CN116291324A - A Wellbore Temperature and Pressure Control System and Method for Natural Gas Hydrate Exploitation - Google Patents

Abstract

The invention discloses a wellbore temperature and pressure control system and method for natural gas hydrate exploitation, and relates to the technical field of natural gas hydrate exploitation. A protective tube is arranged between the beds, the upper end of the protective tube is installed at the lower end of the sea surface mining device, the lower end of the protective tube is set at the upper end of the seabed, and the wellbore casing is vertically installed at the lower end of the protective tube. The lower end of the wellbore casing passes through the seabed reservoir and is arranged on the upper end of the hydrate reservoir, the open-hole gravel is laid on the upper end of the production layer, and the gas-liquid separation mechanism is arranged inside the protective tube and the wellbore casing. Two sets of electric submersible pump units and two sets of electric heaters flexibly control the temperature and pressure of the fluid in the wellbore casing, and real-time monitoring through several temperature and pressure sensors can effectively prevent the secondary generation of hydrate in the wellbore casing and ensure safety and efficiency Production.

Description

A Wellbore Temperature and Pressure Control System and Method for Natural Gas Hydrate Exploitation

technical field

The invention relates to the technical field of natural gas hydrate exploitation, in particular to a wellbore temperature and pressure control system and method for natural gas hydrate exploitation.

Background technique

At present, the practice of trial production of natural gas hydrate in sea areas shows that, as an economical and effective development method, the depressurization method promotes the decomposition of hydrate by pumping out liquid water and free gas in the reservoir to reduce the reservoir pressure. The main method of trial mining.

In the production process of natural gas hydrate, the most effective tool for pumping reservoir fluid to achieve the depressurization effect is the electric submersible pump.

The depressurization exploitation of natural hydrate realizes the separation of natural gas and water. During the process of lifting the free gas of formation water to the ground, due to the change of temperature and pressure in the wellbore, there is a risk of secondary formation of hydrate, resulting in pipeline blockage. Affect hydrate mining. During the lifting process of formation water and free gas, it is necessary to monitor and control the temperature and pressure of the wellbore to prevent the secondary generation of hydrate in the wellbore.

At present, the mode of installing a set of electric submersible pump unit and electric heater in the wellbore is often used in the process of natural gas hydrate test production. The reservoir fluid is heated by the electric heater and then enters the electric submersible pump unit. The fluid is lifted to the surface, and the temperature and pressure of the hydrate production wellbore are controlled through the joint action of a set of electric submersible pump units and electric heaters. However, since the depth of the hydrate production wellbore is more than 1000 meters, this method has a very limited control effect on the temperature and pressure in the wellbore, and cannot effectively prevent the secondary formation of hydrate in the wellbore. Often, a large amount of hydrate inhibitor is added The method to prevent the secondary generation of hydrate in the wellbore, but this method is costly and easy to pollute the environment.

In view of the above problems, an improved gas hydrate production wellbore temperature and pressure control system and method are now designed.

Contents of the invention

The object of the present invention is to provide a wellbore temperature and pressure control system and method for natural gas hydrate production, so as to solve the problems raised in the above-mentioned background technology.

To achieve the above object, the present invention provides the following technical solutions:

A wellbore temperature and pressure control system for natural gas hydrate production, comprising a sea surface production device, a seabed and a gas-liquid separation mechanism, a protective cylinder is arranged between the sea surface production device and the seabed, and the upper end of the protection cylinder is installed on the sea surface production device The lower end of the protective tube is set on the upper end of the seabed, the lower end of the protective tube is vertically installed with a wellbore casing, and the lower end of the wellbore casing passes through the seabed reservoir and is arranged on the upper end of the hydrate reservoir.

The gas-liquid separation mechanism is arranged inside the protective cylinder and the wellbore casing, and is used for separating the gas-liquid of the produced hydrate.

As a further solution of the present invention: the gas-liquid separation mechanism includes an ESP packer, a liquid flow bypass pipeline, a first closed system suspension, a second closed system suspension and a sand control packer, and the liquid flow bypass pipeline is vertically installed directly on the inner wall of the protective casing, the upper end of the liquid flow bypass pipeline is connected to the sea surface production device on the sea surface, the ESP packer is installed on the upper end of the inner wall of the wellbore casing, and a mining area is formed above the ESP packer liquid annulus, the inside of the ESP packer is equipped with a liquid flow converter, and the liquid output end of the liquid flow converter transports liquid water to the sea surface mining device through the liquid production annulus and the liquid flow bypass pipeline. A separation gas pipeline is installed at the gas output end of the liquid flow converter, and the upper end of the separation gas pipeline is connected to a sea surface mining device on the sea surface.

The sand control packer is installed at the lower end of the side wall of the wellbore casing, and a gas production annulus is formed between the sand control packer and the ESP packer, and a flow channel is provided inside the sand control packer, so No. 5 temperature and pressure sensor is installed at the input end of the internal flow channel of the sand control packer, and the liquid output end of the internal flow channel of the sand control packer is equipped with a lower closed system tank body, and the lower closed system tank body The upper end is provided with a connecting pipeline, the upper end of the connecting pipeline is equipped with an upper closed system tank, the upper end of the upper closed system tank is provided with a separation liquid pipeline, and the upper end of the separation liquid pipeline is installed in the liquid of the liquid flow converter. At the input end, the interior of the upper closed system tank and the lower closed system tank is provided with a regulating component for flexibly regulating the temperature and pressure of the fluid in the wellbore casing.

As a further solution of the present invention: the control assembly includes a power-on submersible pump unit and a lower power-on submersible pump unit, the power-on submersible pump unit is installed inside the tank of the upper closed system, and the power-on submersible pump unit is above the There is a No. 1 temperature and pressure sensor installed inside the tank body of the upper closed system, and an electric heater is installed inside the tank body of the upper closed system below the electric submersible pump unit. No. 2 temperature and pressure sensor is installed inside the tank of the upper closed system, the lower electric submersible pump unit is installed inside the tank of the lower closed system, and No. 3 temperature sensor is installed inside the tank of the lower closed system above the lower electric submersible pump unit. pressure sensor, a lower electric heater is installed inside the tank of the lower closed system below the lower electric submersible pump unit, and a No. The temperature and pressure sensor, the electric submersible pump unit, the electric heater, the submersible pump unit and the electric heater are electrically connected to the sea mining device on the sea surface through control cables.

As a further solution of the present invention: the depth difference between the installation positions of the powered-up submersible pump unit and the powered-down submersible pump unit should be controlled within 400-800 meters.

As a further solution of the present invention: the separation gas pipeline is provided with a BOP and an underwater test tree.

As a further solution of the present invention: a blowout preventer is installed at the lower end of the inner wall of the protective cylinder.

As a further solution of the present invention: the upper end of the mining layer is laid with open-hole gravel for preventing sand production from clogging.

As a further solution of the present invention: the side wall of the wellbore casing is provided with reinforcing ribs for improving the structural strength of the wellbore casing.

As a further solution of the present invention: the connecting pipeline and the tank body of the lower closed system are suspended and connected together through the second closed system, and the separation liquid pipeline is connected together with the tank body of the upper closed system through the first closed system.

A method for using a wellbore temperature and pressure control system for natural gas hydrate production, comprising the following steps:

Step 1: Use the electric submersible pump unit and the electric heater to lift and heat the reservoir fluid, so as to regulate the temperature and pressure of the wellbore. During normal operation, turn on the electric submersible pump unit and the electric heater for hydrate production The formation pressure decreases, and the hydrate decomposes under the pressure reduction. The decomposed gas enters the annulus of the wellbore casing through the channel at the sand control packer, and enters the separated gas pipeline on the upper part of the ESP packer through the liquid flow converter to realize the collection of natural gas. .

Step 2: Due to the pumping effect, the water separated from the hydrate enters the lower electric heater through the oil pipe in the wellbore casing to be heated to prevent the secondary generation of hydrate. The separated water flows out from the lower electric submersible pump unit and enters the upper electric heater through the connecting oil pipe , and then enter the electric submersible pump unit, the upper and lower electric submersible pump units and electric heaters are controlled by steel pipe cables and sea surface mining devices, and the temperature and pressure are monitored in real time by temperature and pressure sensors at five positions in the wellbore to determine the hydration of the production layer. The decomposition rate of hydrates and whether there is a risk of hydrate secondary generation in the wellbore.

Step 3: When it reaches the condition for the secondary generation of hydrate, start the electric submersible pump unit and electric heater to accelerate the extraction efficiency of the fluid in the production layer, and at the same time heat the fluid in the wellbore to increase the hydrate The production efficiency is high, and the secondary generation of hydrate in the wellbore is prevented.

Compared with prior art, the beneficial effect of the present invention is:

The invention flexibly regulates the temperature and pressure of the fluid in the wellbore casing through two sets of electric submersible pump units and two sets of electric heaters, and monitors in real time through several temperature and pressure sensors to effectively prevent the secondary generation of hydrate in the wellbore casing and ensure Safe and efficient production.

Two sets of electric submersible pump units and electric heaters are installed at different depths of the wellbore casing. The temperature and pressure environment in the wellbore casing is monitored in real time through temperature and pressure sensors at different positions. When the rate of hydrate decomposition in the production layer decreases, the electric submersible pump is turned on. The unit and the electric heater can reduce the pressure of the production layer and improve the production efficiency. When the internal temperature and pressure of the wellbore casing and tubing meet the secondary formation of hydrate, the electric heater is turned on to increase the fluid temperature in the tubing and effectively prevent hydrate The secondary generation of the electric submersible pump unit and the electric heater can be flexibly controlled. According to the temperature and pressure sensor data at five positions in the wellbore casing, the electric submersible pump unit and the electric heater can be started and stopped at the same time , can also be started and stopped independently, flexible operation.

Description of drawings

Fig. 1 is a structural schematic diagram of the present invention.

Fig. 2 is a schematic diagram of the path of the production fluid in the present invention.

Fig. 3 is a schematic structural diagram of the liquid flow converter in the present invention.

Among them: 1. Sea surface mining device; 2. Liquid flow bypass pipeline; 3. Separation gas pipeline; 4. Seabed; 5. Control cable; 6. Wellbore casing; 7. No. 1 temperature and pressure sensor; System tank; 9. No. 2 temperature and pressure sensor; 10. Connecting pipeline; 11. No. 3 temperature and pressure sensor; 12. Lower closed system tank; 13. No. 4 temperature and pressure sensor; 14. Sand control packer; 15. Open-hole gravel; 16. No. 5 temperature and pressure sensor; 17. Blowout preventer; 18. Liquid flow converter; 19. ESP packer; 20. Suspension of the first closed system; 23. Suspension of the second closed system; 24. Lower electric submersible pump unit; 25. Lower electric heater; 26. Separation liquid pipeline; 101. Separate water flow path; 102. Separate air flow path.

Detailed ways

The following will clearly and completely describe the technical solutions in the embodiments of the present invention with reference to the accompanying drawings in the embodiments of the present invention. Obviously, the described embodiments are only some, not all, embodiments of the present invention. Based on the embodiments of the present invention, all other embodiments obtained by persons of ordinary skill in the art without making creative efforts belong to the protection scope of the present invention.

Example 1

Please refer to Fig. 1-Fig. 3, in the embodiment of the present invention, a wellbore temperature and pressure control system for natural gas hydrate exploitation includes sea surface exploitation device 1, seabed 4, open-hole gravel 15 and gas-liquid separation mechanism, said sea surface exploitation device 1 A protective tube is arranged between the seabed 4, the upper end of the protective tube is installed on the lower end of the sea surface mining device 1, the lower end of the protective tube is arranged on the upper end of the seabed 4, and the lower end of the protective tube is vertically installed with The wellbore casing 6, the lower end of the wellbore casing 6 passes through the seabed reservoir and is arranged at the upper end of the hydrate reservoir, the open-hole gravel 15 is laid on the upper end of the production layer, and a blowout preventer is installed at the lower end of the inner wall of the protective tube 17.

The gas-liquid separation mechanism is arranged inside the protection cylinder and the wellbore casing 6, and is used for separating the gas-liquid of the produced hydrate.

The gas-liquid separation mechanism includes an ESP packer 19, a liquid bypass pipeline 2, a first closed system suspension 20, a second closed system suspension 23 and a sand control packer 14, and the liquid flow bypass pipeline 2 is vertical Installed on the inner wall of the protective cylinder, the upper end of the liquid flow bypass pipeline 2 is connected to the sea surface production device 1 on the sea surface, the ESP packer 19 is installed on the upper end of the inner wall of the wellbore casing 6, and the ESP packer 19 A liquid production annulus is formed above the ESP packer 19, and a liquid flow converter 18 is installed inside the ESP packer 19, and the liquid output end of the liquid flow converter 18 flows to the sea surface through the liquid production annulus and the liquid flow bypass pipeline 2. The mining device 1 transports liquid water, the gas output end of the liquid flow converter 18 is equipped with a separation gas pipeline 3, and the upper end of the separation gas pipeline 3 is connected to the sea surface mining device 1 on the sea surface, and the separation gas pipeline 3 is provided with BOP and underwater test tree.

The sand control packer 14 is installed at the lower end of the side wall of the wellbore casing 6, and a gas production annulus is formed between the sand control packer 14 and the ESP packer 19, and the inside of the sand control packer 14 is provided with The purpose of the flow channel is to ensure the passage of hydrate separation gas. The input end of the flow channel inside the sand control packer 14 is equipped with a No. 5 temperature and pressure sensor 16, and the liquid in the flow channel inside the sand control packer 14 The output end is equipped with a lower closed system tank body 12, the upper end of the lower closed system tank body 12 is provided with a connecting pipeline 10, and the connecting pipeline 10 and the lower closed system tank body 12 are connected together through the second closed system suspension 23, The upper end of the connecting pipeline 10 is equipped with an upper airtight system tank body 8, and the upper end of the upper airtight system tank body 8 is provided with a separation liquid pipeline 26, and the separation liquid line 26 and the upper airtight system tank body 8 pass through the first airtight The system suspensions 20 are connected together, and the upper end of the separation liquid pipeline 26 is installed at the liquid input end of the liquid flow converter 18 .

Example 2

Please refer to Fig. 1-Fig. 3, the difference between this embodiment and embodiment 1 is that the inside of the upper closed system tank body 8 and the lower closed system tank body 12 is provided with a temperature control system for controlling the temperature of the fluid in the wellbore casing 6. A regulating assembly for flexibly regulating pressure and pressure, the regulating assembly includes an electric submersible pump unit 21 and a lower electric submersible pump unit 24, the electric submersible pump unit 21 is installed inside the upper closed system tank 8, and the upper A temperature and pressure sensor 7 is installed inside the upper closed system tank body 8 above the electric submersible pump unit 21, and an upper electric heater 22 is installed inside the upper closed system tank body 8 below the upper electric submersible pump unit 21. No. 2 temperature and pressure sensor 9 is installed inside the upper closed system tank body 8 between the electric heater 22 and the upper electric submersible pump unit 21, and the lower electric submersible pump unit 24 is installed inside the lower closed system tank body 12. No. 3 temperature and pressure sensor 11 is installed inside the lower closed system tank body 12 above the lower electric submersible pump unit 24, and a lower electric heater 25 is installed inside the lower closed system tank body 12 below the lower electric submersible pump unit 24. No. 4 temperature and pressure sensors 13 are installed inside the lower closed system tank body 12 between the lower electric heater 25 and the lower electric submersible pump unit 24. The unit 24 and the lower electric heater 25 are electrically connected to the sea surface mining device 1 on the sea surface through the control cable 5, and the depth difference between the installation positions of the upper electric submersible pump unit 21 and the lower electric submersible pump unit 24 should be controlled at 400-800 meters .

Compared with the existing technology, two sets of electric submersible pump units and two sets of electric heaters are used to flexibly control the temperature and pressure of the fluid in the wellbore casing 6, and several temperature and pressure sensors are used to monitor in real time, effectively preventing the wellbore casing from 6 The secondary generation of internal hydrate ensures safe and efficient production.

Two sets of electric submersible pump units and electric heaters are installed at different depths of the wellbore casing 6, and the temperature and pressure environment inside the wellbore casing 6 is monitored in real time through temperature and pressure sensors at different positions. The electric submersible pump unit 21 and the electric heater 22 can reduce the pressure of the production layer and improve the production efficiency. When the internal temperature and pressure of the tubing in the casing 6 of the wellbore meet the secondary formation of hydrate, the electric heater 22 is turned on to increase the pressure in the tubing. The fluid temperature can effectively prevent the secondary generation of hydrates. The start and stop of the electric submersible pump unit 21 and the electric heater 22 can be flexibly adjusted. According to the temperature and pressure sensor data at five positions in the wellbore casing 6, they can be started The electric submersible pump unit 21 and the electric heater 22 can be stopped, and can also be started and stopped independently, and the operation is flexible.

The first is that during normal production, the lower electric submersible pump unit 24 and the lower electric heater 25 are turned on. After turning on, the natural gas hydrate is decomposed by decompression and becomes a gas-liquid two-phase flow upward from the bottom of the wellbore casing 6, and the mixed fluid flow After the electric heater and the electric submersible pump unit, the gas-liquid two-phase separation, the gas phase enters the annular space below the ESP packer, combines with the mixed fluid from the reservoir, and flows upward into the ESP packer in the wellbore casing 6 annular space The oil pipe above the device reaches the subsea test tree, and finally enters the sea surface production device through the separated gas pipeline.

The second is that when the hydrate decomposition efficiency of the production layer is reduced or there is a risk of hydrate secondary generation in the wellbore casing 6, during the production process, the temperature and pressure sensors at five positions in the wellbore casing 6 will receive real-time real-time temperature and pressure data The temperature and pressure sensor at the production layer monitors the temperature and pressure of the reservoir. The temperature and pressure data can reflect the decomposition efficiency of reservoir hydrate. The temperature and pressure sensor at the inlet and outlet of the electric submersible pump monitors the temperature and pressure in the oil pipe. The temperature and pressure environment of the fluid, combined with the phase balance data, can determine whether the secondary hydrate is generated. By analyzing the temperature and pressure data at these five locations, the power-on submersible pump unit and the power-on submersible pump unit can be selectively turned on or off. The heater is used to maximize the production efficiency while effectively preventing the secondary generation of hydrates in the wellbore casing 6 and improving the production efficiency.

Example 3

A method for using a wellbore temperature and pressure control system for natural gas hydrate production, comprising the following steps:

Step 1: Use the electric submersible pump unit and the electric heater to lift and heat the reservoir fluid, so as to regulate the temperature and pressure of the wellbore. During normal operation, turn on the electric submersible pump unit and the electric heater for hydrate production Formation pressure drops, hydrate decomposes under reduced pressure, and the decomposed gas enters the annulus of the wellbore casing 6 through the channel at the sand control packer, and enters the separation gas pipeline 3 on the upper part of the ESP packer through the liquid flow converter, realizing natural gas recovery. For the collection of , refer to the separated airflow path 102 in FIG. 2 for details.

Step 2: Due to the pumping effect, the water separated from the hydrate enters the lower electric heater through the inner oil pipe of the wellbore casing 6 to be heated to prevent the secondary generation of hydrate. The heater then enters the electric submersible pump unit. See the separated water flow path 101 in Figure 2 for details. The upper and lower electric submersible pump units and the electric heater are regulated by steel pipe cables and sea surface mining devices. The temperature and pressure at five positions in the wellbore The sensors monitor the temperature and pressure in real time to determine the rate of hydrate decomposition in the production layer and whether there is a risk of hydrate secondary generation in the wellbore.

Step 3: During the hydrate production process, the temperature of the hydrate production layer decreases, and the decomposition efficiency of the hydrate decreases. At the same time, the temperature and pressure of the wellbore casing 6 change continuously with the development of the hydrate. When it reaches the condition for the secondary generation of hydrate, By starting the electric submersible pump unit and the electric heater, the extraction efficiency of the fluid in the production layer is accelerated, and the fluid in the wellbore is heated at the same time, which can improve the production efficiency of hydrate and prevent the secondary generation of hydrate in the wellbore.

It will be apparent to those skilled in the art that the invention is not limited to the details of the above-described exemplary embodiments, but that the invention can be embodied in other specific forms without departing from the spirit or essential characteristics of the invention.

Claims (10)

1. The utility model provides a natural gas hydrate exploitation pit shaft temperature and pressure control system, includes sea exploitation device (1), seabed (4) and gas-liquid separation mechanism, be provided with the protection section of thick bamboo between sea exploitation device (1) and seabed (4), the upper end of protection section of thick bamboo is installed in the lower extreme of sea exploitation device (1), the lower extreme of protection section of thick bamboo sets up the upper end at seabed (4), its characterized in that, the vertical pit shaft sleeve (6) of installing of lower extreme of protection section of thick bamboo, the lower extreme of pit shaft sleeve (6) passes the seabed reservoir and sets up in the hydrate reservoir upper end;

the gas-liquid separation mechanism is arranged in the protective casing and the shaft sleeve (6) and is used for separating gas and liquid of produced hydrate.

2. A natural gas hydrate production wellbore temperature and pressure control system according to claim 1, characterized in that the gas-liquid separation mechanism comprises an ESP packer (19), a liquid flow bypass line (2), a first closed system suspension (20), a second closed system suspension (23) and a sand control packer (14), the liquid flow bypass line (2) is vertically mounted on the inner wall of the protective casing, the upper end of the liquid flow bypass line (2) is connected to the sea surface production device (1) at the sea surface, the ESP packer (19) is mounted on the upper end of the inner wall of the wellbore casing (6), a liquid production annulus is formed above the ESP packer (19), a liquid flow converter (18) is mounted inside the ESP packer (19), the liquid output end of the liquid flow converter (18) delivers liquid water to the sea surface production device (1) through the liquid production annulus and the liquid flow bypass line (2), a gas separation line (3) is mounted at the gas output end of the liquid flow converter (18), and the sea surface device (1) is connected to the upper end of the separation gas line (3);

the sand control packer (14) is installed at the lower end of the side wall of the well casing (6), a gas production annulus is formed between the sand control packer (14) and the ESP packer (19), a flow passage is arranged in the sand control packer (14), a five-temperature-pressure sensor (16) is installed at the input end of the flow passage in the sand control packer (14), a lower airtight system tank body (12) is installed at the liquid output end of the flow passage in the sand control packer (14), a connecting pipeline (10) is arranged at the upper end of the lower airtight system tank body (12), an upper airtight system tank body (8) is installed at the upper end of the connecting pipeline (10), a separation liquid pipeline (26) is arranged at the upper end of the upper airtight system tank body (8), and a flexible regulation and control component for regulating and control of the temperature and the pressure of fluid in the well casing (6) is arranged in the upper airtight system tank body (8) and the lower airtight system tank body (12).

3. The system according to claim 2, wherein the regulating and controlling assembly comprises an upper electric submersible pump unit (21) and a lower electric submersible pump unit (24), the upper electric submersible pump unit (21) is installed inside an upper airtight system tank (8), a first temperature and pressure sensor (7) is installed inside the upper airtight system tank (8) above the upper electric submersible pump unit (21), an upper electric heater (22) is installed inside the upper airtight system tank (8) below the upper electric submersible pump unit (21), a second temperature and pressure sensor (9) is installed inside the upper airtight system tank (8) between the upper electric heater (22) and the upper electric submersible pump unit (21), the lower electric submersible pump unit (24) is installed inside a lower airtight system tank (12), a third temperature and pressure sensor (11) is installed inside the lower airtight system tank (12) above the lower electric submersible pump unit (24), an electric heater (25) is installed inside the lower airtight system tank (12), and the electric submersible pump unit (25) is installed inside the electric submersible pump unit (12) The lower electric submersible pump unit (24) and the lower electric heater (25) are electrically connected with the sea surface exploitation device (1) on the sea surface through the control cable (5).

4. A system for controlling the temperature and pressure of a natural gas hydrate exploitation shaft according to claim 3, wherein the depth difference between the installation positions of the upper electric submersible pump unit (21) and the lower electric submersible pump unit (24) is controlled to be 400-800 m.

5. A natural gas hydrate production wellbore temperature and pressure control system according to claim 2, characterized in that the separated gas pipeline (3) is provided with BOPs and a subsea test tree.

6. A natural gas hydrate production wellbore temperature and pressure control system according to claim 1, characterized in that the lower end of the inner wall of the protective casing is provided with a blowout preventer (17).

7. A natural gas hydrate production wellbore temperature and pressure control system according to claim 1, characterized in that open hole gravel (15) for preventing sand production from clogging is laid on the upper end of the production layer.

8. A natural gas hydrate production wellbore temperature and pressure control system according to claim 1, characterized in that the side wall of the wellbore casing (6) is provided with reinforcing ribs for improving the structural strength of the wellbore casing (6).

9. A natural gas hydrate production wellbore temperature and pressure control system according to claim 2, characterized in that the connecting line (10) and the lower closed system tank (12) are connected together by a second closed system suspension (23), and the separation liquid line (26) and the upper closed system tank (8) are connected together by a first closed system suspension (20).

10. A method of using a natural gas hydrate production wellbore temperature and pressure control system according to any one of claims 1-9, comprising the steps of:

step one: lifting operation and heating are carried out on reservoir fluid by utilizing an electric submersible pump unit and an electric heater, so that the temperature and pressure of a shaft are regulated and controlled, the electric submersible pump unit and the electric heater are started during normal operation, the pressure of hydrate exploitation layers is reduced, the hydrate is decompressed and decomposed, decomposed gas enters the annular space of a shaft sleeve (6) through a channel at a sand prevention packer, and enters a separation gas pipeline (3) at the upper part of the ESP packer through a liquid flow converter, so that natural gas is collected;

step two: due to pumping action, water separated from hydrate enters a lower electric heater through an oil pipe in a shaft sleeve (6) to be heated, so that secondary generation of hydrate is prevented, the separated water flows out from a lower electric submersible pump unit to enter an upper electric heater through a connecting oil pipe and then enters an upper electric submersible pump unit, the lower electric submersible pump unit and the electric heater are regulated and controlled by utilizing a steel pipe cable and a sea surface exploitation device, temperature and pressure are monitored in real time by temperature and pressure sensors at five positions in the shaft, and the decomposition rate of hydrate in an exploitation layer and the risk of secondary generation of hydrate in the shaft can be determined;

step three: when the conditions of secondary generation of the hydrate are reached, the extraction efficiency of the fluid in the well bore is accelerated by starting the electric submersible pump unit and the electric heater, and meanwhile, the fluid in the well bore is heated, so that the extraction efficiency of the hydrate can be improved, and the secondary generation of the hydrate in the well bore is prevented.

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