A device and method for early warning and rapid removal of liquid accumulation in deep water ultra-shallow gas exploitation

Abstract

This invention relates to the field of marine oil and gas resource development technology, and particularly to a device and method for early warning and rapid removal of liquid accumulation in deep-water ultra-shallow gas extraction. The technical solution is as follows: a critical liquid-carrying rate calculation system is used to calculate the critical liquid-carrying rate required to continuously carry liquid from the bottom of the well to the surface under the current operating conditions of the gas well, based on the flow state of the wellbore and the collected real-time operating parameters; a data acquisition device enables continuous data acquisition; a liquid accumulation identification and intelligent early warning system, based on the critical liquid-carrying rate calculation results and real-time flow parameters, determines whether there is a risk of liquid accumulation in the wellbore and provides graded early warnings based on the degree of risk; a dynamic liquid accumulation removal device at the bottom of the well is used to rapidly remove liquid from the bottom of the well and the wellbore when preset conditions are met. The beneficial effects of this invention are: it forms a coordinated control system of monitoring-calculation-early warning-removal-optimization, which can achieve timely identification, accurate early warning, and efficient removal of liquid accumulation risks in the wellbore, thereby improving the continuous and stable production capacity of the gas well.

Description

Technical Field

[0001] This invention relates to the field of marine oil and gas resource development technology, and in particular to a device and method for early warning and rapid removal of liquid accumulation in deep-water ultra-shallow gas extraction. Background Technology

[0002] With the continuous growth of global energy demand, and the abundance of offshore oil and gas resources, especially in deepwater areas, these resources have gradually become a focus of exploration and development in recent years. Deepwater ultra-shallow natural gas resources, due to their abundant reserves and great development potential, have gradually become one of the important areas of offshore oil and gas development. However, because these gas wells are shallowly buried, have low formation compaction, and complex wellbore flow conditions, and are affected by factors such as the deepwater environment, the layout of the subsea production system, and the structural characteristics of the wellbore, they are highly susceptible to wellbore fluid accumulation problems during extraction.

[0003] Liquid accumulation in the wellbore is a common technical challenge in gas well production. When the gas production capacity of a gas well decreases or the gas flow rate within the wellbore falls below the required level for liquid transport, the liquid at the bottom of the well and within the wellbore cannot be effectively carried to the surface by the gas flow. The liquid gradually accumulates within the wellbore, increasing the bottom pressure and weakening the formation's ability to supply gas to the wellbore, leading to a decrease in gas production. In severe cases, wellbore liquid accumulation can cause intermittent or unstable production, and even wellbore failure and shutdown, significantly impacting the safe and efficient development of deep-water and ultra-shallow gas reservoirs. Therefore, how to efficiently predict and quickly remove wellbore liquid accumulation has become a pressing technical challenge in the current development of deep-water and ultra-shallow gas.

[0004] For deep-water ultra-shallow gas extraction, due to the low production of shallow gas, horizontal well extraction methods are often adopted to increase production, and a certain length of open hole section is typically present at the bottom of the well. Given the characteristics of deep-water shallow reservoirs and the temperature and pressure distribution in the wellbore, fluid accumulation in the wellbore is highly likely. Existing technologies for controlling fluid accumulation in gas wells mainly include fluid drainage for gas production, foam drainage, plunger drainage, and intervention based on human experience. While the aforementioned methods can alleviate the problem of wellbore fluid accumulation to some extent, they still have significant shortcomings in deepwater and ultra-shallow gas extraction scenarios: First, existing fluid accumulation identification relies heavily on single production parameters or manual experience, resulting in delayed early warnings and difficulty in timely detecting the formation trend of wellbore fluid accumulation; second, existing fluid drainage measures are mostly single-method approaches, with limited efficiency in clearing fluid accumulation under complex operating conditions, making it difficult to achieve rapid and precise treatment; third, operational intervention in deepwater environments is costly and difficult to implement, and the inability to provide early warnings and rapid response will significantly increase production risks and development costs; fourth, existing technologies are not sufficiently adaptable to the complex wellbore flow conditions and dynamic changes in deepwater and ultra-shallow gas wells, making it difficult to meet the needs of efficient and intelligent fluid drainage and gas extraction. Summary of the Invention

[0005] The purpose of this invention is to address the aforementioned deficiencies in the existing technology by providing a device and method for early warning and rapid removal of liquid accumulation in deep-water and ultra-shallow gas extraction, so as to achieve timely identification, accurate early warning, and efficient removal of liquid accumulation risks in the wellbore, thereby improving the continuous and stable production capacity of gas wells.

[0006] This invention discloses a device for early warning and rapid removal of liquid accumulation in deep-water ultra-shallow gas extraction. The technical solution includes a riser, casing, blowout preventer, and a collaborative control device. The collaborative control device includes a computer and a collaborative control system, further comprising a critical liquid carrying rate calculation system, a data acquisition device, a liquid accumulation identification and intelligent early warning system, and a bottom-hole liquid dynamic removal device. The critical liquid carrying rate calculation system calculates the critical liquid carrying rate required to continuously carry liquid from the bottom of the well to the surface under the current operating conditions, based on the wellbore flow state and collected real-time operating parameters. The data acquisition device continuously acquires data and transmits the acquired data via a monitoring data transmission fiber optic cable to the critical liquid carrying rate calculation system and the liquid accumulation identification and intelligent early warning system. The liquid accumulation identification and intelligent early warning system, based on the calculation results of the critical liquid carrying rate calculation system and real-time flow parameters, determines whether there is a risk of liquid accumulation in the wellbore and provides graded early warnings based on the degree of risk. The bottom-hole liquid dynamic removal device rapidly removes liquid from the bottom of the well and the wellbore when preset conditions are met. The bottom hole fluid dynamic removal device includes a bubbler injection component, a plunger discharge component, and a wellhead fluid collection tank. The bubbler injection component is located at the wellhead and is used to quantitatively inject bubbler into the bottom hole or the fluid accumulation area of ​​the wellbore. The plunger discharge component is used to form an effective mechanical lifting and liquid column pushing effect in the wellbore, so that the accumulated fluid is discharged to the wellhead fluid collection tank.

[0007] Preferably, the aforementioned data acquisition device includes a downhole monitoring data transmission fiber optic cable, a wellhead flow monitoring system, valves, a wellhead pressure monitoring point, a wellhead temperature monitoring point, a downhole pressure signal receiving system, a downhole temperature signal receiving system, a downhole flow signal receiving system, and a downhole detection system. The casing is located in the wellbore where natural gas, water, and accumulated liquid are produced. The wellhead flow monitoring system, valves, wellhead pressure monitoring point, wellhead temperature monitoring point, downhole pressure signal receiving system, downhole temperature signal receiving system, and downhole flow signal receiving system are located at the wellhead end of the casing. The downhole detection system is installed at the bottom of the well via the downhole monitoring data transmission fiber optic cable and is used to collect real-time operating parameters and wellbore structural parameters during the gas well production process.

[0008] Preferably, the above-mentioned bubbler injection assembly includes a bubbler injection pipeline, a bubbler flow meter, a bubbler injection valve, a bubbler injection pump, and a bubbler storage tank. The input end of the bubbler injection pump is connected to the bubbler storage tank through a pipeline, and the output end of the bubbler injection pump is connected to a sleeve through the bubbler injection pipeline, the bubbler injection valve, and the bubbler flow meter. The bubbler flow meter, the bubbler injection valve, and the bubbler injection pump are respectively connected to the collaborative control system through signal lines.

[0009] Preferably, the plunger drainage assembly includes an air lift valve, a plunger, a spring, a check valve, a plunger valve, and a cylinder. Multiple air lift valves are installed at the outer end of the cylinder, a plunger is installed inside the cylinder, a spring is installed at the right end of the plunger, a check valve is installed at the right end of the spring, and a plunger valve is installed on the plunger. The accumulated liquid is lifted by the plunger.

[0010] Preferably, the above-mentioned critical liquid carrying rate calculation system establishes a critical liquid carrying rate calculation model based on gas density, liquid density, gas-liquid interfacial tension, wellbore pressure, temperature, wellbore diameter, and fluid flow state. The model parameters are then modified by incorporating the unique wellbore temperature and pressure variation characteristics of deep-water ultra-shallow gas wells, so that the calculation results can truly reflect the wellbore liquid carrying capacity under the current operating conditions.

[0011] Preferably, the aforementioned liquid accumulation detection and intelligent early warning system compares and analyzes the actual gas rising velocity, gas production rate change rate, bottom hole pressure rate change rate, wellhead back pressure change, production fluctuation amplitude, pressure recovery characteristics, and historical liquid accumulation removal effect parameters with the calculated results of the critical liquid carrying rate. When the actual flow velocity is close to the critical liquid carrying rate, the system determines that the wellbore is in a liquid accumulation sensitive state. When the actual flow velocity is continuously lower than the critical liquid carrying rate and is accompanied by an increase in bottom hole pressure, a decrease in gas production, or abnormal fluctuations in production, the system determines that the wellbore has entered a liquid accumulation early warning state. When the actual flow velocity is significantly lower than the critical liquid carrying rate and the wellbore pressure difference is abnormal and the production capacity decline is significant, the system determines that the wellbore has formed a serious liquid accumulation state and outputs a high-level early warning signal to the collaborative control module.

[0012] Preferably, the above-mentioned liquid accumulation identification and intelligent early warning system classifies the liquid accumulation risk into at least three levels, including Level 1 attention warning, Level 2 intervention warning, and Level 3 rapid removal warning. Specifically, Level 1 attention warning corresponds to the actual working condition being close to the critical liquid-carrying boundary but before obvious liquid accumulation has formed; Level 2 intervention warning corresponds to the liquid starting to accumulate in the wellbore and causing an initial impact on production; and Level 3 rapid removal warning corresponds to the formation of an obvious liquid column at the bottom of the well or in the wellbore, requiring immediate initiation of the removal procedure.

[0013] Preferably, the aforementioned collaborative control system dynamically configures the plunger operating parameters and the bubbler injection parameters based on the current wellbore operating conditions, the degree of fluid accumulation at the bottom of the well, and historical removal effects.

[0014] The method of using the liquid accumulation early warning and rapid removal device in deep-water ultra-shallow gas extraction mentioned in this invention includes the following process: I. Input static parameters of gas wells and establish basic models In the process of deep-water ultra-shallow gas extraction, the static parameters of the target gas well are first entered into the critical fluid carrying rate calculation system to establish a basic database of the gas well. The entered content includes well depth, casing size, wellbore trajectory, well inclination angle, wellbore structural parameters and fluid physical property parameters. These parameters are used for subsequent calculation of the critical fluid carrying parameters of the wellbore. The interfacial tension σ between gas and liquid is calculated using the following formula: (1), (2), (3), In the formula, P represents the pressure of the natural gas, in MPa; After the basic database is established, the system generates the wellbore geometric model and the initial flow model into the critical fluid carrying rate calculation system, providing a basis for subsequent dynamic calculations; II. Input and update dynamic production data in real time. After the gas well enters normal production, the downhole monitoring system installed downhole monitors the data inside the wellbore in real time. The downhole temperature, downhole pressure, gas production, and liquid production are transmitted to the downhole pressure signal receiving system, downhole temperature signal receiving system, and downhole flow signal receiving system via downhole monitoring data transmission fiber optic cable, and are also transmitted in real time to the critical liquid carrying rate calculation system. The wellhead flow monitoring system, wellhead pressure monitoring point, and wellhead temperature monitoring point collect the wellhead monitoring data in real time and transmit it in real time to the critical liquid carrying rate calculation system. The dynamic data detected above serves as the real-time input for wellbore condition identification and liquid accumulation judgment. III. Calculation of wellbore pressure and temperature distribution at different production stages The system uses wellhead pressure and wellhead temperature as boundary conditions, and divides the wellbore by unit length. ΔL i The calculation is performed in discrete segments, and the pressure and temperature of each segment are solved recursively. For the i-th segment, the outlet temperature of the segment is first calculated based on the heat transfer model, and the outlet temperature satisfies the following: (4), in, T i Let T be the inlet temperature of the i-th segment. i+1 Let i be the outlet temperature of the i-th segment. G T This is the geothermal gradient correction term. U i Let be the overall heat transfer coefficient of the i-th segment. Tei Let m be the ambient temperature of the i-th segment, and m be the fluid mass flow rate. C p For isobaric specific heat capacity, ΔL i Let be the length of the i-th segment; IV. Calculation of critical liquid-carrying velocity and critical liquid-carrying flow rate After obtaining the temperature and pressure distribution in the wellbore, the system analyzes the fluid flow state of the gas well and calculates the critical fluid-carrying velocity under the current operating conditions based on the critical fluid-carrying model, using the following formula: (9), Among them, v cr ρ is the critical fluid-carrying velocity of the gas well, in m / s; σ is the gas-liquid interfacial tension; l ρ is the density of the liquid. g θ is the gas density; θ is the wellbore inclination angle. Based on the pressure, temperature, gas-liquid density, and inclination angle parameters at different depths, the corresponding critical fluid-carrying velocity is calculated. Then, combined with the effective flow cross-sectional area of ​​each wellbore section, the critical fluid-carrying velocity is converted into the critical fluid-carrying flow rate. Q cr : (10) In the formula, Z represents the natural gas compressibility factor, which is dimensionless. In this process, the critical liquid carrying rate calculation system not only outputs the critical liquid carrying flow rate value at a single moment, but also outputs the critical liquid carrying flow rate change curves at different production stages and different depths, thus providing a basis for subsequent liquid accumulation trend analysis. 5. Compare the critical liquid-carrying flow rate with the actual gas production rate to determine the amount and location of accumulated liquid. The system will measure the actual gas production. Q g With critical liquid carrying flow rate Q cr When comparing, Q g > Q cr At that time, it was determined that the gas well had no liquid accumulation; when Q g < Q cr At that time, it was determined that the gas well had accumulated liquid; (11), in, Q g This represents the actual gas production of the gas well, expressed in tens of thousands of cubic meters per day. Q crThe critical fluid-carrying flow rate of the gas well is expressed in 10,000 cubic meters per day. The fluid accumulation identification and intelligent early warning system combines the critical fluid-carrying flow rate of the gas well in the wellbore with changes in fluid holdup along the wellbore, temperature and pressure distribution, and fluid production changes to determine the specific location and degree of fluid accumulation. VI. Initiate the liquid removal procedure according to the warning level. After the liquid accumulation detection and intelligent early warning system outputs an early warning signal, the collaborative control system selects the appropriate removal strategy based on the amount of liquid accumulation, the location of the liquid accumulation, and the early warning level: For Level 1 warnings, the system adopts light intervention measures such as strengthening monitoring, increasing data sampling frequency, and optimizing production procedures to delay the formation of effluent; For the secondary warning, the liquid accumulation judgment and intelligent warning system activates the foaming agent injection system, and the collaborative control system controls the foaming agent injection pump to inject the foaming agent from the foaming agent storage tank into the liquid accumulation area at the bottom of the well through the foaming agent injection pipeline via the foaming agent injection valve; For Level 3 warning, the liquid accumulation detection and intelligent warning system activates the plunger drainage component and works in conjunction with the foaming agent injection component. VII. Dynamically adjust the cleaning parameters and evaluate the cleaning effect. During the process of clearing accumulated fluid, the critical fluid carrying rate calculation system continuously monitors the wellhead pressure, bottom hole pressure, fluid production, gas production, and plunger operating status. If insufficient foaming effect is found, the foaming agent concentration is increased, the injection volume is adjusted, or the injection rhythm is changed. If the plunger is obstructed from returning upwards or the fluid drainage efficiency is low, the plunger insertion depth, operating cycle, or start / stop threshold is adjusted. After a round of cleaning is completed, the collaborative control system and computer conduct a comprehensive evaluation of the cleaning effect. If the actual gas production after cleaning is higher than the critical fluid carrying flow rate again, and the bottom hole pressure decreases and the gas production returns to stability, then the cleaning is deemed effective and the collaborative control system exits the fluid removal procedure. If the actual gas production after cleaning is still lower than the critical fluid carrying flow rate, then the fluid has not been completely removed and the collaborative control system enters the next round of fluid removal procedure. 8. Establish long-term monitoring, early warning, and liquid accumulation removal mechanisms. After completing one round of fluid removal, the critical fluid carrying rate calculation system continues to collect static and dynamic production data, repeatedly executing the wellbore temperature and pressure distribution calculation, critical fluid carrying parameter calculation, fluid identification, and removal control process. Through long-term rolling monitoring, the collaborative control system analyzes the changes in critical fluid carrying flow rate in the wellbore, the formation pattern of fluid in the wellbore, and the differences in removal effects during different production periods, gradually forming parameter templates and experience databases applicable to target wells or similar well groups.

[0015] Preferably, step three also includes the following process: The system combines wellbore structure, well inclination angle, and multiphase flow state to solve for the pressure gradient of the i-th segment of the wellbore. The total pressure gradient of the wellbore is expressed as the sum of gravity pressure drop, friction pressure drop, and acceleration pressure drop terms, i.e.: (5), Preferably, the pressure gradient calculation formula is: (6), Where, ρ m Let g be the gas-liquid miscibility density, g be the gravitational acceleration, θ be the well inclination angle, and ƒ be the friction coefficient. m Where D is the miscible flow velocity and D is the wellbore inner diameter; The gas-liquid miscibility density is calculated based on the liquid holdup as follows: (7), in, H l For liquid holdup, ρ l For the density of the liquid, ρ g Let be the gas density; after obtaining the average pressure gradient of the i-th segment, calculate the outlet pressure of that segment: (8), in, P i Let the inlet pressure be the i-th segment. P i+1 To calculate the outlet pressure of the i-th segment, after solving for the temperature and pressure of the current calculation segment, set the outlet temperature T of that segment as the outlet pressure. i+1 and export pressure P i+1 As the entry boundary condition for the next calculation segment, the calculation is carried out segment by segment towards the bottom of the well until the temperature and pressure fields along the entire wellbore are completed. Based on the obtained temperature and pressure distribution models of the wellbore at different production stages, the gas density, liquid density, interfacial tension, liquid holdup and critical liquid-carrying velocity of each well segment are further calculated to determine the location, amount and trend of liquid accumulation in the wellbore.

[0016] Compared with the prior art, the beneficial effects of the present invention are as follows: The present invention collects flow parameters at the wellhead, downhole, and wellbore in real time, dynamically calculates the current fluid carrying capacity of the wellbore using a critical fluid carrying rate model, and classifies and intelligently warns of fluid accumulation risk in the wellbore based on the deviation between the calculation results and the actual production state; after detecting a tendency for fluid accumulation or the formation of fluid accumulation in the wellbore, the bottom-hole fluid dynamic removal module is activated, and the fluid accumulation in the bottom-hole and wellbore is quickly removed through the synergistic action of the plunger fluid drainage component and the bubble agent injection component; at the same time, the plunger operating parameters and bubble agent injection parameters are dynamically corrected based on the feedback parameters during the removal process, thereby forming a monitoring-calculation-early warning-removal-optimization synergistic control system, improving the continuous production capacity and fluid drainage and gas production efficiency of deepwater ultra-shallow gas wells; Furthermore, this invention does not passively address fluid accumulation after it forms, but rather identifies and provides graded warnings of wellbore fluid accumulation risks based on dynamic calculation of critical fluid-carrying rates and real-time flow parameter analysis, effectively solving the problem of delayed warnings in existing technologies. This invention organically combines plunger drainage with bubble agent injection, selecting single or synergistic removal modes according to different levels of fluid accumulation and well conditions, resulting in higher drainage efficiency and stronger adaptability to operating conditions compared to single bubble or plunger drainage methods. By setting up a synergistic control module, this invention achieves coordinated operations of warning, control, execution, and feedback, adjusting control parameters according to the complex and variable temperature and pressure conditions and flow states of deep-water ultra-shallow gas wells, significantly improving the targeting and accuracy of fluid removal. This invention reduces the reliance on manual experience and frequent human intervention on offshore platforms, lowering deep-water operation costs, shortening fault response time, and improving the stability and economy of continuous gas well production. It is applicable to deep-water ultra-shallow gas wells, deep-water low-yield and low-pressure gas wells, and similar offshore gas wells with periodic fluid accumulation problems, possessing significant engineering promotion value. Attached Figure Description

[0017] Figure 1 This is a schematic diagram of the structure when the present invention is in use; Figure 2 This is a schematic diagram of the operation of the plunger drainage assembly; Figure 3 This is a schematic diagram of the plunger drainage assembly during drainage. Figure 4 This is a schematic diagram of the state of the plunger drainage assembly after drainage; Figure 5 This is a schematic diagram of the method flow of the present invention; In the diagram: 1. Critical fluid carrying rate calculation system; 2. Monitoring data transmission fiber optic cable; 3. Computer; 4. Wellhead flow monitoring system; 5. Valve; 6. Wellhead pressure monitoring point; 7. Wellhead temperature monitoring point; 8. Downhole pressure signal receiving system; 9. Downhole temperature signal receiving system; 10. Downhole flow signal receiving system; 11. Fluid accumulation discrimination and intelligent early warning system; 12. Collaborative control system; 13. Wellhead fluid accumulation collection tank; 14. Bubble injector pipeline; 15. Bubble injector flow meter; 16. Bubble injector valve; 17. Bubble injector pump; 18. Bubble injector storage tank; 19. Riser; 20. Casing; 21. Blowout preventer; 22. Downhole monitoring data transmission fiber optic cable; 23. Shallow gas reservoir; 24. Cementing sheath; 25. Submarine shallow layer; 26. Gas lift valve; 27. Plunger; 28. Spring; 29. ​​Check valve; 30. Downhole detection system; 31. Plunger valve; 32. Fluid accumulation; 33. Cylinder; 34. Gas injection device. Detailed Implementation

[0018] The preferred embodiments of the present invention will be described below with reference to the accompanying drawings. It should be understood that the preferred embodiments described herein are for illustration and explanation only and are not intended to limit the present invention.

[0019] Example 1, referring to Figures 1-4 This invention discloses a device for early warning and rapid removal of liquid accumulation in deep-water ultra-shallow gas extraction, comprising a riser 19, casing 20, blowout preventer 21, and a collaborative control device. The collaborative control device includes a computer 3 and a collaborative control system 12, further comprising a critical liquid carrying rate calculation system 1, a data acquisition device, a liquid accumulation discrimination and intelligent early warning system 11, and a bottom-hole liquid dynamic removal device. The critical liquid carrying rate calculation system 1 calculates the critical liquid carrying rate required to continuously carry liquid from the bottom of the well to the surface under the current operating conditions, based on the wellbore flow state and collected real-time operating parameters. The data acquisition device continuously acquires data and transmits the acquired data to the critical liquid carrying rate calculation system 1 and the liquid accumulation discrimination and intelligent early warning system 11 via a monitoring data transmission fiber optic cable 2. The liquid accumulation discrimination and intelligent early warning system 11 determines whether there is a risk of liquid accumulation in the wellbore based on the calculation results of the critical liquid carrying rate calculation system 1 and real-time flow parameters, and provides graded early warnings based on the degree of risk. The bottom-hole liquid dynamic removal device rapidly removes liquid from the bottom of the well and the wellbore when preset conditions are met. The bottom hole fluid dynamic removal device includes a bubbler injection component, a plunger discharge component, and a wellhead fluid collection tank 13. The bubbler injection component is located at the wellhead and is used to quantitatively inject bubbler into the bottom hole or the fluid accumulation area of ​​the wellbore. The plunger discharge component is used to form an effective mechanical lifting and liquid column pushing effect in the wellbore, so that the accumulated fluid is discharged to the wellhead fluid collection tank 13.

[0020] The data acquisition device mentioned in this invention includes a downhole monitoring data transmission fiber optic cable 22, a wellhead flow monitoring system 4, a valve 5, a wellhead pressure monitoring point 6, a wellhead temperature monitoring point 7, a downhole pressure signal receiving system 8, a downhole temperature signal receiving system 9, a downhole flow signal receiving system 10, and a downhole detection system 30. The casing 20 is located in the wellbore, producing natural gas, water, and liquid 32 from the shallow gas reservoir 23. The wellhead flow monitoring system 4, valve 5, wellhead pressure monitoring point 6, wellhead temperature monitoring point 7, downhole pressure signal receiving system 8, downhole temperature signal receiving system 9, and downhole flow signal receiving system 10 are located at the wellhead end of the casing 20. The downhole detection system 30 is installed at the bottom of the well via the downhole monitoring data transmission fiber optic cable 22 and is used to collect real-time operating parameters and wellbore structural parameters during the gas well production process.

[0021] The gas-injector injection assembly mentioned in this invention includes a gas-injector injection pipeline 14, a gas-injector flow meter 15, a gas-injector injection valve 16, a gas-injector injection pump 17, and a gas-injector storage tank 18. The input end of the gas-injector injection pump 17 is connected to the gas-injector storage tank 18 through a pipeline, and the output end of the gas-injector injection pump 17 is connected to the sleeve 20 through the gas-injector injection pipeline 14, the gas-injector injection valve 16, and the gas-injector flow meter 15. The gas-injector flow meter 15, the gas-injector injection valve 16, and the gas-injector injection pump 17 are respectively connected to the collaborative control system 12 through signal lines.

[0022] The plunger drainage assembly mentioned in this invention includes an air lift valve 26, a plunger 27, a spring 28, a check valve 29, a plunger valve 31, and a cylinder 33. Multiple air lift valves 26 are installed at the outer end of the cylinder 33. The plunger 27 is installed inside the cylinder 33. A spring 28 is installed at the right end of the plunger 27, and a check valve 29 is installed at the right end of the spring 28. The plunger valve 31 is installed on the plunger 27. The accumulated liquid 32 is lifted by the plunger 27. The upper end of the cylinder 33 is connected to an oil pipe, and the cylinder 33 is located in the horizontal section of the casing 20 in the shallow seabed layer 25. The location is such that above the shallow seabed layer 25 is a shallow gas reservoir 23, and the upper side of the casing 20 near the surface is a cementing sheath 24. A blowout preventer 21 is installed at the wellhead on the seabed surface. A riser 19 is installed on the upper part of the blowout preventer 21 all the way to the water surface. The upper part of the casing 20 is located inside the riser 19. A gas injection device 34 is installed on the upper outer side of the riser 19 and is used to inject gas into the annulus between the tubing and the casing 20, thereby driving the corresponding gas lift valve 26, which in turn moves the plunger 27 to achieve the drainage function.

[0023] The critical liquid carrying rate calculation system 1 mentioned in this invention establishes a critical liquid carrying rate calculation model based on gas density, liquid density, gas-liquid interfacial tension, wellbore pressure, temperature, wellbore diameter, and fluid flow state. The model parameters are then modified by incorporating the unique wellbore temperature and pressure variation characteristics of deep-water ultra-shallow gas wells, so that the calculation results can accurately reflect the wellbore's liquid carrying capacity under the current operating conditions. Specifically, the critical liquid carrying rate calculation system 1 is implemented according to the scheme described in steps one to four of the usage method below. Its circuit connection relationship is a conventional technology well known to those skilled in the art and will not be described in detail here.

[0024] The liquid accumulation detection and intelligent early warning system 11 mentioned in this invention judges the liquid accumulation risk based on the critical liquid carrying capacity calculated by the critical liquid carrying rate calculation system 1; on this basis, the liquid accumulation risk is divided into different levels. The actual gas rising velocity, gas production rate change rate, bottom hole pressure rate change rate, wellhead back pressure change, production fluctuation amplitude, pressure recovery characteristics, and historical liquid accumulation removal effect parameters are compared and analyzed with the critical liquid carrying rate calculation results; when the actual flow velocity is close to the critical liquid carrying rate, the system determines that the wellbore is in a liquid accumulation sensitive state; when the actual flow velocity is continuously lower than the critical liquid carrying rate and is accompanied by an increase in bottom hole pressure, a decrease in gas production, or abnormal fluctuations in production, the system determines that the wellbore has entered a liquid accumulation early warning state; when the actual flow velocity is significantly lower than the critical liquid carrying rate and the wellbore pressure difference is abnormal and the production capacity decline is significant, the system determines that the wellbore has formed a serious liquid accumulation state and outputs a high-level early warning signal to the collaborative control module.

[0025] The fluid accumulation detection and intelligent early warning system 11 mentioned in this invention classifies fluid accumulation risk into at least three levels, including a Level 1 attention warning, a Level 2 intervention warning, and a Level 3 rapid removal warning. The Level 1 attention warning corresponds to actual operating conditions approaching the critical fluid-carrying boundary but before significant fluid accumulation has formed; the Level 2 intervention warning corresponds to the beginning of fluid accumulation in the wellbore and its initial impact on production; and the Level 3 rapid removal warning corresponds to the formation of a significant fluid column at the bottom of the well or within the wellbore, requiring immediate initiation of a removal procedure. It should be noted that the aforementioned fluid accumulation detection and intelligent early warning system 11 is implemented according to the method described in step five of the usage method, and its circuit connections are conventional techniques well-known to those skilled in the art, and will not be detailed further.

[0026] The collaborative control system 12 mentioned in this invention dynamically configures the plunger operating parameters and foaming agent injection parameters based on the current wellbore operating conditions, the degree of fluid accumulation at the bottom of the well, and historical removal effects. That is, it selects different fluid removal schemes based on the fluid accumulation assessment and the fluid accumulation risk level output by the intelligent early warning system 11. For a level one early warning, the system mainly strengthens monitoring and increases the data sampling frequency, without taking any further measures. For a level two early warning, the foaming agent injection system is activated. For a level three early warning, the plunger drainage assembly is activated and operates collaboratively with the foaming agent injection assembly. This is the method described in step six of the method, and its circuit connections are conventional techniques well-known to those skilled in the art, and will not be detailed further.

[0027] Reference Figure 5 The method of using the liquid accumulation early warning and rapid removal device in deep-water ultra-shallow gas extraction mentioned in this invention includes the following process: I. Input static parameters of gas wells and establish basic models In the process of deep-water ultra-shallow gas extraction, the basic database of the gas well is established by first inputting the static parameters of the target gas well into the critical fluid carrying rate calculation system 1. The input content includes well depth, casing size, wellbore trajectory, well inclination angle, wellbore structural parameters and fluid physical property parameters. The above parameters are used for subsequent calculation of the critical fluid carrying parameters of the wellbore. The interfacial tension σ between gas and liquid is calculated using the following formula: (1), (2), (3), In the formula, P represents the pressure of the natural gas, in MPa; After the basic database is established, the system generates the wellbore geometric model and the initial flow model to the critical fluid carrying rate calculation system 1, providing a basis for subsequent dynamic calculations; II. Input and update dynamic production data in real time. After the gas well enters normal production, the downhole monitoring system 30 installed downhole monitors the data inside the wellbore in real time. The downhole temperature, downhole pressure, gas production, and liquid production data are transmitted to the downhole pressure signal receiving system 8, downhole temperature signal receiving system 9, and downhole flow rate signal receiving system 10 via the downhole monitoring data transmission fiber optic cable 22, and are also transmitted in real time to the critical liquid carrying rate calculation system 1. The wellhead flow rate monitoring system 4, wellhead pressure monitoring point 6, and wellhead temperature monitoring point 7 collect the wellhead monitoring data in real time and transmit it in real time to the critical liquid carrying rate calculation system 1. The dynamic data detected above are used as real-time input for wellbore condition identification and liquid accumulation judgment. III. Calculation of wellbore pressure and temperature distribution at different production stages The system uses wellhead pressure and wellhead temperature as boundary conditions, and divides the wellbore by unit length. ΔL i The calculation is performed in discrete segments, and the pressure and temperature of each segment are solved recursively. For the i-th segment, the outlet temperature of the segment is first calculated based on the heat transfer model, and the outlet temperature satisfies the following: (4), in, T i Let T be the inlet temperature of the i-th segment. i+1 Let i be the outlet temperature of the i-th segment. G T This is the geothermal gradient correction term. U i Let be the overall heat transfer coefficient of the i-th segment. T ei Let m be the ambient temperature of the i-th segment, and m be the fluid mass flow rate. C p For isobaric specific heat capacity, ΔLi Let be the length of the i-th segment; IV. Calculation of critical liquid-carrying velocity and critical liquid-carrying flow rate After obtaining the temperature and pressure distribution in the wellbore, the system analyzes the fluid flow state of the gas well and calculates the critical fluid-carrying velocity under the current operating conditions based on the critical fluid-carrying model, using the following formula: (9), Among them, v cr ρ is the critical fluid-carrying velocity of the gas well, in m / s; σ is the gas-liquid interfacial tension; l ρ is the density of the liquid. g θ is the gas density; θ is the wellbore inclination angle. Based on the pressure, temperature, gas-liquid density, and inclination angle parameters at different depths, the corresponding critical fluid-carrying velocity is calculated. Then, combined with the effective flow cross-sectional area of ​​each wellbore section, the critical fluid-carrying velocity is converted into the critical fluid-carrying flow rate. Q cr : (10) In the formula, Z represents the natural gas compressibility factor, which is dimensionless. In this process, the critical liquid carrying rate calculation system 1 not only outputs the critical liquid carrying flow rate value at a single moment, but also outputs the critical liquid carrying flow rate change curves at different production stages and different depths, thus providing a basis for subsequent liquid accumulation trend analysis. 5. Compare the critical liquid-carrying flow rate with the actual gas production rate to determine the amount and location of accumulated liquid. The system will measure the actual gas production. Q g With critical liquid carrying flow rate Q cr When comparing, Q g > Q cr At that time, it was determined that the gas well had no liquid accumulation; when Q g < Q cr At that time, it was determined that the gas well had accumulated liquid; (11), in, Q g This represents the actual gas production of the gas well, expressed in tens of thousands of cubic meters per day. Q cr The critical fluid-carrying flow rate of the gas well is expressed in 10,000 cubic meters per day. The liquid accumulation identification and intelligent early warning system 11 combines the critical fluid-carrying flow rate of the gas well in the wellbore with changes in fluid holdup along the flow path, temperature and pressure distribution, and changes in production to determine the specific location and degree of liquid accumulation. VI. Initiate the liquid removal procedure according to the warning level. After the liquid accumulation detection and intelligent early warning system 11 outputs an early warning signal, the collaborative control system 12 selects the appropriate removal strategy based on the amount of liquid accumulation, the location of the liquid accumulation, and the early warning level: For Level 1 warnings, the system mainly adopts light intervention measures such as strengthening monitoring, increasing data sampling frequency, and optimizing production systems to delay the formation of effluent. For the secondary warning, the liquid accumulation judgment and intelligent warning system 11 starts the foaming agent injection system, and the collaborative control system 12 controls the foaming agent injection pump 17 to inject the foaming agent from the foaming agent storage tank 18 into the liquid accumulation area at the bottom of the well through the foaming agent injection pipeline 14 via the foaming agent injection valve 16. For Level 3 warning, the liquid accumulation identification and intelligent warning system 11 activates the plunger drainage component and works in coordination with the foaming agent injection component; VII. Dynamically adjust the cleaning parameters and evaluate the cleaning effect. During the process of clearing accumulated fluid, the critical fluid carrying rate calculation system 1 continuously monitors the wellhead pressure, bottom hole pressure, fluid production, gas production, and plunger operation status. If the foaming effect is insufficient, the foaming agent concentration is increased, the injection volume is adjusted, or the injection rhythm is changed. If the plunger is obstructed or the fluid drainage efficiency is low, the plunger insertion depth, operating cycle, or start / stop threshold is adjusted. After a round of cleaning is completed, the collaborative control system 12 and computer 3 conduct a comprehensive evaluation of the cleaning effect. If the actual gas production after cleaning is higher than the critical fluid carrying flow rate again, and the bottom hole pressure decreases and the gas production returns to stability, then the cleaning is deemed effective and the collaborative control system 12 exits the fluid removal procedure. If the actual gas production after cleaning is still lower than the critical fluid carrying flow rate, then the fluid is deemed not to have been completely removed and the collaborative control system 12 enters the next round of fluid removal procedure. 8. Establish long-term monitoring, early warning, and liquid accumulation removal mechanisms. After completing one round of liquid removal, the critical liquid carrying rate calculation system 1 continues to collect static and dynamic production data, and repeatedly executes the wellbore temperature and pressure distribution calculation, critical liquid carrying parameter calculation, liquid identification and removal control process; through long-term rolling monitoring, the collaborative control system 12 analyzes the changes in critical liquid carrying flow rate in the wellbore, the formation law of liquid in the wellbore and the differences in removal effect in different production periods, and gradually forms parameter templates and experience databases applicable to target wells or similar well groups.

[0028] Preferably, step three above also includes the following process: The system combines wellbore structure, well inclination angle, and multiphase flow state to solve for the pressure gradient of the i-th segment of the wellbore. The total pressure gradient of the wellbore is expressed as the sum of gravity pressure drop, friction pressure drop, and acceleration pressure drop terms, i.e.: (5), Preferably, the pressure gradient calculation formula is: (6), Where, ρ m Let g be the gas-liquid miscibility density, g be the gravitational acceleration, θ be the well inclination angle, and ƒ be the friction coefficient. m Where D is the miscible flow velocity and D is the wellbore inner diameter; The gas-liquid miscibility density is calculated based on the liquid holdup as follows: (7), in, H l For liquid holdup, ρ l For the density of the liquid, ρ g Let be the gas density; after obtaining the average pressure gradient of the i-th segment, calculate the outlet pressure of that segment: (8), in, P i Let the inlet pressure be the i-th segment. P i+1 To calculate the outlet pressure of the i-th segment, after solving for the temperature and pressure of the current calculation segment, set the outlet temperature T of that segment as the outlet pressure. i+1 and export pressure P i+1 As the entry boundary condition for the next calculation segment, the calculation is carried out segment by segment towards the bottom of the well until the temperature and pressure fields along the entire wellbore are completed. Based on the obtained temperature and pressure distribution models of the wellbore at different production stages, the gas density, liquid density, interfacial tension, liquid holdup and critical liquid-carrying velocity of each well segment are further calculated to determine the location, amount and trend of liquid accumulation in the wellbore.

[0029] The above description is merely a partial preferred embodiment of the present invention. Any person skilled in the art can modify the above-described technical solutions or modify them into equivalent technical solutions. Therefore, any simple modifications or equivalent transformations made based on the technical solutions of the present invention fall within the scope of protection claimed by the present invention.

Claims

1. A device for early warning and rapid removal of liquid accumulation in deep-water ultra-shallow gas extraction, comprising a riser (19), a casing (20), a blowout preventer (21), and a collaborative control device, wherein the collaborative control device comprises a computer (3) and a collaborative control system (12), characterized in that: It also includes a critical liquid carrying rate calculation system (1), a data acquisition device, a liquid accumulation discrimination and intelligent early warning system (11), and a bottom-hole liquid dynamic removal device. The critical liquid carrying rate calculation system (1) is used to calculate the critical liquid carrying rate that continuously carries liquid from the bottom of the well to the surface under the current working conditions of the gas well based on the flow state of the wellbore and the collected real-time operating parameters, and obtain the critical liquid carrying capacity. The data acquisition device realizes continuous data acquisition and transmits the collected data to the critical liquid carrying rate calculation system (1) and the liquid accumulation discrimination and intelligent early warning system (11) through the monitoring data transmission fiber (2). The liquid accumulation discrimination and intelligent early warning system (11) judges whether there is a risk of liquid accumulation in the wellbore based on the calculation results of the critical liquid carrying rate calculation system (1) and the real-time flow parameters, and classifies and warns the degree of risk. The bottom-hole liquid dynamic removal device is used to quickly remove the liquid at the bottom of the well and in the wellbore when the preset conditions are met. The bottom hole fluid dynamic removal device includes a bubbler injection component, a plunger discharge component, and a wellhead fluid collection tank (13). The bubbler injection component is located at the wellhead and is used to quantitatively inject bubbler into the bottom hole or the fluid accumulation area of ​​the wellbore. The plunger discharge component is used to form an effective mechanical lifting and liquid column pushing effect in the wellbore, so that the fluid is discharged to the wellhead fluid collection tank (13).

2. The device for early warning and rapid removal of liquid accumulation in deep-water ultra-shallow gas extraction according to claim 1, characterized in that: The data acquisition device includes a downhole monitoring data transmission fiber optic cable (22), a wellhead flow monitoring system (4), a valve (5), a wellhead pressure monitoring point (6), a wellhead temperature monitoring point (7), a downhole pressure signal receiving system (8), a downhole temperature signal receiving system (9), a downhole flow signal receiving system (10), and a downhole detection system (30). The casing (20) is located in the wellbore where natural gas, water, and liquid (32) are produced. The wellhead flow monitoring system (4), valve (5), wellhead pressure monitoring point (6), wellhead temperature monitoring point (7), downhole pressure signal receiving system (8), downhole temperature signal receiving system (9), and downhole flow signal receiving system (10) are located at the wellhead end of the casing (20). The downhole detection system (30) is installed at the bottom of the well via the downhole monitoring data transmission fiber optic cable (22) and is used to collect real-time operating parameters and wellbore structure parameters during the gas well production process.

3. The device for early warning and rapid removal of liquid accumulation in deep-water ultra-shallow gas extraction according to claim 2, characterized in that: The bubbler injection assembly includes a bubbler injection line (14), a bubbler flow meter (15), a bubbler injection valve (16), a bubbler injection pump (17), and a bubbler storage tank (18). The input end of the bubbler injection pump (17) is connected to the bubbler storage tank (18) through a pipeline. The output end of the bubbler injection pump (17) is connected to the sleeve (20) through the bubbler injection line (14), the bubbler injection valve (16), and the bubbler flow meter (15). The bubbler flow meter (15), the bubbler injection valve (16), and the bubbler injection pump (17) are respectively connected to the collaborative control system (12) through signal lines.

4. The device for early warning and rapid removal of liquid accumulation in deep-water ultra-shallow gas extraction according to claim 3, characterized in that: The plunger drainage assembly includes an air lift valve (26), a plunger (27), a spring (28), a check valve (29), a plunger valve (31), and a cylinder (33). Multiple air lift valves (26) are installed at the outer end of the cylinder (33), and a plunger (27) is installed inside the cylinder (33). A spring (28) is installed at the right end of the plunger (27), and a check valve (29) is installed at the right end of the spring (28). A plunger valve (31) is installed on the plunger (27), and the accumulated liquid (32) is lifted by the plunger (27).

5. The device for early warning and rapid removal of liquid accumulation in deep-water ultra-shallow gas extraction according to claim 4, characterized in that: The critical liquid carrying rate calculation system (1) establishes a critical liquid carrying rate calculation model based on gas density, liquid density, gas-liquid interfacial tension, wellbore pressure, temperature, wellbore diameter and fluid flow state, and corrects the model parameters by combining the unique wellbore temperature and pressure change characteristics of deep-water ultra-shallow gas wells, so that the calculation results can truly reflect the wellbore liquid carrying capacity under the current working conditions.

6. The device for early warning and rapid removal of liquid accumulation in deep-water ultra-shallow gas extraction according to claim 5, characterized in that: The liquid accumulation discrimination and intelligent early warning system (11) compares and analyzes the actual gas rising velocity, gas production rate change rate, bottom hole pressure rate change rate, wellhead back pressure change, production fluctuation amplitude, pressure recovery characteristics, and historical liquid accumulation removal effect parameters with the critical liquid carrying rate calculation results. When the actual flow velocity is close to the critical liquid carrying rate, the system determines that the wellbore is in a liquid accumulation sensitive state. When the actual flow velocity is continuously lower than the critical liquid carrying rate and is accompanied by an increase in bottom hole pressure, a decrease in gas production, or abnormal fluctuations in production, the system determines that the wellbore has entered a liquid accumulation early warning state. When the actual flow velocity is significantly lower than the critical liquid carrying rate and the wellbore pressure difference is abnormal and the production capacity is significantly reduced, the system determines that the wellbore has formed a serious liquid accumulation state and outputs a high-level early warning signal to the collaborative control module.

7. The device for early warning and rapid removal of liquid accumulation in deep-water ultra-shallow gas extraction according to claim 6, characterized in that: The liquid accumulation identification and intelligent early warning system (11) divides the liquid accumulation risk into at least three levels, including Level 1 attention warning, Level 2 intervention warning and Level 3 rapid removal warning. Among them, Level 1 attention warning corresponds to the actual working condition being close to the critical liquid carrying boundary but not yet forming obvious liquid accumulation; Level 2 intervention warning corresponds to the liquid starting to accumulate in the wellbore and causing initial impact on production; Level 3 rapid removal warning corresponds to the formation of an obvious liquid column at the bottom of the well or in the wellbore, requiring immediate initiation of the removal procedure.

8. The device for early warning and rapid removal of liquid accumulation in deep-water ultra-shallow gas extraction according to claim 7, characterized in that: The collaborative control system (12) dynamically configures the plunger operating parameters and the bubbler injection parameters according to the current working conditions of the wellbore, the degree of fluid accumulation at the bottom of the well and the historical removal effect.

9. A method of using the liquid accumulation early warning and rapid removal device in deep-water ultra-shallow gas extraction as described in claim 8, characterized in that: The process includes the following: I. Input static parameters of the gas well and establish a basic model In the process of deep-water ultra-shallow gas extraction, the basic database of gas wells is established by first inputting the static parameters of the target gas well into the critical fluid carrying rate calculation system (1). The input content includes well depth, casing size, wellbore trajectory, well inclination angle, wellbore structural parameters and fluid property parameters. The above parameters are used for subsequent calculation of critical fluid carrying parameters of the wellbore. The interfacial tension σ between gas and liquid is calculated using the following formula: （1）， （2）， （3）， In the formula, P represents the pressure of the natural gas, in MPa; After the basic database is established, the system generates the wellbore geometric model and the initial flow model into the critical fluid carrying rate calculation system (1), which provides a basis for subsequent dynamic calculations; II. Input and update dynamic production data in real time. After the gas well enters normal production, the downhole monitoring system (30) installed downhole monitors the data in the wellbore in real time. The bottom hole temperature, bottom hole pressure, gas production and liquid production data are transmitted to the downhole pressure signal receiving system (8), downhole temperature signal receiving system (9) and downhole flow signal receiving system (10) through the downhole monitoring data transmission fiber (22), and transmitted to the critical liquid carrying rate calculation system (1) in real time. The wellhead flow monitoring system (4), wellhead pressure monitoring point (6) and wellhead temperature monitoring point (7) collect the wellhead monitoring data in real time and transmit it to the critical liquid carrying rate calculation system (1) in real time. The dynamic data detected above are used as the real-time input for wellbore condition identification and liquid accumulation judgment. III. Calculation of wellbore pressure and temperature distribution at different production stages The system uses wellhead pressure and wellhead temperature as boundary conditions, and divides the wellbore by unit length. ΔL i The calculation is performed in discrete segments, and the pressure and temperature of each segment are solved recursively. For the i-th segment, the outlet temperature of the segment is first calculated based on the heat transfer model, and the outlet temperature satisfies the following: （4）， in, T i Let T be the inlet temperature of the i-th segment. i+1 Let i be the outlet temperature of the i-th segment. G T This is the geothermal gradient correction term. U i Let be the overall heat transfer coefficient of the i-th segment. T ei Let m be the ambient temperature of the i-th segment, and m be the fluid mass flow rate. C p For isobaric specific heat capacity, ΔL i Let be the length of the i-th segment; IV. Calculation of critical liquid-carrying velocity and critical liquid-carrying flow rate After obtaining the temperature and pressure distribution in the wellbore, the system analyzes the fluid flow state of the gas well and calculates the critical fluid-carrying velocity under the current operating conditions based on the critical fluid-carrying model, using the following formula: （9）， Among them, v cr ρ is the critical fluid-carrying velocity of the gas well, in m / s; σ is the gas-liquid interfacial tension; l ρ is the density of the liquid. g θ is the gas density; θ is the wellbore inclination angle. Based on the pressure, temperature, gas-liquid density, and inclination angle parameters at different depths, the corresponding critical fluid-carrying velocity is calculated. Then, combined with the effective flow cross-sectional area of ​​each wellbore section, the critical fluid-carrying velocity is converted into the critical fluid-carrying flow rate. Q cr : （10）， In the formula, Z represents the natural gas compressibility factor, which is dimensionless. In this process, the critical liquid carrying rate calculation system (1) not only outputs the critical liquid carrying flow rate value at a single moment, but also outputs the critical liquid carrying flow rate change curves at different production stages and different depths, thus providing a basis for subsequent liquid accumulation trend analysis.

5. Compare the critical liquid-carrying flow rate with the actual gas production rate to determine the amount and location of accumulated liquid. The system will measure the actual gas production. Q g With critical liquid carrying flow rate Q cr When comparing, Q g > Q cr At that time, it was determined that the gas well had no liquid accumulation; when Q g < Q cr At that time, it was determined that the gas well had accumulated liquid; （11）， in, Q g This represents the actual gas production of the gas well, expressed in tens of thousands of cubic meters per day. Q cr The critical liquid-carrying flow rate of the gas well is expressed in 10,000 cubic meters per day. The liquid accumulation identification and intelligent early warning system (11) combines the critical liquid-carrying flow rate of the gas well in the wellbore, the change in liquid holdup along the flow path, the temperature and pressure distribution, and the change in production to determine the specific location and degree of liquid accumulation. VI. Initiate the liquid removal procedure according to the warning level. After the liquid accumulation detection and intelligent early warning system (11) outputs an early warning signal, the collaborative control system (12) selects the appropriate removal strategy based on the amount of liquid accumulation, the location of the liquid accumulation, and the early warning level: For Level 1 warnings, the system adopts light intervention measures such as strengthening monitoring, increasing data sampling frequency, and optimizing production procedures to delay the formation of effluent; For the secondary warning, the liquid accumulation identification and intelligent warning system (11) starts the foaming agent injection system, and the collaborative control system (12) controls the foaming agent injection pump (17) to inject the foaming agent in the foaming agent storage tank (18) into the liquid accumulation area at the bottom of the well through the foaming agent injection pipeline (14) via the foaming agent injection valve (16); For the three-level warning, the liquid accumulation discrimination and intelligent warning system (11) starts the plunger drainage component and works in coordination with the foaming agent injection component; VII. Dynamically adjust the cleaning parameters and evaluate the cleaning effect. During the process of clearing accumulated liquid, the critical liquid carrying rate calculation system (1) continuously monitors the wellhead pressure, bottom hole pressure, liquid production, gas production and plunger operation status; if the foaming effect is insufficient, the foaming agent concentration is increased, the injection volume is adjusted or the injection rhythm is changed; if the plunger is blocked or the liquid discharge efficiency is low, the plunger insertion depth, operating cycle or start / stop threshold is adjusted. After a round of cleaning is completed, the collaborative control system (12) and the computer (3) conduct a comprehensive evaluation of the cleaning effect. If the actual gas production after cleaning is higher than the critical fluid carrying flow rate again, and the bottom hole pressure decreases and the gas production returns to stability, then the cleaning is deemed effective and the collaborative control system (12) exits the liquid removal procedure. If the actual gas production after cleaning is still lower than the critical fluid carrying flow rate, then the liquid is deemed not to have been completely removed and the collaborative control system (12) enters the next round of liquid removal procedure.

8. Establish long-term monitoring, early warning, and liquid accumulation removal mechanisms. After completing one round of liquid removal, the critical liquid carrying rate calculation system (1) continues to collect static and dynamic production data and repeatedly executes the wellbore temperature and pressure distribution calculation, critical liquid carrying parameter calculation, liquid identification and removal control process; through long-term rolling monitoring, the collaborative control system (12) analyzes the changes in critical liquid carrying flow rate of the wellbore, the formation law of liquid in the wellbore and the differences in removal effect during different production periods, and gradually forms parameter templates and experience databases applicable to target wells or similar well groups.

10. The method of using the liquid accumulation early warning and rapid removal device in deep-water ultra-shallow gas extraction according to claim 9, characterized in that: In step three, there is also The process includes the following: The system combines wellbore structure, well inclination angle, and multiphase flow state to solve for the pressure gradient of the i-th segment of the wellbore. The total pressure gradient of the wellbore is expressed as the sum of gravity pressure drop, friction pressure drop, and acceleration pressure drop terms, i.e.: （5）， The formula for calculating the pressure gradient is: （6）， Where, ρ m Let g be the gas-liquid miscibility density, g be the gravitational acceleration, θ be the well inclination angle, and ƒ be the friction coefficient. m Where D is the miscible flow velocity and D is the wellbore inner diameter; The gas-liquid miscibility density is calculated based on the liquid holdup as follows: （7）， in, H l For liquid holdup, ρ l For the density of the liquid, ρ g Let the gas density be denoted as ; after obtaining the average pressure gradient of the i-th segment, calculate the outlet pressure of that segment: （8）， in, P i Let the inlet pressure be the i-th segment. P i+1 To calculate the outlet pressure of the i-th segment, after solving for the temperature and pressure of the current calculation segment, set the outlet temperature T of that segment as the outlet pressure. i+1 and export pressure P i+1 As the entry boundary condition for the next calculation segment, the calculation is carried out segment by segment towards the bottom of the well until the temperature and pressure fields along the entire wellbore are completed. Based on the obtained temperature and pressure distribution models of the wellbore at different production stages, the gas density, liquid density, interfacial tension, liquid holdup and critical liquid-carrying velocity of each well segment are further calculated to determine the location, amount and trend of liquid accumulation in the wellbore.

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