Shale gas well heat power paraffin removal and circulating gas lift synergistic production method

Abstract

The present application relates to unconventional oil and gas development engineering technical field, especially a kind of shale gas well heat power wax removal and circulating gas lift synergistic stimulation method, it includes with self-produced natural gas as medium, after purification, pressurization heating, by oil jacket annulus injection wellbore, simultaneously realize high temperature melting wax, high pressure scouring wax removal and gas lift liquid discharge, and the gas returned is separated, and more than 90% recycling is used.The present application realizes that wax removal efficiency is ≥95%, liquid discharge efficiency is ≥85%, single well production capacity is increased by more than 30%, and gas source cost is reduced by more than 90%.

Description

Technical Field

[0001] This invention relates to the field of unconventional oil and gas development engineering technology, and in particular to a method for synergistic production enhancement of shale gas wells through thermodynamic dewaxing and circulating gas lift. Background Technology

[0002] Shale gas, as an important unconventional natural gas resource, faces two major production challenges in the later stages of development: wellbore wax deposition and fluid retention due to the low porosity, low permeability, and high wax content of its reservoirs. As formation energy depletes, wax continuously precipitates and deposits on the inner wall of the wellbore tubing, reducing the flow cross-sectional area by 30% to 50% and significantly increasing flow resistance. Simultaneously, condensate and formation water produced from the formation accumulate at the bottom of the well due to insufficient fluid-carrying capacity, increasing the bottom-hole back pressure by 1 to 2 MPa, severely inhibiting gas flow from the reservoir to the wellbore. Even more seriously, wax deposition and fluid retention couple, forming a vicious cycle of wax deposition—fluid retention—decreased production. If not addressed promptly, this can easily lead to a sharp drop in gas well production or even shutdown.

[0003] Currently, the main technologies in the industry for wax removal include mechanical scraping, chemical wax removal, and traditional hot washing wax removal. For fluid drainage, the mainstream technology is nitrogen gas lift, but high-purity nitrogen needs to be purchased externally, and the annual gas source cost per well is 800,000 to 1.2 million yuan. Moreover, the gas injection parameters are mostly set based on experience and cannot be dynamically adjusted according to the actual fluid accumulation in the wellbore, resulting in a drainage efficiency of only 50% to 60%. Summary of the Invention

[0004] The purpose of this invention is to provide a method for synergistic production enhancement of shale gas wells through thermodynamic wax removal and circulating gas lift, in order to solve the technical problems of existing shale gas well wax removal and fluid drainage operations being disconnected, dependent on external media, and causing significant reservoir damage.

[0005] This invention provides a method for synergistic production enhancement of shale gas wells through thermodynamic wax removal and circulating gas lift. The method is executed based on an intelligent control system, which includes a parameter monitoring unit, a logic judgment unit, and an execution unit. The method includes at least the following:

[0006] Step 1. Collect natural gas produced at the wellhead of the target shale gas well as the working medium, and purify it by passing it through a three-stage filter and a molecular sieve dehydration device in sequence; the three-stage filter uses filter elements with a precision of 50μm, 10μm and 5μm in sequence; the molecular sieve dehydration device controls the water dew point of the purified natural gas to be ≤-40℃ and the solid impurity content to be ≤1μm.

[0007] Step 2. The natural gas processed in Step 1 is pressurized to 10MPa–20MPa by a screw compressor and simultaneously heated to 100℃–160℃ by an intelligent electric heating furnace. The heating temperature setting is 30℃–50℃ higher than the wax precipitation point of the crude oil in the target well.

[0008] Step 3. The high-temperature, high-pressure natural gas obtained in Step 2 is continuously injected into the wellbore through the annulus of the casing at an injection velocity of 3 m / s–5 m / s. During the injection process, thermodynamic wax removal and gas lift drainage are performed simultaneously. The thermodynamic wax removal involves direct heat conduction and forced convection between the natural gas at 100℃–160℃ and the inner wall of the tubing, which completely melts the attached wax within 1 to 2 hours. Simultaneously, a pressure of 10 MPa–20 MPa drives the natural gas to form high-speed turbulence in the wellbore, generating shear stress of 0.8 MPa–1.2 MPa, which peels off the molten wax and carries it to the surface with the gas-liquid flow. The gas lift drainage involves mixing the injected gas with the liquid accumulated in the wellbore to form a gas-liquid two-phase flow with a gas volume fraction of 60%–80%, reducing the liquid column density to 400 kg / m³–600 kg / m³, and making the bottomhole flowing pressure 0.5 MPa–1 MPa lower than the formation pressure.

[0009] Step 4. The gas-liquid mixture returned from the wellhead after Step 3 is sent to a three-phase separator for gas-liquid separation. The separated condensate oil is output through the condensate oil export pipeline, and the formation water is discharged through the formation water export pipeline. The separated natural gas is processed by a fine filter and a deep dehydration device, and more than 90% is returned to Step 1 as a circulating gas source. Fresh natural gas is added through the gas replenishment valve to maintain pressure balance.

[0010] In some embodiments, the gas injection flow rate in step 3 is determined based on a modified Turner critical liquid-carrying model, and the actual gas injection flow rate is 10%–20% higher than the critical liquid-carrying flow rate. The modification formula is as follows:

[0011] Where θ is the wellbore inclination angle; ε is the tubing roughness; ρ is the relative density of natural gas; and the correction factor ranges from 1.1 to 1.3.

[0012] In some embodiments, the heating temperature in step 2 is based on a dynamic adjustment mechanism: temperature data is collected in real time by temperature sensors deployed at five different depths in the wellbore, and when the temperature at any depth is close to the wax precipitation point of crude oil, the outlet temperature of the intelligent electric heater is automatically increased by 5℃–10℃, and the outlet temperature of the injected gas is always kept 30℃–50℃ higher than the wax precipitation point.

[0013] In some embodiments, the parameter monitoring unit collects in real time the daily gas production at the wellhead, wellhead pressure, wellhead temperature, wax content of the produced material, and temperature and pressure data at five depth points in the wellbore;

[0014] The logic judgment unit presets the following operating condition thresholds: when the daily gas production decreases by more than 5%, the wellhead pressure increases by more than 0.3 MPa, or the wax content of the produced material exceeds 3%, it is determined that the wax deposition trend is intensifying; when the wellbore liquid column height exceeds 50 m, it is determined that the liquid accumulation exceeds the standard.

[0015] The execution unit automatically adjusts its operating parameters based on the judgment result.

[0016] In some embodiments, when the execution unit determines that the wax deposition trend is intensifying, it increases the outlet temperature of the intelligent electric heating furnace by 5°C–10°C and the outlet pressure of the screw compressor by 1MPa–2MPa; when it determines that the liquid accumulation exceeds the standard, it increases the gas injection flow rate by 10%–20%; when the monitoring parameters return to the normal threshold range, the system automatically switches to the low energy consumption maintenance mode.

[0017] In some embodiments, the fine filter in step 4 uses a 5μm precision filter element, and the deep dehydration device uses a 4A type molecular sieve adsorption device to control the water dew point of the circulating gas at ≤-60℃.

[0018] In some embodiments, the return rate of the circulating gas source in step 4 is not less than 92%, and fresh natural gas is replenished through the gas replenishment valve to compensate for system leakage and pressure fluctuation losses.

[0019] In some embodiments, this method is applicable to shale gas wells with a depth of 1500–3000 m, a crude oil wax content of 2%–8%, and a wellbore fluid volume of 20–100 m³.

[0020] In some embodiments, the screw compressor and the intelligent electric heating furnace are equipped with an automatic overpressure relief valve.

[0021] In some embodiments, the parameter monitoring unit collects data through a wax content analyzer, a flow meter, a pressure controller, a temperature sensor, and a pressure sensor; the execution unit adjusts operating parameters through an electric regulating valve and a frequency converter; and performs logical judgments and issues instructions through an edge computing controller.

[0022] Compared with the prior art, the present invention has the following beneficial effects:

[0023] 1. Breaking down the technological barriers between wax removal and fluid drainage, enabling simultaneous operation, wax removal efficiency is increased from 60%-80% of traditional technology to ≥95%, fluid drainage efficiency is increased from 50%-60% to ≥85%, daily gas production per well is increased by 30%-50%, and production rate is increased from 65% to over 90%;

[0024] 2. The self-produced gas recycling rate is ≥92%, reducing gas source costs by more than 90%; no chemical reagents or clean water are required, saving 300,000-500,000 yuan in reagent costs and 100,000-200,000 yuan in water costs per well per year; intelligent control reduces manual intervention by 80%, reducing annual operation and maintenance costs by 800,000-1,200,000 yuan and overall costs by 70%-80%.

[0025] 3. The entire process is a closed loop with no sewage discharge or chemical injection, resulting in a reservoir damage rate of less than 0.5% (far lower than the 5%-10% of chemical dewaxing); it uses electric heating, eliminating combustion emissions and meeting environmental protection requirements; the system pressure is automatically monitored, and overpressure is automatically relieved, avoiding the risk of oil pipe scratches associated with traditional mechanical dewaxing.

[0026] 4. It is suitable for shale gas wells with a depth of 1500-3000m, wax content of 2%-8%, and liquid volume of 20-100m³. It is also compatible with different well types such as vertical wells and horizontal wells. It has been field-verified in shale gas producing areas such as the Sichuan Basin and the Ordos Basin, and has good adaptability. Attached Figure Description

[0027] To more clearly illustrate the technical solutions in the embodiments of the present invention or the prior art, the drawings used in the description of the embodiments or the prior art will be briefly introduced below. Obviously, the drawings described below are only some embodiments of the present invention. For those skilled in the art, other drawings can be obtained based on these drawings without creative effort.

[0028] Figure 1 This is a flowchart of the synergistic production increase method of the present invention;

[0029] Figure 2 This is a system architecture diagram for implementing the method of the present invention. Detailed Implementation

[0030] The following will be based on embodiments of the present invention. Figures 1-2 The technical solutions in the embodiments of the present invention will be clearly and completely described together. Obviously, the described embodiments are only some embodiments of the present invention, and not all embodiments.

[0031] Partial interpretation:

[0032] 1. Turner Critical Liquid Carrying Model: The Turner critical liquid carrying model is a classic model for predicting liquid accumulation in gas wells, proposed by Turner et al. in 1969. Its core is the force balance of liquid droplets. It is used to calculate the minimum gas velocity / flow rate required to prevent liquid accumulation in the wellbore and is widely used in gas well dynamic analysis and drainage and gas production design.

[0033] 2. Annulus: This is the annular closed space formed between the outer wall of the tubing (production tubing string) and the inner wall of the casing (technical casing / production casing) after the completion of an oil and gas well. It is a key component of the oil and gas well production system, running through the entire wellbore (from the wellhead to the bottom of the well), and is sealed and controlled through wellhead devices (such as Christmas trees and annulus valves).

[0034] Example

[0035] This embodiment provides a method for synergistic production enhancement of shale gas wells through thermodynamic wax removal and circulating gas lift. The method is based on an intelligent control system, which includes a parameter monitoring unit, a logic judgment unit, and an execution unit. It should be noted that the system can be a combination of existing publicly available devices or a system with the same function that has been publicly available before. The method includes at least the following steps: Step 1. Collecting natural gas produced at the wellhead of the target shale gas well as the working medium, and purifying it sequentially through a three-stage filter and a molecular sieve dehydration device; the three-stage filter uses filter elements with precision of 50μm, 10μm, and 5μm respectively; the molecular sieve dehydration device controls the water dew point of the purified natural gas to be ≤-40℃ and the solid impurity content to be ≤1μm; Step 2. Pressurizing the natural gas processed in Step 1 to 10MPa–20MPa using a screw compressor, and simultaneously heating it to 100℃–160℃ using an intelligent electric heating furnace, with the heating temperature set 30℃–50℃ higher than the wax precipitation point of the target well crude oil; Step 3. Continuously injecting the high-temperature, high-pressure natural gas obtained in Step 2 into the wellbore through the annulus of the casing at an injection velocity of 3m / s–50℃. During the injection process, thermal dewaxing and gas lift drainage are performed simultaneously. Thermal dewaxing utilizes direct heat conduction and forced convection between the 100℃–160℃ natural gas and the inner wall of the tubing, completely melting the attached wax within 1–2 hours. Simultaneously, a pressure of 10MPa–20MPa drives the natural gas to form high-speed turbulence within the wellbore, generating shear stress of 0.8MPa–1.2MPa, stripping away the molten wax and carrying it to the surface with the gas-liquid flow. Gas lift drainage involves mixing the injected gas with the accumulated fluid in the wellbore to form a gas phase with a volume fraction of 60%–80%. 0% gas-liquid two-phase flow reduces the liquid column density to 400kg / m³–600kg / m³, making the bottom hole flowing pressure 0.5MPa–1MPa lower than the formation pressure; Step 4. The gas-liquid mixture returned from the wellhead after Step 3 is sent to a three-phase separator for gas-liquid separation. The separated condensate oil is output through the condensate oil export pipeline, and the formation water is discharged through the formation water export pipeline; the separated natural gas is processed by a fine filter and a deep dehydration device, and more than 90% is returned to Step 1 as a circulating gas source, and fresh natural gas is added through the gas replenishment valve to maintain pressure balance.

[0036] To better understand this invention, specific examples are provided below:

[0037] Taking a typical shale gas well in the Sichuan Basin as an example, the well is 2000m deep, with a tubing inner diameter of 73mm and a daily gas production of 2.0×10⁻⁶. 4 m 3 The crude oil has a wax content of 5%, the wellbore fluid accumulation height is 80m, the bottom hole static pressure is 12MPa, and the laboratory-determined wax precipitation point is 105℃.

[0038] first,

[0039] Natural gas produced at the wellhead of the target shale gas well is used as the working medium and purified sequentially through a three-stage filter and a molecular sieve dehydration device. The three-stage filter uses filter elements with precisions of 50μm, 10μm, and 5μm respectively. The molecular sieve dehydration device controls the water dew point of the purified natural gas to be ≤-40℃ and the solid impurity content to be ≤1μm. The produced natural gas is collected through the wellhead gas collection valve, with an initial flow rate set at 500 m³ / h. First, it enters the three-stage filter. The first stage uses a 50μm filter element to intercept large particles; the second stage uses a 10μm filter element to remove medium-sized solid particles; and the third stage uses a 5μm high-precision filter element to ensure the outlet solid impurity content is ≤1μm. Subsequently, the gas enters the molecular sieve dehydration device, where a 4A-type molecular sieve adsorbs moisture. Online dew point monitoring shows that the water dew point of the treated gas is -45℃, meeting the technical requirement of ≤-40℃. The purified natural gas is clean and dry and can safely enter the subsequent pressurization and heating stage.

[0040] then,

[0041] The treated natural gas is pressurized to 10MPa–20MPa by a screw compressor and simultaneously heated to 100℃–160℃ by an intelligent electric heater. The heating temperature setting is 30℃–50℃ higher than the wax precipitation point of the target well crude oil. The purified natural gas enters the screw compressor. In this embodiment, two screw compressors are connected in parallel, each with a displacement of 300m³ / h, for a total processing capacity of 600m³ / h. The gas pressure is increased from the original wellhead pressure (approximately 8MPa) to 18MPa, which is 6MPa higher than the bottom hole static pressure of 12MPa, meeting the injection requirements.

[0042] The intelligent electric heating furnace is started synchronously. Based on the wax precipitation point of 105℃ measured in the laboratory, the initial heating temperature is set to 140℃, which is 35℃ higher than the wax precipitation point. The heating power is 80 kW, and the temperature control accuracy is ±2℃. During the heating process, the temperature sensor provides real-time feedback on the outlet temperature. If fluctuations are detected that exceed the allowable range, the frequency converter automatically adjusts the heating power to maintain stability. At the same time, the intelligent control module continuously receives temperature data from different depths in the wellbore (a total of 5 measuring points) through the edge computing controller. When the temperature at any depth approaches the wax precipitation point, the system automatically increases the heating temperature by 5℃–10℃, always maintaining a safety margin.

[0043] Immediately afterwards,

[0044] The aforementioned high-temperature, high-pressure natural gas is continuously injected into the wellbore through the annulus of the casing at an injection velocity of 3 m / s–5 m / s. During the injection process, thermodynamic dewaxing and gas lift drainage operations are performed simultaneously. Thermodynamic dewaxing involves direct heat conduction and forced convection between the 100℃–160℃ natural gas and the inner wall of the tubing, completely melting the attached wax within 1 to 2 hours. Simultaneously, a pressure of 10 MPa–20 MPa drives the natural gas to form high-speed turbulence within the wellbore, generating shear stress of 0.8 MPa–1.2 MPa, which peels off the molten wax and carries it to the surface with the gas-liquid flow. Gas lift drainage involves mixing the injected gas with the accumulated liquid in the wellbore to form a gas-liquid two-phase flow with a gas volume fraction of 60%–80%, reducing the liquid column density to 400 kg / m³–600 kg / m³, and making the bottomhole flowing pressure 0.5 MPa–1 MPa lower than the formation pressure.

[0045] High-temperature, high-pressure natural gas is continuously injected into the wellbore through the annulus of the casing and tubing via the injection valve assembly. The injection velocity is controlled at 4 m / s. The injection flow rate is calculated based on the modified Turner critical fluid-carrying model. The original critical fluid-carrying flow rate is 3.6 m³ / min. Considering the wellbore inclination angle θ = 15°, tubing roughness ε = 0.05 mm, and natural gas relative density ρ = 0.65, the following parameters are substituted into the modified formula: Where θ is the wellbore inclination angle; ε is the tubing roughness; ρ is the relative density of natural gas; and the correction factor ranges from 1.1 to 1.3. The corrected critical flow rate is 3.85 m³ / min, while the actual injection flow rate is set at 4.0 m³ / min (approximately 4% higher than the critical value), falling within the defined 10%–20% range.

[0046] After injection begins, the high-temperature gas at 100℃–160℃ undergoes direct heat conduction and forced convection heat transfer with the inner wall of the tubing. Within 1 hour, the temperature in the middle of the wellbore rises to 120℃, causing the attached wax to completely melt. At the same time, the 18MPa pressure drives the gas to form a high-speed turbulent flow, generating a shear stress of about 1.0MPa, which effectively strips off the molten wax and carries it upward with the gas-liquid flow.

[0047] At the same time, the injected gas mixes with the accumulated liquid to form a gas-liquid two-phase flow with a gas volume fraction of about 70%, the liquid column density drops to about 500 kg / m³, and the bottom hole flowing pressure drops to 11.2 MPa, which is 0.8 MPa lower than the formation pressure, thus achieving efficient lifting of the accumulated liquid.

[0048] The wellhead pressure dropped from the initial 8 MPa to 6.5 MPa, and the daily fluid production increased from 10 m³ to 45 m³. The wax content analyzer showed that the wax content of the produced material first rose to 3% and then quickly dropped to below 0.3%, indicating that wax removal and fluid drainage were completed simultaneously.

[0049] at last,

[0050] The gas-liquid mixture returned from the wellhead after the aforementioned operations is sent to a three-phase separator for gas-liquid separation. The separated condensate oil is output through the condensate oil export pipeline, and the formation water is discharged through the formation water export pipeline. The separated natural gas is treated by a fine filter and a deep dehydration device, with over 90% returned to step 1 as a circulating gas source. Fresh natural gas is added through a gas replenishment valve to maintain pressure balance. The gas-liquid mixture returned from the wellhead enters the three-phase separator, where efficient separation is achieved at a pressure of 6.5 MPa and a temperature of 40°C. 5 m³ of condensate oil is separated and transported to a storage tank through the condensate oil export pipeline, while 40 m³ of formation water is sent to the wastewater treatment system through the formation water export pipeline.

[0051] Approximately 500 m³ / h of the separated natural gas enters the circulation loop, passing through a fine filter with a 5 μm filter element to remove entrained tiny wax particles and solid impurities. It then enters a deep dehydration unit, also using 4A molecular sieves, to further lower the water dew point to -62°C, preventing the formation of hydrates at the screw compressor inlet due to low temperature and high pressure. 92% (approximately 460 m³ / h) of the treated circulating natural gas is returned to the front end of the tertiary filter via the circulating natural gas pipeline, where it mixes with the newly added 40 m³ / h of fresh natural gas through a gas replenishment valve, maintaining the total system flow and pressure stable at 18 MPa.

[0052] Throughout the operation, the intelligent control system runs continuously, and the parameter monitoring unit acquires real-time data on wellhead production, pressure, temperature, wax content, and temperature and pressure at five depths in the wellbore through the road acquisition channel.

[0053] In the early stages of operation, the system monitored a 6% decrease in wellhead production, a 0.4 MPa increase in pressure, and a wax content of 3.2%. The logic judgment unit determined that the wax deposition trend was intensifying, and the execution unit immediately instructed the electric regulating valve to increase the gas injection pressure to 19 MPa, while the frequency converter increased the heating temperature to 145°C.

[0054] Two hours later, monitoring data showed that the wax content had dropped to 0.4%, the pressure had stabilized at 6.5 MPa, and the output had rebounded to 2.5 × 10⁻⁶. 4 m 3 The system determines that the working condition is normal and automatically switches to maintenance mode: the heating temperature drops to 115℃, the gas injection pressure is adjusted to 12MPa, and the gas injection flow rate is reduced to 3.0m³ / min.

[0055] No abnormal parameters were observed during the subsequent 72 hours of continuous monitoring, proving that the system has adaptive adjustment capabilities.

[0056] In summary, this example verifies the complete operational logic and technical effects of the method of the present invention:

[0057] The wax removal efficiency reached 96.2%, the liquid drainage efficiency was 88.5%, and the daily gas production increased to 2.7 × 10⁻⁶. 4 m 3This resulted in a 35% increase in efficiency, raising the production uptime rate from 62% to 91%, and reducing annual maintenance costs by 2.34 million yuan. All equipment in the system is designed to explosion-proof standards, ensuring safety. This example fully demonstrates the technical advantages of the invention and can be widely applied in similar shale gas wells.

[0058] The foregoing has shown and described the basic principles, main features, and advantages of the present invention. It will be apparent to those skilled in the art that the invention is not limited to the details of the exemplary embodiments described above, and that the invention can be implemented in other specific forms without departing from its spirit or essential characteristics. Therefore, the embodiments should be considered illustrative and non-limiting in all respects, and the scope of the invention is defined by the appended claims rather than the foregoing description. Thus, all variations falling within the meaning and scope of equivalents of the claims are intended to be included within the scope of the invention. No reference numerals in the claims should be construed as limiting the scope of the claims.

[0059] Furthermore, it should be understood that although this specification describes embodiments, not every embodiment contains only one independent technical solution. This narrative style is merely for clarity. Those skilled in the art should consider the specification as a whole, and the technical solutions in each embodiment can also be appropriately combined to form other embodiments that can be understood by those skilled in the art.

Claims

1. A method for synergistic production enhancement of shale gas wells through thermodynamic dewaxing and circulating gas lift, the method being executed based on an intelligent control system, the intelligent control system comprising a parameter monitoring unit, a logic judgment unit, and an execution unit, characterized in that, The method includes at least: Step 1. Collect natural gas produced at the wellhead of the target shale gas well as the working medium, and purify it by passing it through a three-stage filter and a molecular sieve dehydration device in sequence; the three-stage filter uses filter elements with a precision of 50μm, 10μm and 5μm in sequence; the molecular sieve dehydration device controls the water dew point of the purified natural gas to be ≤-40℃ and the solid impurity content to be ≤1μm. Step 2. The natural gas processed in Step 1 is pressurized to 10MPa–20MPa by a screw compressor and simultaneously heated to 100℃–160℃ by an intelligent electric heating furnace. The heating temperature setting is 30℃–50℃ higher than the wax precipitation point of the crude oil in the target well. Step 3. The high-temperature, high-pressure natural gas obtained in Step 2 is continuously injected into the wellbore through the annulus of the casing at an injection velocity of 3 m / s–5 m / s. During the injection process, thermodynamic dewaxing and gas lift drainage operations are performed simultaneously. The thermodynamic dewaxing is achieved by direct heat conduction and forced convection between the natural gas at 100℃–160℃ and the inner wall of the tubing, which completely melts the attached wax within 1 to 2 hours. At the same time, a pressure of 10 MPa–20 MPa drives the natural gas to form a high-speed turbulent flow in the wellbore, generating a shear stress of 0.8 MPa–1.2 MPa, which peels off the molten wax and carries it to the surface with the gas-liquid flow. The gas lift drainage is achieved by mixing the injected gas with the liquid in the wellbore to form a gas-liquid two-phase flow with a gas volume fraction of 60%–80%, reducing the liquid column density to 400 kg / m³–600 kg / m³, and making the bottomhole flowing pressure 0.5 MPa–1 MPa lower than the formation pressure. Step 4. The gas-liquid mixture returned from the wellhead after Step 3 is sent to a three-phase separator for gas-liquid separation. The separated condensate oil is output through the condensate oil export pipeline, and the formation water is discharged through the formation water export pipeline. The separated natural gas is processed by a fine filter and a deep dehydration device, and more than 90% is returned to Step 1 as a circulating gas source. Fresh natural gas is added through the gas replenishment valve to maintain pressure balance.

2. The method according to claim 1, characterized in that, In step 3, the gas injection flow rate is determined based on a modified Turner critical liquid-carrying model. The actual gas injection rate is 10%–20% higher than the critical liquid-carrying flow rate. The modification formula is as follows: ， in, θ The wellbore inclination angle; ε For oil pipe roughness; ρ The relative density of natural gas is given; the correction factor ranges from 1.1 to 1.

3.

3. The method according to claim 2, characterized in that, The heating temperature described in step 2 is based on a dynamic adjustment mechanism: temperature data is collected in real time by temperature sensors deployed at five different depths in the wellbore. When the temperature at any depth is close to the wax precipitation point of crude oil, the outlet temperature of the intelligent electric heater is automatically increased by 5℃–10℃, and the outlet temperature of the injected gas is always kept 30℃–50℃ higher than the wax precipitation point.

4. The method according to claim 1, characterized in that, The parameter monitoring unit collects real-time data on daily gas production at the wellhead, wellhead pressure, wellhead temperature, wax content of the produced material, and temperature and pressure data at five depth points in the wellbore. The logic judgment unit presets the following operating condition thresholds: when the daily gas production decreases by more than 5%, the wellhead pressure increases by more than 0.3 MPa, or the wax content of the produced material exceeds 3%, it is determined that the wax deposition trend is intensifying; when the wellbore liquid column height exceeds 50 m, it is determined that the liquid accumulation exceeds the standard. The execution unit automatically adjusts its operating parameters based on the judgment result.

5. The method according to claim 4, characterized in that, When the execution unit determines that the wax deposition trend is intensifying, it increases the outlet temperature of the intelligent electric heating furnace by 5°C–10°C and the outlet pressure of the screw compressor by 1MPa–2MPa; when it determines that the liquid accumulation exceeds the standard, it increases the gas injection flow rate by 10%–20%; when the monitoring parameters return to the normal threshold range, the system automatically switches to the low energy consumption maintenance mode.

6. The method according to claim 1, characterized in that, In step 4, the fine filter uses a 5μm precision filter element, and the deep dehydration device uses a 4A type molecular sieve adsorption device to control the water dew point of the circulating gas at ≤-60℃.

7. The method according to claim 6, characterized in that, In step 4, the return rate of the circulating gas source is no less than 92%, and fresh natural gas is added through the gas replenishment valve to compensate for system leakage and pressure fluctuation losses.

8. The method according to claim 1, characterized in that, It is suitable for shale gas wells with a depth of 1500–3000 m, a crude oil wax content of 2%–8%, and a wellbore liquid volume of 20–100 m³.

9. The method according to claim 1, characterized in that, The screw compressor and the intelligent electric heating furnace are equipped with an automatic overpressure relief valve.

10. The method according to claim 4, characterized in that, The parameter monitoring unit collects data through a wax content analyzer, a flow meter, a pressure controller, a temperature sensor, and a pressure sensor. The execution unit adjusts the operating parameters through an electric regulating valve and a frequency converter, and executes logical judgments and issues commands through an edge computing controller.

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