of the sleeve 22 seals the water inlet 21; when the drill pipe 2 is in the heat exchange position, the sleeve 22 slides downward away from the water inlet 21. In this embodiment, the sleeve 22 is slidably disposed on the inner wall of the water injection sub. The sleeve 22 can block the water inlet 21 and thus close the water inlet 21. Therefore, the opening and closing of the water inlet 21 can be achieved by moving the sleeve 22. The structure is simple and the operation is convenient.

[0049] Specifically, such as Figures 2 to 4 As shown, a ball seat 23 for supporting the pressure-holding ball 200 is provided on the inner wall of the water injection sub. The sleeve 22 is disposed abutting against the ball seat 23 along the axial direction of the water injection sub and below the ball seat 23. The ball seat 23 can move downward along the axial direction under the action of external force to squeeze the sleeve 22, so that the sleeve 22 slides downward to open the water inlet 21. In this embodiment, inserting the pressure-holding ball 200 into the drill pipe 2 and sealing the pressure-holding ball by abutting against the ball seat 23 is a common technical means and method in the art. After the pressure-holding ball 200 falls on the ball seat 23 of the water injection sub, the operator injects liquid into the drill pipe 2 and pressurizes it. Then the ball seat 23 will move downward under the pressure. The sleeve 22 is fixed to the inner wall of the water injection sub by shear pins. The downward movement of the ball seat 23 will squeeze the sleeve 22 and shear the shear pins used to fix the sleeve 22. At this time, the sleeve 22 will move downward under the action of gravity to open the water inlet 21.

[0050] Specifically, such as Figure 3 and Figure 4As shown, a stop block 26 is provided on the inner wall of the water injection sub. When the drill pipe 2 is in the heat exchange position, the sleeve 22 abuts against the stop block 26 axially. In this embodiment, after the sleeve 22 falls to open the water inlet 21, the lower end of the sleeve 22 will abut against the stop block 26 to prevent the sleeve 22 from falling further to the bottom of the drill pipe 2 or entering the casing 1, thus affecting subsequent drilling operations.

[0051] Furthermore, the bottom end of the casing 1 is provided with a single-flow float collar for allowing fluid to pass through in one direction; when the drill pipe 2 is in the cementing position, the drill pipe 2 is connected to the single-flow float collar, and the single-flow float collar is opened; when the drill pipe 2 is in the heat exchange position, the drill pipe 2 is disengaged from the single-flow float collar, and the single-flow float collar is closed. In this embodiment, the single-flow float collar, also known as a float shoe, is a casing accessory commonly used in the insertion cementing process in this field. The single-flow float collar is equipped with a single-flow valve. When the drill pipe 2 is pressed down and inserted into the single-flow float collar, the single-flow valve in the single-flow float collar opens. At this time, the drill pipe 2 is in the cementing position, and the single-flow float collar is connected to the drill pipe 2. Therefore, the fluid in the drill pipe 2 can enter the cementing annulus 100 outside the casing 1 through the single-flow float collar in the direction from top to bottom. When the drill pipe 2 is lifted up and pulled out of the single-flow float collar, the single-flow valve in the single-flow float collar closes. At this time, the drill pipe 2 is in the heat exchange position, and the fluid cannot pass through the single-flow float collar in the directions from top to bottom and from bottom to top.

[0052] This embodiment also provides a cementing method for marine natural gas hydrate production wells, using the aforementioned marine natural gas hydrate production well cementing system, including the following steps:

[0053] S1. Move drill pipe 2 to the cementing position, start lift pump 33 and inject working fluid into drill pipe 2 for circulation and well washing. In this embodiment, before cementing, the operator first uses drill pipe 2 on the drilling vessel 300 to drill the production well to the designed depth. After drilling, the operator uses drill pipe 2 to lower casing 1 into the well to the designed depth and moves drill pipe 2 to the cementing position. At this time, drill pipe 2 is connected to the cementing annulus 100 through the single-flow float collar at the bottom of casing 1. Then, the operator injects working fluid into drill pipe 2. The working fluid enters the cementing annulus 100 through drill pipe 2 and returns to the suction module 31. It then flows back to the processing equipment on the drilling vessel 300 through return pipeline 32. After processing, it is injected back into drill pipe 2 to circulate and clean the wellbore, thereby improving the wellbore properties and facilitating subsequent cementing. Specifically, when drill pipe 2 is in the cementing position, the sleeve 22 is fixed to the inner wall of the water injection sub by shear pins and blocks the water inlet 21, preventing seawater from entering drill pipe 2.

[0054] S2. Stop injecting the working fluid, and sequentially inject the isolation fluid and cement slurry into the drill pipe 2. Then, use the displacement fluid to displace the cement slurry to the designed height in the cementing annulus 100. In this embodiment, after the circulation flushing is completed, the operator injects the isolation fluid into the drill pipe 2, and then injects the cement slurry through the drill pipe 2 according to the designed displacement and design volume. After that, the displacement fluid is injected to displace the cement slurry. The cement slurry will enter the cementing annulus 100 from bottom to top through the single-flow float. Under the action of pressure, the displacement fluid can displace the cement slurry to the specified height in the cementing annulus 100. The isolation fluid is used to separate the flushing fluid from the cement slurry to prevent the cement slurry from mixing with the working fluid and affecting the cementing effect of the cement slurry.

[0055] S3. Move drill rod 2 to the heat exchange position and open inlet 21. Lift pump 33 generates negative pressure in lower cavity 25, causing seawater to flow into lower cavity 25 through inlet 21. Then, the seawater returns to suction module 31 through heat exchange annular cavity and flows out through return pipeline 32 until cement slurry solidifies. In this embodiment, after grouting is completed, the operator lifts drill rod 2 to move it to the heat exchange position. At this time, drill rod 2 is disconnected from single-flow float hoop, the single-flow valve inside the single-flow float hoop is closed, and the bottom end of drill rod 2 is connected to heat exchange annular cavity 11. While lifting drill rod 2, the operator puts pressure ball 200 into drill rod 2 and injects liquid to pressurize it, causing ball seat 23 in water injection section to move downward and cut shear pin of sleeve 22. Sleeve 22 then moves downward, thereby opening inlet 21. Lift pump 33 generates negative pressure in drill rod 2 through return pipeline 32 and heat exchange annular cavity 11. Under the pressure difference, low-temperature seawater flows into the lower cavity 25 of the drill pipe 2 through the inlet 21 and flows from bottom to top through the heat exchange annulus 11, thereby exchanging heat with the cement slurry in the cementing annulus 100 to absorb the heat released during the hydration of the cement slurry. Since the seawater will enter the suction module 31 after heat exchange and be pumped to the drilling vessel 300 or discharged into the sea through the lift pump 33, the low-temperature seawater can continuously enter the drill pipe 2 and the heat exchange annulus 11 through the inlet 21, thereby continuously exchanging heat with the cement slurry in the cementing annulus 100.

[0056] In the above cementing method for offshore natural gas hydrate production wells, a heat exchange annulus 11 is formed between drill pipe 2 and casing 1. After cement slurry is displaced into the cementing annulus 100, the cement slurry in the cementing annulus 100 will release heat during solidification. After the drill pipe 2 is moved to the heat exchange position, low-temperature seawater, under the action of the internal and external pressure difference, enters the lower cavity 25 below the drill pipe 2 through the inlet 21. The low-temperature seawater will enter the heat exchange annulus 11 from the bottom of the drill pipe 2 and flow through the heat exchange annulus 11 in an upward direction, thereby exchanging heat with the cement slurry through the side wall of casing 1, carrying away most of the heat generated during the hydration of the cement slurry, ensuring that the cementing process is successful. During the process, the natural gas hydrate will not decompose due to heat, thus preventing gas channeling and ensuring the integrity of the wellbore. Simultaneously, as the low-temperature seawater flows upwards from the heat exchange annulus 11 after passing through the bottom of the well, the flow of the low-temperature seawater will generate a certain pressure at the bottom of the well, thereby increasing the pressure at the bottom and well wall. This ensures that the pressure at the location of the natural gas hydrate reservoir is within the stability range of the natural gas hydrate, thereby ensuring the stability of the natural gas hydrate and preventing its decomposition. Furthermore, because this method uses recycling equipment 3 to recycle and reuse the working fluid and cement slurry, it greatly reduces the cost of using the working fluid and cement slurry and protects the marine environment.

[0057] Specifically, step S1, which involves injecting working fluid into the drill pipe 2 for circulating well cleaning, includes: injecting completion fluid into the drill pipe 2 and circulating the completion fluid between the drill pipe 2, the cementing annulus 100, and the return line 32; and injecting pre-flush fluid into the drill pipe 2 and circulating the pre-flush fluid between the drill pipe 2, the cementing annulus 100, and the return line 32. In this embodiment, circulating completion fluid and pre-flush fluid in the wellbore are conventional practices in the art, with the aim of cleaning the wellbore and improving wellbore properties.

[0058] Specifically, a natural gas hydrate decomposition inhibitor is added to the completion fluid. This inhibitor is a commonly used chemical substance in the field to inhibit the decomposition of natural gas hydrates. Its main components are inorganic salts such as CaCl2 and NaCl. The inhibitor increases the temperature and pressure required for the decomposition of natural gas hydrates near the wellbore, making it less likely for natural gas hydrates to decompose under normal seafloor temperatures and pressures. Its specific mechanism of action will not be elaborated here. In this embodiment, the completion fluid containing the natural gas hydrate decomposition inhibitor is fully circulated in the production well. The inhibitor penetrates to a certain depth into the formation on both sides of the wellbore, thereby inhibiting the decomposition of natural gas hydrates.

[0059] Specifically, heat-insulating particles are added to the pre-fluid, which can be adsorbed onto the well wall. In this embodiment, the heat-insulating particles are a mixture of chitosan and other polymers, which are poor conductors of heat and can be adsorbed onto the well wall. Specifically, the flushing fluid is fully circulated in the production well. Based on the oleophilic and hydrophilic properties of the metal pipe and the formation clay particles, the heat-insulating particles will be adsorbed onto the well wall, forming a layer of heat-insulating particles on the well wall, thereby reducing the heat from cement slurry hydration entering the formation on both sides of the well wall.

[0060] Specifically, an endothermic phase change material is added to the cement slurry. In this embodiment, the phase change material is a phase change energy storage microsphere commonly used in the art. The phase change energy storage microsphere is made by encapsulating the phase change material PCW-30 as the core material using an in-situ polymerization method. Specifically, the phase change material "smooths and fills the valleys" of the heat released by the hydration of the cement slurry through phase change endothermic processes, so that the heat generated by the hydration of the cement slurry is released evenly, thereby avoiding excessive heat absorption and decomposition of natural gas hydrates.

[0061] 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 will be able to make various obvious changes, readjustments, and substitutions without departing from the scope of protection of the present invention. 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. A cementing system for marine natural gas hydrate production wells, characterized in that, include: A casing (1) is installed in the wellbore, and a cemented annulus (100) is formed between the casing (1) and the well wall; Drill pipe (2), one end of which is mounted on the drilling vessel (300), the drill pipe (2) being used to inject working fluid and cement slurry into the wellbore; Recovery equipment (3), the recovery equipment (3) includes a suction module (31), a return pipeline (32) and a lifting pump (33). The suction module (31) is installed at the wellhead. The drill pipe (2) passes through the suction module (31) and extends into the casing (1). A heat exchange annulus (11) is formed between the drill pipe (2) and the casing (1). A water injection sub is provided on the drill pipe (2) above the suction module (31). An openable and closable water inlet (2) is provided on the side wall of the water injection sub. 1) The bottom end of the drill pipe (2) can be selectively connected to the cementing annulus (100) and the heat exchange annulus (11); the suction module (31) is used to contain the fluid returning upward in the cementing annulus (100) and the heat exchange annulus (11); one end of the return pipeline (32) is connected to the suction module (31), and the other end of the return pipeline (32) is connected to the processing equipment on the drilling vessel (300); the lift pump (33) is installed on the return pipeline (32); The drill pipe (2) has a cementing position and a heat exchange position. In the cementing position, the bottom end of the drill pipe (2) is connected to the cementing annulus (100), the water inlet (21) is closed, and the working fluid or the cement slurry flows sequentially through the drill pipe (2) and the cementing annulus (100) and returns to the suction module (31). In the heat exchange position, the bottom end of the drill pipe (2) is connected to the heat exchange annulus (11), and the water injection sub is located above the water inlet (21) to form a sealing structure to divide the inside of the drill pipe (2) into an upper cavity (24) and a lower cavity (25) connected to the water inlet (21). The water inlet (21) is opened, and the lifting pump (33) generates negative pressure in the lower cavity (25) through the heat exchange annulus (11).

2. The cementing system for marine natural gas hydrate production wells according to claim 1, characterized in that, The inner wall of the water injection sub is provided with a sleeve (22) that can move axially. When the drill pipe (2) is in the cementing position, the outer wall of the sleeve (22) is sealed on the water inlet (21); when the drill pipe (2) is in the heat exchange position, the sleeve (22) slides downward away from the water inlet (21).

3. The cementing system for marine natural gas hydrate production wells according to claim 2, characterized in that, The inner wall of the water injection section is provided with a ball seat (23) for supporting the pressure ball (200), and the sleeve (22) is disposed below the ball seat (23) along the axial direction of the water injection section and abutting against the ball seat (23); The ball seat (23) can move axially downward under the action of external force to squeeze the sleeve (22) so that the sleeve (22) slides downward to open the water inlet (21).

4. The cementing system for marine natural gas hydrate production wells according to claim 3, characterized in that, A stop block (26) is provided on the inner wall of the water injection section. When the drill rod (2) is located in the heat exchange position, the sleeve (22) abuts against the stop block (26) axially.

5. The cementing system for marine natural gas hydrate production wells according to claim 1, characterized in that, The bottom end of the sleeve (1) is provided with a single-flow float collar for allowing fluid to pass through in one direction; When the drill pipe (2) is in the cementing position, the drill pipe (2) is connected to the single-flow float, and the single-flow float is opened; when the drill pipe (2) is in the heat exchange position, the drill pipe (2) is disengaged from the single-flow float, and the single-flow float is closed.

6. A cementing method for marine natural gas hydrate production wells, characterized in that, Using the cementing system for marine natural gas hydrate production wells as described in any one of claims 1-5, the following steps are included: S1. Move the drill pipe (2) to the cementing position, start the lifting pump (33) and inject the working fluid into the drill pipe (2) for circulation and well washing; S2. Stop injecting the working fluid, inject the isolation fluid and cement slurry into the drill pipe (2) in sequence, and use the displacement fluid to replace the cement slurry to the designed height in the cementing annulus (100); S3. Move the drill rod (2) to the heat exchange position and open the inlet (21). The lifting pump (33) generates negative pressure in the lower cavity (25), so that seawater flows into the lower cavity (25) through the inlet (21). Then the seawater returns to the suction module (31) through the heat exchange ring cavity and flows out through the return pipeline (32) until the cement slurry solidifies.

7. The cementing method for marine natural gas hydrate production wells according to claim 6, characterized in that, Step S1, which involves injecting the working fluid into the drill pipe (2) for circulating well washing, includes: Completement fluid is injected into the drill pipe (2) and circulated between the drill pipe (2), the cementing annulus (100) and the return line (32); Pre-fluid is injected into the drill pipe (2) and circulated between the drill pipe (2), the cementing annulus (100) and the return line (32).

8. The cementing method for marine natural gas hydrate production wells according to claim 7, characterized in that, The completion fluid contains a natural gas hydrate decomposition inhibitor.

9. The cementing method for marine natural gas hydrate production wells according to claim 7, characterized in that, The pre-fluid contains heat-resistant particles that can be adsorbed onto the well wall.

10. The cementing method for marine natural gas hydrate production wells according to claim 6, characterized in that, The cement slurry contains an endothermic phase change material.

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