A natural gas cluster and gas lift process and method of making same

Abstract

This invention relates to the field of natural gas extraction technology, specifically to a natural gas cluster gas lift process and its preparation method. The process includes: collecting the produced fluid from a cluster well group into a gas-liquid separator for phase separation; introducing the separated associated gas into a dehydration tower to remove saturated water using triethylene glycol solvent; pressurizing and heating the purified gas to a set temperature via a multi-stage reciprocating compressor; and finally injecting it into the annulus of each well's casing through a gas distribution manifold to reduce fluid density. This invention establishes a coupled circulation system of multi-well gathering and centralized gas injection, utilizing gas-liquid separation and triethylene glycol dehydration units to deeply remove water from associated gas, completely eliminating the thermodynamic basis for hydrate formation. Combined with multi-stage pressurization and critical flow distribution technology, it achieves precise steady-state control of injection pressure, effectively optimizing gas-liquid slippage losses within the wellbore, significantly reducing the operating energy consumption of the compression system, and greatly improving the overall drainage capacity of the natural gas cluster well group.

Description

Technical Field

[0001] This invention relates to the field of natural gas extraction technology, and in particular to a natural gas cluster gas lift process and its preparation method. Background Technology

[0002] The field of natural gas extraction technology involves systematic engineering that utilizes physical or chemical methods to lift natural gas resources from underground reservoirs to the surface. Among these, the traditional natural gas cluster well gas lift process involves deploying multiple independent gas source devices at a cluster well site. High-pressure gas is injected into the annulus of a single oil or gas well, utilizing the principles of gas expansion work and reduced liquid column density to lower the bottomhole flowing pressure, thereby lifting the formation fluid to the surface. This is complemented by a surface separation device for gas-liquid processing.

[0003] Existing cluster well gas lift systems typically employ a single-well independent gas supply mode, resulting in high redundancy of surface compressor units and persistently high overall energy consumption. The lack of a coordinated control mechanism for the gas injection flow rate at each wellhead based on pipeline coupling causes frequent oscillations and transformations of the multiphase flow pattern within the wellbore. Furthermore, the produced gas is highly susceptible to condensation and precipitation of heavy components under low-temperature transportation conditions, leading to the accumulation and blockage of hydrates at the throttle valve, which severely weakens the continuous lifting efficiency of the gas lift system. Summary of the Invention

[0004] The purpose of this invention is to overcome the shortcomings of the existing technology and to propose a natural gas cluster gas lift process and its preparation method.

[0005] To achieve the above objectives, the present invention adopts the following technical solution: a natural gas cluster gas lift process, comprising: S1: Multiple gas-liquid mixtures from the cluster well group are fed into the three-phase separator. Under an operating pressure of 2.5-4.0 MPa, the gas-liquid density difference is used to perform three-phase separation. The liquid phase mixture at the bottom is separated and removed to obtain the crude associated gas at the top. S2: The crude associated gas is introduced into the bottom of the plate dehydration tower, so that it comes into countercurrent contact with the lean triethylene glycol solution sprayed from the top of the tower in the packing layer. The gas-liquid balance is controlled, and deep dehydration is carried out under the condition of 35-45℃ at the top of the tower to obtain dry gas. S3: Dry gas is delivered to a multi-stage reciprocating compressor unit for three-stage pressurization. The interstage cooling temperature is controlled at 40-50℃ by the intercooler, and the final stage exhaust temperature is adjusted to 60-80℃ by the aftercooler to obtain high-pressure injection gas. S4: Adjust the flow rate of high-pressure gas injection and inject it quantitatively into the annulus of each production well via the gas injection pipeline, so that it mixes with the formation fluid in the wellbore and drives the fluid to be lifted to the surface to obtain the lifted production fluid.

[0006] As a further aspect of the present invention, the specific execution process of the deep dehydration treatment in S2 includes: S21: the crude associated gas is introduced into the buffer section of the plate dehydration tower through the bottom air inlet pipe, and the airflow velocity is rectified to a stable flow rate of 0.8 to 1.2 m / s; S22: The lean triethylene glycol solution is pressurized and transported to the top spray device of the plate dehydration tower using a circulating pump. The solvent is atomized into droplets with an average diameter of 500 to 800 micrometers through a spiral nozzle, forming a uniform liquid film covering the entire cross section of the tower. S23: Control the rising crude associated gas and the descending lean triethylene glycol solution to make cross-flow contact on the multi-layer bubble cap tray, maintain the tray pressure drop at 0.5 to 1.0 kPa, and absorb saturated water vapor in the gas flow. S24: The dehydrated airflow is guided to the wire mesh demister at the top of the tower, where the intercepted droplets are coalesced and returned to the tower plate; S25: Monitor the water dew point temperature of the gas flow at the top of the tower in real time. When the water dew point is below -10 degrees Celsius, open the regulating valve at the top of the tower to discharge the gas and obtain dry gas.

[0007] As a further aspect of the present invention, the specific execution process of the three-stage pressurization process in S3 includes: S31: Dry gas after being stabilized by the buffer tank is drawn in through the first-stage suction valve of the multi-stage reciprocating compressor unit, and the gas pressure is increased from the primary pressure to 1.2 to 1.5 MPa under the action of cylinder volume change; S32: The high-temperature gas after primary compression is introduced into the primary intercooler, and the gas temperature is reduced to below 45 degrees Celsius by forced air cooling, and the condensate precipitated during the cooling process is separated and discharged. S33: The cooled gas is sequentially fed into the second-stage and third-stage cylinders for relay compression, and the compression ratio of each stage is strictly controlled between 2.5 and 3.0. Through step-by-step work, the gas pressure is increased to the design injection pressure of 20 to 25 MPa. S34: The aftercooler installed at the compressor outlet is used to perform heat exchange treatment on the gas discharged from the final stage, and the gas temperature is precisely controlled within the range of 65 to 75 degrees Celsius by adjusting the flow rate of the cooling medium. S35: The qualified gas is delivered to the high-pressure buffer container through the outlet check valve. The pressure sensor monitors the pressure fluctuation in the container. When the pressure stabilizes at the set threshold, the output valve is opened to obtain high-pressure gas injection.

[0008] A method for preparing natural gas cluster gas lift, the method being used to perform the above-described natural gas cluster gas lift process, comprising the following steps: The production manifold of the cluster well group is physically connected to the inlet of the three-phase separator. A coalescing plate assembly is installed inside the separator to enhance phase separation. The separated crude associated gas is continuously discharged from the top pipeline, and the liquid phase mixture deposited at the bottom is transported to the storage tank area through the drain valve. The crude associated gas is introduced into the lower air inlet of the plate dehydration tower, allowing it to pass through the bubble cap plate and fully contact the lean triethylene glycol solution. The dry gas discharged from the top of the tower is purified by a filter and then fed into a buffer tank. The water-absorbed rich liquid is then transported to a regeneration kettle for purification and recycling. The dry gas in the buffer tank is pumped into a multi-stage reciprocating compressor unit. After being processed by an intercooler, it is heat-exchanged by the hot fluid produced by the formation through a shell-and-tube heat exchanger. The obtained high-pressure injection gas is then delivered to the high-pressure injection main pipe. The high-pressure gas injection main is connected to the gas distribution manifold. After the flow rate is adjusted by the intelligent needle valve, the gas is injected into the casing gate of each well. This drives the lifted produced fluid to be discharged back to the surface, and the lifted produced fluid is then recycled back to the inlet of the three-phase separator in S1.

[0009] As a further aspect of the present invention, the enhanced phase separation process includes: guiding the lifted product liquid entering from the production manifold to the inlet rectifier chamber of the three-phase separator, and initially separating large-diameter free bubbles; The rectified fluid is passed through a set of corrugated coalescing plates with an inclination angle of 45 to 60 degrees in a laminar flow state to capture and coalesce the tiny oil or water droplets of the dispersed phase. The residence time of the fluid in the settling section of the separator is controlled to be maintained at 15 to 20 minutes to form a clear oil-water interface; By monitoring the height of the oil-water interface in real time using an interface meter installed at the oil-water interface, and adjusting the opening of the oil outlet valve and water outlet valve based on the monitoring data using PID control, the upper layer of crude oil and the lower layer of wastewater are discharged independently.

[0010] As a further aspect of the present invention, the specific execution process of the rich liquid purification cycle includes: collecting the triethylene glycol rich liquid that has absorbed water discharged from the bottom of the plate dehydration tower, and exchanging it with the high-temperature lean triethylene glycol solution in a countercurrent heat exchanger to preheat the temperature of the rich liquid to 80 to 100 degrees Celsius. The preheated rich liquid is sent to a flash tank and flashed at a low pressure of 0.4 to 0.6 MPa to separate and recover the hydrocarbon gases dissolved in the rich liquid. The rich liquor after flash evaporation is sent to a reboiler, where the heat provided by the burner is used to heat the rich liquor to a boiling temperature of 195 to 204 degrees Celsius, causing the water in it to vaporize and evaporate. Dry stripping gas is introduced into the stripping tower to further remove trace amounts of water remaining in the solvent, restoring the triethylene glycol mass concentration to above 99.0%, thus obtaining the regenerated lean triethylene glycol solution.

[0011] As a further aspect of the present invention, the specific execution process of the heat exchange includes: introducing the high-temperature compressed gas discharged from the multi-stage reciprocating compressor unit into the tube side of the shell-and-tube heat exchanger, and controlling the gas flow velocity in the tube bundle to be 15 to 20 m / s. The high-temperature lift-up produced fluid from the formation is introduced into the shell side of the shell-and-tube heat exchanger, where it is laterally flushed by the tube bundle under the guidance of baffles, and exchanges heat with the gas in the tube side in a countercurrent manner. Monitor the temperature and pressure difference data at the inlet and outlet of the heat exchanger. When the pressure difference exceeds 1.2 times the design value, start the online cleaning program or switch to the standby heat exchanger to remove the paraffin or scale deposited on the tube wall surface. Adjust the bypass flow rate of the shell-side fluid to precisely control the gas temperature after heat exchange and maintain it between 60 and 80 degrees Celsius.

[0012] As a further aspect of the present invention, the specific execution process of the flow regulation includes: acquiring formation pressure, water cut and production index data of each single well, and calculating the theoretical gas injection volume required to maintain stable production of the well in combination with the tubing structure parameters, as the target setting value for flow regulation; High-pressure air is introduced into the valve seat cavity of the intelligent needle valve, and the valve needle is driven to move axially by a servo motor, changing the flow area of ​​the valve port so that the fluid reaches the critical flow state when it flows through the valve port. The actual gas injection flow rate and pressure data are collected in real time using flow meters and pressure transmitters installed after the valve, and then fed back to the central control unit for comparison and analysis with the target set value. The valve needle's stroke position is dynamically adjusted based on the comparison deviation value.

[0013] As a further aspect of the present invention, the method also includes a gas lift efficiency optimization process, which includes: collecting wellhead casing pressure, wellhead oil pressure, daily liquid production and injected gas volume data of each single well, and constructing a production database reflecting changes in the operating conditions of the gas lift well; Based on real-time data from the production database, the current gas injection efficiency stability index is calculated using a gas lift performance evaluation model. ; The gas injection efficiency stability index The calculation formula is as follows: ; in, This represents the injection flow rate under standard conditions. Represents the gas injection sleeve pressure. Represents the wellhead oil pressure. Represents daily liquid production. This represents the average density of the gas-liquid mixture within the wellbore. Represents gravitational acceleration. Represents the effective lifting height. Represents the bottom hole temperature. Represents the wellhead temperature; Based on the calculated gas injection efficiency stability index The opening degree of the intelligent needle valve is iteratively corrected, and an alarm is automatically triggered and an adaptive adjustment strategy is executed when the index deviates from the preset optimal range.

[0014] Compared with the prior art, the advantages and positive effects of the present invention are as follows: In this invention, by establishing a multi-well gathering and transportation and centralized gas injection coupled circulation system, and utilizing gas-liquid separation and glycol dehydration units to deeply remove associated gas moisture, the thermodynamic basis for hydrate formation is completely eliminated. Combined with multi-stage pressurization and critical flow distribution technology, precise steady-state control of gas injection pressure is achieved, effectively optimizing gas-liquid slippage loss in the wellbore, significantly reducing the operating energy consumption of the compression system, and greatly improving the overall drainage capacity of natural gas cluster well groups. Attached Figure Description

[0015] Figure 1 This is a flow chart of the natural gas cluster and gas lift process of the present invention. Detailed Implementation

[0016] To make the objectives, technical solutions, and advantages of this invention clearer, the technical solutions of this invention will be described in detail below with reference to the accompanying drawings and embodiments. It should be understood that the specific embodiments described herein are only for explaining the technical solutions of this invention and do not constitute a limitation on the scope of protection.

[0017] In the description of this invention, the process flow relationships or material and energy transfer paths indicated by terms such as "unit," "step," "equipment," "pipeline," "material flow," and "process parameters" are defined based on the process flow diagram or equipment structure diagram corresponding to the embodiments. This way of expression is only used to clearly illustrate the logical relationship between the elements in the technical solution, and not to limit the specific equipment connection method or physical layout. The term "multiple" includes two or more technical units, including but not limited to multiple reactors, pumps, valves, separation units, or detection instruments and other expandable elements. The specific number is determined according to specific process requirements or production scale and needs to be specifically stated.

[0018] Example 1

[0019] In this embodiment, the three-phase separator operates at a pressure of 2.5 MPa, the corrugated coalescing plate assembly is tilted at 45 degrees, and the fluid residence time in the separator settling section is 15 minutes. The plate dehydration tower top temperature is controlled at 35°C, the buffer section airflow rectification velocity is 0.8 m / s, the average droplet diameter of the lean triethylene glycol solution is 500 micrometers, the plate pressure drop is maintained at 0.5 kPa, the rich liquid preheating temperature is 80°C, the flash pressure is 0.4 MPa, and the reboiler heating temperature is 195°C. The multi-stage reciprocating compressor unit has an interstage cooling temperature of 40°C, a final stage exhaust temperature adjusted to 60°C, a first-stage compression final pressure of 1.2 MPa, a first-stage intercooler outlet temperature of 35°C, a compression ratio controlled at 2.5 for each stage, a design injection pressure of 20 MPa, a tube-side gas velocity of 15 m / s in the shell-and-tube heat exchanger, and a gas temperature controlled at 60°C after heat exchange.

[0020] Please see Figure 1 This invention provides a technical solution: a natural gas cluster gas lift process, comprising the following steps: S1: Multiple gas-liquid mixtures from the cluster well group are fed into a three-phase separator. Under an operating pressure of 2.5-4.0 MPa, three-phase separation is performed using the density difference between gas and liquid. The liquid phase mixture at the bottom is removed, yielding the crude associated gas at the top. The production manifold of the cluster well group is physically connected to the inlet of the three-phase separator. A coalescing plate assembly is installed inside the separator to enhance phase separation. The separated crude associated gas is continuously discharged from the top pipeline, while the liquid phase mixture deposited at the bottom is transported to the storage tank area via a drain valve. The enhanced phase separation process specifically involves guiding the lifted produced fluid from the production manifold to the inlet rectifier chamber of the three-phase separator, where large-diameter free bubbles are initially separated. The rectified fluid is passed through a set of corrugated coalescing plates with an inclination angle of 45 to 60 degrees in a laminar flow state to capture and coalesce the tiny oil or water droplets of the dispersed phase. The residence time of the fluid in the settling section of the separator is controlled to be maintained at 15 to 20 minutes to form a clear oil-water interface; By monitoring the height of the oil-water interface in real time using an interface meter installed at the oil-water interface, and adjusting the opening of the oil outlet valve and water outlet valve based on the monitoring data using PID control, the upper layer of crude oil and the lower layer of wastewater are discharged independently.

[0021] The operator activates the electrically operated shut-off valve at the inlet of the three-phase separator, introducing the gas-liquid mixture from the cluster well production manifold into the separator's inlet rectifier chamber. Inside the rectifier chamber, the kinetic energy dissipation effect generated by the fluid impacting the rectifier components transforms the initially turbulent mixture into a stable flow. The pressure in the rectifier chamber is monitored by an online pressure transmitter to ensure it remains stable at the setpoint of 2.5 MPa. The fluid then enters the settling separation zone, where, under gravity, free bubbles with a diameter greater than 100 micrometers rapidly rise into the gas phase space. Guided by the baffles, the liquid phase fluid enters the corrugated coalescing plate assembly area in laminar flow mode. This assembly consists of a set of parallel stainless steel corrugated plates, with the installation angle precisely fixed at 45 degrees. When a continuous phase fluid containing tiny dispersed droplets flows through a corrugated plate channel, oil or water droplets with a diameter between 10 and 100 micrometers collide with the plate surface under the combined action of buoyancy and fluid drag. They then adsorb and coalesce using the oleophilic or hydrophilic properties of the plate surface, forming larger droplets that slide down or float to the surface. After leaving the coalescence assembly, the fluid enters a gravity settling section. Operators strictly control the actual residence time of the liquid phase fluid in the settling section to 15 minutes by adjusting the opening of the outlet valve, allowing sufficient time for the oil and water phases to separate.

[0022] During this period, magnetic level gauges and guided wave radar interface meters installed on the sidewall of the separator collect real-time position data of the oil-water interface and transmit the signals to the DCS distributed control system. The control system calculates the adjustment range of the oil outlet valve and water outlet valve based on a preset PID algorithm (proportional coefficient Kp set to 1.2, integral time Ti set to 0.5 min, and derivative time Td set to 0.1 min). When the oil-water interface is detected to be below the set lower limit, the system automatically reduces the opening of the water outlet valve while increasing the opening of the oil outlet valve to maintain dynamic balance of the interface. The separated crude associated gas is discharged through the pressure regulating valve at the top and enters the subsequent processing unit; the wastewater at the bottom and the crude oil in the intermediate layer are transported to the storage tank area through independent metering pipelines. Operators sample and analyze the discharged oil and water phases every 2 hours, using centrifuges to determine the water content and oil content to verify the separation effect.

[0023] Table 1. Three-phase separator operation data table Parameter name unit numerical values Remark Inlet pressure Megapascal 2.50 Pressure fluctuation range ±0.05 Cohesion plate tilt angle Spend 45.0 Fixed installation liquid phase residence time minute 15.0 Achieve this through flow control. Oil phase water content percentage 0.45 Centrifugation method Oil content in aqueous phase mg / L 45.2 Infrared spectrophotometry determination vapor phase liquid content mg / m³ 12.5 Filter paper weighing method for determination As shown in Table 1, under the conditions of operating pressure of 2.5 MPa and coalescing plate tilt angle of 45 degrees, the water content of the oil phase was controlled at 0.45%, and the separation effect met the process requirements.

[0024] S2: The crude associated gas is introduced into the bottom of the plate dehydration tower, where it comes into countercurrent contact with the lean triethylene glycol solution sprayed from the top of the tower within the packing layer. The gas-liquid balance is controlled, and deep dehydration is performed at a top temperature of 35-45℃ to obtain dry gas. The specific execution process of the deep dehydration treatment includes: S21: The crude associated gas is introduced into the buffer section of the plate dehydration tower through the bottom air inlet pipe, and the airflow velocity is rectified to a stable flow rate of 0.8 to 1.2 m / s; S22: The lean triethylene glycol solution is pressurized and transported to the top spray device of the plate dehydration tower by a circulating pump. The solvent is atomized into droplets with an average diameter of 500 to 800 micrometers through spiral nozzles, forming a uniform liquid film covering the entire cross section of the tower. S23: Control the rising crude associated gas and the descending lean triethylene glycol solution to make cross-flow contact on the multi-layer bubble cap tray, maintain the tray pressure drop at 0.5 to 1.0 kPa, and absorb saturated water vapor in the gas flow. S24: The dehydrated airflow is guided to the wire mesh demister at the top of the tower, where the intercepted droplets are coalesced and returned to the tower plate; S25: Real-time monitoring of the water dew point temperature of the gas flow at the top outlet of the tower. When the water dew point is below -10 degrees Celsius, the regulating valve at the top outlet of the tower is opened to discharge the gas and obtain dry gas. During the process, the crude associated gas is introduced into the lower inlet of the plate dehydration tower, allowing it to pass through the bubble cap tray and fully contact the lean triethylene glycol solution. The dry gas discharged from the top of the tower is purified by a filter and then fed into a buffer tank. The rich liquid after water absorption is sent to the regeneration kettle for purification and circulation. The specific execution process of the rich liquid purification and circulation includes: collecting the triethylene glycol rich liquid that has absorbed water discharged from the bottom of the plate dehydration tower, passing it through a lean-rich liquid heat exchanger to exchange heat countercurrently with the high-temperature lean triethylene glycol solution, and preheating the rich liquid temperature to 80 to 100 degrees Celsius. The preheated rich liquid is sent to a flash tank and flashed at a low pressure of 0.4 to 0.6 MPa to separate and recover the hydrocarbon gases dissolved in the rich liquid. The rich liquor after flash evaporation is sent to a reboiler, where the heat provided by the burner is used to heat the rich liquor to a boiling temperature of 195 to 204 degrees Celsius, causing the water in it to vaporize and evaporate. Dry stripping gas is introduced into the stripping tower to further remove trace amounts of water remaining in the solvent, restoring the triethylene glycol mass concentration to over 99.0% and obtaining a regenerated lean triethylene glycol solution.

[0025] The operator opens the inlet valve at the bottom of the plate dehydration tower, introducing the crude associated gas into the bottom buffer section. The average cross-sectional velocity of the rising gas flow is precisely adjusted to 0.8 m / s using an orifice flow meter and gas straightening grid installed at the inlet to prevent flow deviation or channeling. Simultaneously, the lean liquid circulation pump is started, delivering a 99.2% lean triethylene glycol solution to the top spray system. The spray system is equipped with laser-machined spiral nozzles that atomize the triethylene glycol solution into fine droplets with a volume average diameter (Dv50) of 500 micrometers at a spray pressure of 0.3 MPa. These droplets, under gravity, uniformly cover the bubble cap plates below, forming a continuously flowing liquid film. The temperature sensor reading at the top of the tower is maintained at 35°C to ensure optimal absorption efficiency of the triethylene glycol and prevent excessive volatilization.

[0026] The gas and liquid phases undergo multi-stage countercurrent contact on the trays. The rising gas bubbles through the liquid layer via the gaps in the bubble cap, and water molecules in the gas are rapidly absorbed by triethylene glycol. Operators maintain the pressure drop of each tray at 0.5 kPa by adjusting the gas-liquid ratio to prevent flooding or leakage. The dehydrated dry gas rises and passes through a wire mesh demister at the top of the column. Through inertial impaction, it intercepts droplets larger than 5 micrometers in diameter carried by the gas flow. The intercepted droplets coalesce and drip back onto the trays. An online dew point meter monitors the water dew point of the gas at the top outlet in real time. The current reading is -12 degrees Celsius (below the control target of -10 degrees Celsius). At this time, the regulating valve at the top outlet remains open, allowing qualified dry gas to be discharged.

[0027] After absorbing water, the rich triethylene glycol solution is discharged from the bottom of the tower and enters the regeneration system. It first flows through a rich-lean-lean heat exchanger, exchanging heat with the hot lean solution from the reboiler, raising the rich solution temperature to 80°C. Then, the rich solution enters a flash tank, where the pressure is maintained at 0.4 MPa by a pressure control valve. Under this low-pressure environment, dissolved hydrocarbon gases such as methane and ethane in the rich solution desorb and escape, entering the fuel gas system through a recovery pipeline. The flash-evaporated rich solution enters the reboiler, where the burner control system adjusts the fuel quantity based on temperature feedback, maintaining a constant temperature of 195°C for the triethylene glycol solution within the reboiler. At this point, water vaporizes rapidly, while triethylene glycol, due to its higher boiling point, is retained. To further remove residual water, dry stripping gas is introduced to the bottom of the stripping tower. Under the action of stripping, the partial pressure of trace amounts of water in the solvent decreases and precipitates, ultimately restoring the triethylene glycol mass concentration to 99.2%, completing the regeneration cycle.

[0028] Table 2 Operating Parameters of Dehydration and Regeneration Units Parameter name unit numerical values Remark airflow speed meters per second 0.80 Buffer section measurement droplet diameter micrometer 500 Nozzle atomization characteristics Tower top temperature Celsius 35.0 PID control Tray pressure drop kPa 0.50 Differential pressure transmitter reading reboiler temperature Celsius 195.0 Key parameters for regeneration Dry air dew point Celsius -12.0 Online analyzer measurement Anemic fluid concentration percentage 99.2 Refractometer measurement Referring to Table 2, under the above process conditions, the system successfully produced dry gas with a qualified water dew point, and the solvent regeneration effect was good.

[0029] Please see Figure 1The dry gas is delivered to a multi-stage reciprocating compressor unit for three-stage pressurization. The interstage cooling temperature is controlled at 40-50℃ via an intercooler, and the final stage exhaust temperature is adjusted to 60-80℃ using an aftercooler, resulting in high-pressure injection gas. The specific execution process of the three-stage pressurization includes: S31: The first-stage intake valve of the multi-stage reciprocating compressor unit draws in dry gas that has been pressure-stabilized by the buffer tank, and the gas pressure is increased from the primary pressure to 1.2 to 1.5 MPa under the action of cylinder volume change; S32: The high-temperature gas after primary compression is introduced into the primary intercooler, and the gas temperature is reduced to below 45 degrees Celsius by forced air cooling, and the condensate precipitated during the cooling process is separated and discharged. S33: The cooled gas is sequentially fed into the second-stage and third-stage cylinders for relay compression, and the compression ratio of each stage is strictly controlled between 2.5 and 3.0. Through step-by-step work, the gas pressure is increased to the design injection pressure of 20 to 25 MPa. S34: The aftercooler installed at the compressor outlet is used to perform heat exchange treatment on the gas discharged from the final stage, and the gas temperature is precisely controlled within the range of 65 to 75 degrees Celsius by adjusting the flow rate of the cooling medium. S35: The processed gas is delivered to the high-pressure buffer container via an outlet check valve. A pressure sensor monitors pressure fluctuations within the container. When the pressure stabilizes at a set threshold, the output valve opens, resulting in high-pressure injection gas. During execution, dry gas from the buffer tank is pumped into a multi-stage reciprocating compressor unit. After being processed by an intercooler, it undergoes heat exchange using a shell-and-tube heat exchanger with geothermal fluids. The resulting high-pressure injection gas is then delivered to the high-pressure injection main pipe. The specific heat exchange process includes: introducing high-temperature compressed gas from the multi-stage reciprocating compressor unit into the tube side of the shell-and-tube heat exchanger, controlling the gas velocity within the tube bundle to be 15 to 20 m / s. The high-temperature produced liquid from the formation is introduced into the shell side of the shell-and-tube heat exchanger, where it is laterally flushed by the tube bundle under the guidance of the baffles and exchanges heat with the gas in the tube side in a countercurrent manner. Monitor the temperature and pressure difference data at the inlet and outlet of the heat exchanger. When the pressure difference exceeds 1.2 times the design value, start the online cleaning program or switch to the standby heat exchanger to remove the paraffin or scale deposited on the tube wall surface. Adjust the bypass flow rate of the shell-side fluid to precisely control the gas temperature after heat exchange and maintain it between 60 and 80 degrees Celsius.

[0030] Dry gas, after being pressurized by a buffer tank, is introduced into the first-stage cylinder of a multi-stage reciprocating compressor unit through a primary intake pipe. The compressor crankshaft rotates, driving the piston in a reciprocating motion. Gas is drawn in the instant the primary intake valve opens. As the piston compresses, the cylinder volume decreases, and the gas pressure increases. When the cylinder pressure reaches 1.2 MPa, the primary exhaust valve automatically opens, discharging the high-temperature, high-pressure gas. The gas then enters the primary intercooler, where the cooling fan operates at full speed, forcing airflow through the finned tube bundle and rapidly cooling the gas temperature from the primary exhaust temperature (approximately 90°C) to 35°C. A small amount of condensate and heavy hydrocarbon liquid precipitated during the cooling process collects in a separator and is discharged through an automatic drain valve.

[0031] The cooled gas enters the second-stage cylinder, undergoing another compression process. The control system monitors the intake and exhaust pressures at each stage to ensure the actual compression ratio of each stage is maintained at 2.5. After two stages of compression and cooling, the gas enters the third-stage cylinder for final pressurization. The piston diameter of the third-stage cylinder is designed to handle high-pressure conditions. After three stages of compression, the gas pressure is increased to the final injection pressure of 20 MPa. The gas discharged from the final stage is at a relatively high temperature and is directed into a shell-and-tube aftercooler. The operator adjusts the cooling water flow control valve to precisely cool the gas temperature to 60°C.

[0032] Subsequently, the gas enters the high-pressure gas injection heat exchange system. Gas at 20 MPa enters the tube side of the shell-and-tube heat exchanger, and the flow controller maintains the gas velocity inside the tubes at 15 m / s, creating turbulent flow to enhance heat transfer. Simultaneously, the lifted produced fluid from the formation (temperature approximately 75°C) is introduced into the shell side. Guided by baffles, the produced fluid repeatedly flushes the tube bundle, transferring heat to the injected gas in the tube side. A differential pressure transmitter monitors the inlet and outlet pressure difference of the heat exchanger in real time; the current reading is 0.05 MPa, not exceeding 1.2 times the initial pressure difference, indicating that the scaling on the tube walls is within acceptable limits. By adjusting the bypass flow rate of the shell-side fluid, the injected gas temperature is ultimately stabilized at 60°C and delivered to the high-pressure gas injection main through the outlet check valve.

[0033] Table 3 Performance Data of Compression and Heat Exchange System Parameter name unit numerical values Remark First stage exhaust pressure Megapascal 1.20 Pressure sensor readings Interstage cooling temperature Celsius 35.0 Temperature after air cooling Compression ratio Dimensionless 2.50 pressure ratio Final stage exhaust pressure Megapascal 20.0 Design injection pressure Tube gas flow rate meters per second 15.0 Flow meter conversion After heat exchange, the air temperature Celsius 60.0 heat exchange endpoint temperature Table 3 lists the measured data of each key node of the compressor unit, and all indicators meet the lower limit parameter settings of Example 1.

[0034] Please see Figure 1S4: Adjust the flow rate of high-pressure gas injection, quantitatively injecting it into the annulus of each production well via the injection pipeline. This mixes with the formation fluid within the wellbore, driving the fluid to rise to the surface and produce lifted production fluid. Connect the high-pressure gas injection main to the gas distribution manifold, and after adjusting the flow rate via intelligent needle valves, inject the lifted production fluid into the casing gate valves of each individual well, driving the fluid back to the surface. The lifted production fluid is then recycled back to the inlet of the S1 three-phase separator. The specific execution process of flow rate adjustment includes: acquiring formation pressure, water cut, and production index data for each individual well, and calculating the theoretical gas injection volume required to maintain stable production in the well based on the tubing string structure parameters, which serves as the target setpoint for flow rate adjustment. High-pressure air is introduced into the valve seat cavity of the intelligent needle valve, and the valve needle is driven to move axially by a servo motor, changing the flow area of ​​the valve port so that the fluid reaches the critical flow state when it flows through the valve port. The actual gas injection flow rate and pressure data are collected in real time by using flow meters and pressure transmitters installed after the valve, and then fed back to the central control unit for comparison and analysis with the target set value. The valve needle stroke position is dynamically adjusted based on the comparison deviation value. This step also includes a gas lift efficiency optimization process, which specifically involves: collecting wellhead casing pressure, wellhead oil pressure, daily fluid production, and injected gas volume data for each individual well to construct a production database reflecting changes in the operating conditions of the gas lift wells; Based on real-time data from the production database, the current gas injection efficiency stability index is calculated using a gas lift performance evaluation model. ; Gas injection efficiency stability index The calculation formula is as follows: ; in, This represents the injection flow rate under standard conditions. Represents the gas injection sleeve pressure. Represents the wellhead oil pressure. Represents daily liquid production. This represents the average density of the gas-liquid mixture within the wellbore. Represents gravitational acceleration. Represents the effective lifting height. Represents the bottom hole temperature. Represents the wellhead temperature; Based on the calculated gas injection efficiency stability index The opening degree of the intelligent needle valve is iteratively corrected, and an alarm is automatically triggered and an adaptive adjustment strategy is executed when the index deviates from the preset optimal range.

[0035] The latest formation pressure, water cut (currently 85%), and production index data for each well were retrieved through the SCADA system. Combined with wellbore structure calculations, the theoretical gas injection rate for Well A was determined to be 20,000 standard cubic meters per day. The control center issued a command, and high-pressure gas was distributed to the intelligent needle valve of Well A via the main pipe. The servo motor received a 4-20mA control signal, driving the valve needle micro-motion to adjust the valve opening, allowing high-pressure gas to be injected into the annulus at a critical flow state. The Coriolis mass flow meter installed downstream of the valve measured the actual injection flow rate in real time as 19,800 standard cubic meters per day, with an injection pressure of 19.5 MPa. The control unit compared the data and found the deviation to be less than 1%, maintaining the current valve position. After the injected gas entered the annulus, the fluid mixing density within the wellbore decreased, and the lifted produced fluid was successfully returned to the surface.

[0036] To further optimize gas lift efficiency, the system automatically executes a gas lift performance evaluation program. The real-time production data collected from Well A is as follows: Gas injection flow rate under standard conditions. The capacity is 20,000 cubic meters per day, and the gas injection casing pressure is... The wellhead oil pressure is 19.5 MPa. The pressure is 1.5 MPa, and the daily liquid production is... The average density of the gas-liquid mixture in the wellbore is 150 cubic meters per day. The effective lifting height is 750 kg / m³. At a depth of 2000 meters, the bottom temperature... The wellhead temperature was 383.15 Kelvin (110°C). The acceleration due to gravity is 323.15 Kelvin (50°C). Take 9.81 m / s².

[0037] Substitute the above parameter values ​​into the formula for calculating the gas injection efficiency stability index: ; in, This represents the injection flow rate under standard conditions. Represents the gas injection sleeve pressure. Represents the wellhead oil pressure. Represents daily liquid production. This represents the average density of the gas-liquid mixture within the wellbore. Represents gravitational acceleration. Represents the effective lifting height. Represents the bottom hole temperature. This represents the wellhead temperature.

[0038] The stability index of the gas injection efficiency was calculated. The result is 27.76 (Note: the pressure unit here is uniformly converted to Pascal for calculation to ensure dimensional consistency). The system compares this calculation result with the preset optimal range [25.0, 30.0] to determine that the current air lift operation is in a stable and efficient range. If the calculation result deviates from this range, the system will automatically trigger the PID self-tuning algorithm to fine-tune the opening of the intelligent needle valve until the index returns to the normal range.

[0039] Table 4. Airlift Optimization Control Parameters Parameter name unit numerical values Remark Target gas injection volume Standard per day 20000 Theoretical calculation value Actual gas injection flow rate Standard per day 19800 Actual flow meter measurement Gas injection sleeve pressure Megapascal 19.5 pressure transmitter Wellhead oil pressure Megapascal 1.5 pressure transmitter Stability Index Dimensionless 27.76 Model calculation results As shown in Table 4, through intelligent adjustment and model calculation, precise control of the injection volume and real-time evaluation of the gas lift efficiency were achieved.

[0040] Table 5 Comparison of Product Performance in Example 1 Performance indicators unit Product of Example 1 conventional air lift process products Remark Associated gas methane purity percentage 93.5 88.0 After dehydration and purification Lifting system efficiency percentage 28.5 22.0 Energy utilization rate Gas injection pressure fluctuation rate percentage ±1.5 ±5.0 Stability Indicators Maintenance cycle moon 18 12 Equipment reliability

[0041] Example 2

[0042] In this embodiment, the three-phase separator operates at a pressure of 4.0 MPa, the corrugated coalescing plate assembly is tilted at 60 degrees, and the fluid residence time in the separator settling section is 20 minutes. The plate dehydration tower top temperature is controlled at 45°C, the buffer section airflow rectification velocity is 1.2 m / s, the average droplet diameter of the lean triethylene glycol solution is 800 micrometers, the plate pressure drop is maintained at 1.0 kPa, the rich liquid preheating temperature is 100°C, the flash pressure is 0.6 MPa, and the reboiler heating temperature is 204°C. The multi-stage reciprocating compressor unit has an interstage cooling temperature of 50°C, a final stage exhaust temperature adjusted to 80°C, a first-stage compression final pressure of 1.5 MPa, a first-stage intercooler outlet temperature of 42°C, a compression ratio controlled at 3.0 for each stage, a design injection pressure of 25 MPa, a tube-side gas velocity of 20 m / s in the shell-and-tube heat exchanger, and a gas temperature controlled at 80°C after heat exchange.

[0043] Please see Figure 1 This invention provides a technical solution: a natural gas cluster gas lift process, comprising the following steps: S1: Multiple gas-liquid mixtures from the cluster well group are fed into a three-phase separator. Under an operating pressure of 2.5-4.0 MPa, three-phase separation is performed using the density difference between gas and liquid. The liquid phase mixture at the bottom is removed, yielding the crude associated gas at the top. The production manifold of the cluster well group is physically connected to the inlet of the three-phase separator. A coalescing plate assembly is installed inside the separator to enhance phase separation. The separated crude associated gas is continuously discharged from the top pipeline, while the liquid phase mixture deposited at the bottom is transported to the storage tank area via a drain valve. The enhanced phase separation process specifically involves guiding the lifted produced fluid from the production manifold to the inlet rectifier chamber of the three-phase separator, where large-diameter free bubbles are initially separated. The rectified fluid is passed through a set of corrugated coalescing plates with an inclination angle of 45 to 60 degrees in a laminar flow state to capture and coalesce the tiny oil or water droplets of the dispersed phase. The residence time of the fluid in the settling section of the separator is controlled to be maintained at 15 to 20 minutes to form a clear oil-water interface; By monitoring the height of the oil-water interface in real time using an interface meter installed at the oil-water interface, and adjusting the opening of the oil outlet valve and water outlet valve based on the monitoring data using PID control, the upper layer of crude oil and the lower layer of wastewater are discharged independently.

[0044] The operator delivers the gas-liquid mixture from the high-pressure well area to the inlet of the three-phase separator via the production manifold. Given the high fluid pressure under these conditions, the separator inlet rectifier chamber employs a reinforced anti-impact plate design. After the fluid enters, the pressure transmitter displays that the current internal operating pressure of the separator stabilizes at 4.0 MPa. The high-pressure environment is beneficial for retaining light hydrocarbon components in the gas phase, but it also places higher demands on liquid phase separation. After rectification, the fluid smoothly enters the settling zone and then flows into the corrugated coalescing plate assembly. In this embodiment, the tilt angle of the coalescing plate is set at 60 degrees. This large tilt angle is designed to accelerate the sliding of separated heavy phase droplets and prevent plate blockage under high-pressure, high-load conditions.

[0045] Fluid flows within the gaps between coalescing plates, where dispersed phase droplets coalesce and grow on the plate surface. The fluid then enters the settling section of the separator. To ensure complete separation under high pressure and complex component conditions, operators extend the fluid's residence time in the settling section to 20 minutes via a level control loop. At this point, the oil-water interface becomes clearer and more stable. A guided wave radar interface meter continuously monitors the interface height, and the DCS system dynamically adjusts the opening of the large-diameter oil and water outlet valves based on the monitoring data using a PID algorithm. Due to the high throughput and pressure, the PID parameters are set to (proportional coefficient Kp = 1.5, integral time Ti = 0.8 min, derivative time Td = 0.2 min) to prevent adjustment oscillations. The separated crude associated gas is discharged from the top pipeline, metered by a flow meter, and then enters the next stage; the bottom wastewater and the upper crude oil are discharged separately. Sampling and testing every two hours show that the oil-water separation effect is good under the combined effect of high pressure and long residence time.

[0046] Table 6. Operating Data of High-Pressure Three-Phase Separator Parameter name unit numerical values Remark Inlet pressure Megapascal 4.00 High-voltage operating conditions Cohesion plate tilt angle Spend 60.0 Anti-clogging design liquid phase residence time minute 20.0 Deep separation Oil phase water content percentage 0.38 Centrifugation method Oil content in aqueous phase mg / L 38.5 Infrared spectrophotometry determination vapor phase liquid content mg / m³ 10.2 Filter paper weighing method for determination Referring to Table 6, under a high pressure of 4.0 MPa and a residence time of 20 minutes, the water content of the oil phase further decreased to 0.38%, indicating that the process parameters are suitable for processing high-pressure, difficult-to-separate well flow materials.

[0047] S2: The crude associated gas is introduced into the bottom of the plate dehydration tower, where it comes into countercurrent contact with the lean triethylene glycol solution sprayed from the top of the tower within the packing layer. The gas-liquid balance is controlled, and deep dehydration is performed at a top temperature of 35-45℃ to obtain dry gas. The specific execution process of the deep dehydration treatment includes: S21: The crude associated gas is introduced into the buffer section of the plate dehydration tower through the bottom air inlet pipe, and the airflow velocity is rectified to a stable flow rate of 0.8 to 1.2 m / s; S22: The lean triethylene glycol solution is pressurized and transported to the top spray device of the plate dehydration tower by a circulating pump. The solvent is atomized into droplets with an average diameter of 500 to 800 micrometers through spiral nozzles, forming a uniform liquid film covering the entire cross section of the tower. S23: Control the rising crude associated gas and the descending lean triethylene glycol solution to make cross-flow contact on the multi-layer bubble cap tray, maintain the tray pressure drop at 0.5 to 1.0 kPa, and absorb saturated water vapor in the gas flow. S24: The dehydrated airflow is guided to the wire mesh demister at the top of the tower, where the intercepted droplets are coalesced and returned to the tower plate; S25: Real-time monitoring of the water dew point temperature of the gas flow at the top outlet of the tower. When the water dew point is below -10 degrees Celsius, the regulating valve at the top outlet of the tower is opened to discharge the gas and obtain dry gas. During the process, the crude associated gas is introduced into the lower inlet of the plate dehydration tower, allowing it to pass through the bubble cap tray and fully contact the lean triethylene glycol solution. The dry gas discharged from the top of the tower is purified by a filter and then fed into a buffer tank. The rich liquid after water absorption is sent to the regeneration kettle for purification and circulation. The specific execution process of the rich liquid purification and circulation includes: collecting the triethylene glycol rich liquid that has absorbed water discharged from the bottom of the plate dehydration tower, passing it through a lean-rich liquid heat exchanger to exchange heat countercurrently with the high-temperature lean triethylene glycol solution, and preheating the rich liquid temperature to 80 to 100 degrees Celsius. The preheated rich liquid is sent to a flash tank and flashed at a low pressure of 0.4 to 0.6 MPa to separate and recover the hydrocarbon gases dissolved in the rich liquid. The rich liquor after flash evaporation is sent to a reboiler, where the heat provided by the burner is used to heat the rich liquor to a boiling temperature of 195 to 204 degrees Celsius, causing the water in it to vaporize and evaporate. Dry stripping gas is introduced into the stripping tower to further remove trace amounts of water remaining in the solvent, restoring the triethylene glycol mass concentration to over 99.0% and obtaining a regenerated lean triethylene glycol solution.

[0048] Under high-load conditions, operators introduce crude associated gas into the bottom of the plate-type dehydration tower. The inlet gas volume is relatively large; by adjusting the inlet valve, the gas velocity in the buffer section is stabilized at 1.2 m / s, close to the operating limit, to maximize processing capacity. A lean liquor circulation pump delivers a high-concentration lean triethylene glycol solution to the top of the tower, where the solvent is atomized into droplets with an average diameter of 800 micrometers through a high-flow-rate spiral nozzle. The larger droplet diameter helps reduce mist entrainment at high gas velocities while maintaining sufficient specific surface area. The tower top temperature is controlled at 45°C, utilizing the higher operating temperature to enhance mass transfer driving force and meet the high-volume dehydration requirements.

[0049] The gas and liquid phases come into intense contact on the trays. Operators closely monitor the tray pressure drop, maintaining it at approximately 1.0 kPa to ensure sufficient gas-liquid contact and prevent flooding. The dehydrated gas passes through a wire mesh demister to remove entrained droplets. Online monitoring shows that the water dew point of the gas at the top of the column is -15 degrees Celsius (better than the -10 degree Celsius standard), and the outlet regulating valve automatically opens, discharging high-quality dry gas.

[0050] After absorbing water, the rich liquor enters the regeneration system, where it is preheated to 100°C (close to the boiling point of water) via a rich-lean liquor heat exchanger to pre-flash some of the lighter components. It then enters a flash tank at a pressure set at 0.6 MPa to recover dissolved hydrocarbon gases. The rich liquor continues to flow into the reboiler, where the burner operates at full load, raising and maintaining the reboiler temperature at 204°C. With the introduction of drying stripping gas, the water in the rich liquor is thoroughly removed, resulting in a lean liquor concentration of over 99.5%, which is then returned to the dehydration tower for recycling.

[0051] Table 7 High-load dehydration and regeneration parameters Parameter name unit numerical values Remark airflow speed meters per second 1.20 Maximum processing capacity droplet diameter micrometer 800 Anti-pinch setting Tower top temperature Celsius 45.0 Enhanced mass transfer Tray pressure drop kPa 1.00 Gas-liquid contact limit reboiler temperature Celsius 204.0 Deep Regeneration Dry air dew point Celsius -15.0 Better than the standard Anemic fluid concentration percentage 99.5 High-temperature regeneration effect As shown in Table 7, the limiting parameter settings in Example 2 ensured the dehydration depth and solvent regeneration quality under large volume processing conditions.

[0052] Please see Figure 1 S3: Dry gas is delivered to a multi-stage reciprocating compressor unit for three-stage pressurization. The interstage cooling temperature is controlled at 40-50℃ via an intercooler, and the final stage exhaust temperature is adjusted to 60-80℃ using an aftercooler, resulting in high-pressure injection gas. The specific execution process of the three-stage pressurization includes: S31: The first-stage intake valve of the multi-stage reciprocating compressor unit draws in dry gas that has been pressure-stabilized by the buffer tank, and the gas pressure is increased from the primary pressure to 1.2 to 1.5 MPa under the action of cylinder volume change; S32: The high-temperature gas after primary compression is introduced into the primary intercooler, and the gas temperature is reduced to below 45 degrees Celsius by forced air cooling, and the condensate precipitated during the cooling process is separated and discharged. S33: The cooled gas is sequentially fed into the second-stage and third-stage cylinders for relay compression, and the compression ratio of each stage is strictly controlled between 2.5 and 3.0. Through step-by-step work, the gas pressure is increased to the design injection pressure of 20 to 25 MPa. S34: The aftercooler installed at the compressor outlet is used to perform heat exchange treatment on the gas discharged from the final stage, and the gas temperature is precisely controlled within the range of 65 to 75 degrees Celsius by adjusting the flow rate of the cooling medium. S35: The processed gas is delivered to the high-pressure buffer container via an outlet check valve. A pressure sensor monitors pressure fluctuations within the container. When the pressure stabilizes at a set threshold, the output valve opens, resulting in high-pressure injection gas. During execution, dry gas from the buffer tank is pumped into a multi-stage reciprocating compressor unit. After being processed by an intercooler, it undergoes heat exchange using a shell-and-tube heat exchanger with geothermal fluids. The resulting high-pressure injection gas is then delivered to the high-pressure injection main pipe. The specific heat exchange process includes: introducing high-temperature compressed gas from the multi-stage reciprocating compressor unit into the tube side of the shell-and-tube heat exchanger, controlling the gas velocity within the tube bundle to be 15 to 20 m / s. The high-temperature produced liquid from the formation is introduced into the shell side of the shell-and-tube heat exchanger, where it is laterally flushed by the tube bundle under the guidance of the baffles and exchanges heat with the gas in the tube side in a countercurrent manner. Monitor the temperature and pressure difference data at the inlet and outlet of the heat exchanger. When the pressure difference exceeds 1.2 times the design value, start the online cleaning program or switch to the standby heat exchanger to remove the paraffin or scale deposited on the tube wall surface. Adjust the bypass flow rate of the shell-side fluid to precisely control the gas temperature after heat exchange and maintain it between 60 and 80 degrees Celsius.

[0053] Dry gas from the buffer tank enters the multi-stage reciprocating compressor unit, which operates at full load. After the first-stage intake, the piston powerfully compresses the gas, raising the first-stage discharge pressure to 1.5 MPa. The high-temperature gas enters the first-stage intercooler, where its temperature drops to 42°C (meeting the requirement of below 45°C) under strong air cooling. The gas then sequentially enters the second and third-stage cylinders. The control system sets the compression ratio of each stage to 3.0 to fully utilize the compressor's mechanical performance. After stage-by-stage pressurization, the gas pressure discharged from the final stage reaches the designed maximum injection pressure of 25 MPa.

[0054] The high-temperature gas discharged from the final stage enters the aftercooler. Due to the high compression ratio, the exhaust temperature is extremely high. Operators adjust the cooling medium flow rate to control the final gas temperature at 80°C. The gas then enters the high-pressure injection heat exchanger. In the tube side, the gas velocity is increased to 20 m / s, creating a highly turbulent flow that significantly improves the convective heat transfer coefficient. High-temperature, high-pressure lift-up produced fluid (approximately 90°C) is introduced into the shell side, where it exchanges heat counter-currently with the tube-side gas. Operators closely monitor the differential pressure readings. When fluctuations in the differential pressure are detected due to the shedding of minute deposits caused by the high-velocity scouring, the standby heat exchanger switching procedure is promptly initiated to perform online cleaning of the main heat exchanger. After precise heat balance adjustment, the injection temperature at the heat exchanger outlet stabilizes at 80°C, meeting the thermodynamic requirements of deep-well high-pressure gas lift. Finally, the gas is transported to the injection pipeline network via a high-pressure buffer container.

[0055] Table 8 Performance Data of High Pressure Compression System Parameter name unit numerical values Remark First stage exhaust pressure Megapascal 1.50 Full load operation Interstage cooling temperature Celsius 42.0 Approaching the upper limit Compression ratio Dimensionless 3.00 Maximum efficiency point Final stage exhaust pressure Megapascal 25.0 Maximum design pressure Tube gas flow rate meters per second 20.0 Enhanced heat transfer After heat exchange, the air temperature Celsius 80.0 High-temperature gas injection The data in Table 8 show that, under the maximum parameter settings, the system can stably produce high-energy injection fluid at 25 MPa and 80°C.

[0056] Please see Figure 1 S4: Adjust the flow rate of high-pressure gas injection, quantitatively injecting it into the annulus of each production well via the injection pipeline. This mixes with the formation fluid within the wellbore, driving the fluid to rise to the surface and produce lifted production fluid. Connect the high-pressure gas injection main to the gas distribution manifold, and after adjusting the flow rate via intelligent needle valves, inject the lifted production fluid into the casing gate valves of each individual well, driving the fluid back to the surface. The lifted production fluid is then recycled back to the inlet of the S1 three-phase separator. The specific execution process of flow rate adjustment includes: acquiring formation pressure, water cut, and production index data for each individual well, and calculating the theoretical gas injection volume required to maintain stable production in the well based on the tubing string structure parameters, which serves as the target setpoint for flow rate adjustment. High-pressure air is introduced into the valve seat cavity of the intelligent needle valve, and the valve needle is driven to move axially by a servo motor, changing the flow area of ​​the valve port so that the fluid reaches the critical flow state when it flows through the valve port. The actual gas injection flow rate and pressure data are collected in real time by using flow meters and pressure transmitters installed after the valve, and then fed back to the central control unit for comparison and analysis with the target set value. The valve needle stroke position is dynamically adjusted based on the comparison deviation value. This step also includes a gas lift efficiency optimization process, which specifically involves: collecting wellhead casing pressure, wellhead oil pressure, daily fluid production, and injected gas volume data for each individual well to construct a production database reflecting changes in the operating conditions of the gas lift wells; Based on real-time data from the production database, the current gas injection efficiency stability index is calculated using a gas lift performance evaluation model. ; Gas injection efficiency stability index The calculation formula is as follows: ; in, This represents the injection flow rate under standard conditions. Represents the gas injection sleeve pressure. Represents the wellhead oil pressure. Represents daily liquid production. This represents the average density of the gas-liquid mixture within the wellbore. Represents gravitational acceleration. Represents the effective lifting height. Represents the bottom hole temperature. Represents the wellhead temperature; Based on the calculated gas injection efficiency stability index The opening degree of the intelligent needle valve is iteratively corrected, and an alarm is automatically triggered and an adaptive adjustment strategy is executed when the index deviates from the preset optimal range.

[0057] For the deep, high-pressure well B, the system acquired its formation parameters and production index, calculating a theoretical gas injection volume of 50,000 standard cubic meters per day required to maintain production. High-pressure gas at 25 MPa was injected via a distribution manifold to the intelligent needle valve at well B. A servo motor drove the valve needle to a predetermined opening, allowing high-pressure gas to pass through the valve port. The flow meter reported an actual flow rate of 50,100 standard cubic meters per day and an injection pressure of 24.8 MPa; the control unit confirmed the deviation was within acceptable limits. The high-pressure gas flow was injected into the annulus, powerfully lifting the deep fluid.

[0058] Entering the gas lift efficiency optimization phase, the system collects real-time data from well B: gas injection flow rate under standard conditions. The gas injection casing pressure is 50,000 cubic meters per day. The wellhead oil pressure is 24.8 MPa. The pressure is 2.0 MPa, and the daily liquid production is... The average density of the gas-liquid mixture in the wellbore is 300 cubic meters per day. 800 kg / m³, effective lifting height At a depth of 3500 meters, the bottom temperature... The wellhead temperature was 403.15 Kelvin (130℃). The gravitational acceleration is 333.15 Kelvin (60°C). Take 9.81 m / s².

[0059] Substitute the above parameter values ​​into the aforementioned formula for calculating the gas injection efficiency stability index. The calculated gas injection efficiency stability index is... The result is 26.37 (Note: the pressure parameters have also been converted to Pascals for calculation). This value is within the preset high-efficiency range [25.0, 30.0], indicating that under high-pressure deep well conditions, the current gas distribution scheme and lifting process are highly compatible, and no valve opening adjustment is required. The system records this state parameter as a reference benchmark for subsequent production in similar wells.

[0060] Table 9 Deep Well Gas Lift Optimization Data Table Parameter name unit numerical values Remark Target gas injection volume Standard per day 50000 High-yield well setting Actual gas injection flow rate Standard per day 50100 Flow meter feedback Gas injection sleeve pressure Megapascal 24.8 High-pressure gas injection Wellhead oil pressure Megapascal 2.0 Back pressure control Stability Index Dimensionless 26.37 Located in the preferred area Table 9 shows the system's operational stability under high load conditions, as verified by the model.

[0061] Table 10 Comparison of Product Performance in Example 2 Performance indicators unit Product of Example 2 conventional air lift process products Remark Associated gas methane purity percentage 95.2 89.5 Deep dehydration and purification Lifting system efficiency percentage 31.0 24.5 After high voltage optimization Maximum lifting depth rice 4200 3000 Improved stress tolerance Compressor energy efficiency ratio kWh / standard 0.12 0.18 Interstage cooling optimization The above embodiments illustrate preferred embodiments of the present invention. Any equivalent adjustments to the technical solution based on chemical engineering methods are within the scope of protection, including but not limited to: using different chemical reaction processes to achieve technical effects, optimizing the production process flow, adjusting the raw material ratio scheme, improving reactor design, and improving energy efficiency. Any implementation scheme derived from reasonable modifications to the production process, raw material utilization, equipment configuration, or system integration level without departing from the core technology of the present invention should be considered within the protection scope defined by the technical solution of the present invention.

Claims

1. A natural gas cluster gas lift process, characterized in that, include: S1: Multiple gas-liquid mixtures from the cluster well group are fed into the three-phase separator. Under an operating pressure of 2.5-4.0 MPa, the gas-liquid density difference is used to perform three-phase separation. The liquid phase mixture at the bottom is separated and removed to obtain the crude associated gas at the top. S2: The crude associated gas is introduced into the bottom of the plate dehydration tower, so that it comes into countercurrent contact with the lean triethylene glycol solution sprayed from the top of the tower in the packing layer. The gas-liquid balance is controlled, and deep dehydration is carried out under the condition of 35-45℃ at the top of the tower to obtain dry gas. S3: Dry gas is delivered to a multi-stage reciprocating compressor unit for three-stage pressurization. The interstage cooling temperature is controlled at 40-50℃ by the intercooler, and the final stage exhaust temperature is adjusted to 60-80℃ by the aftercooler to obtain high-pressure injection gas. S4: Adjust the flow rate of high-pressure gas injection and inject it quantitatively into the annulus of each production well via the gas injection pipeline, so that it mixes with the formation fluid in the wellbore and drives the fluid to be lifted to the surface to obtain the lifted production fluid.

2. The natural gas cluster gas lift process according to claim 1, characterized in that, The specific execution process of the deep dehydration treatment in S2 includes: S21: The crude associated gas is introduced into the buffer section of the plate dehydration tower through the bottom air inlet pipe, and the airflow velocity is rectified to a stable flow rate of 0.8 to 1.2 m / s; S22: The lean triethylene glycol solution is pressurized and transported to the top spray device of the plate dehydration tower using a circulating pump. The solvent is atomized into droplets with an average diameter of 500 to 800 micrometers through a spiral nozzle, forming a uniform liquid film covering the entire cross section of the tower. S23: Control the rising crude associated gas and the descending lean triethylene glycol solution to make cross-flow contact on the multi-layer bubble cap tray, maintain the tray pressure drop at 0.5 to 1.0 kPa, and absorb saturated water vapor in the gas flow. S24: The dehydrated airflow is guided to the wire mesh demister at the top of the tower, where the intercepted droplets are coalesced and returned to the tower plate; S25: Monitor the water dew point temperature of the gas flow at the top of the tower in real time. When the water dew point is below -10 degrees Celsius, open the regulating valve at the top of the tower to discharge the gas and obtain dry gas.

3. The natural gas cluster gas lift process according to claim 1, characterized in that, The specific execution process of the three-stage boost process in S3 includes: S31: The first-stage intake valve of the multi-stage reciprocating compressor unit draws in dry gas that has been pressure-stabilized by the buffer tank, and the gas pressure is increased from the primary pressure to 1.2 to 1.5 MPa under the action of cylinder volume change; S32: The high-temperature gas after primary compression is introduced into the primary intercooler, and the gas temperature is reduced to below 45 degrees Celsius by forced air cooling, and the condensate precipitated during the cooling process is separated and discharged. S33: The cooled gas is sequentially fed into the second-stage and third-stage cylinders for relay compression, and the compression ratio of each stage is strictly controlled between 2.5 and 3.

0. Through step-by-step work, the gas pressure is increased to the design injection pressure of 20 to 25 MPa. S34: The aftercooler installed at the compressor outlet is used to perform heat exchange treatment on the gas discharged from the final stage, and the gas temperature is precisely controlled within the range of 65 to 75 degrees Celsius by adjusting the flow rate of the cooling medium. S35: The qualified gas is delivered to the high-pressure buffer container through the outlet check valve. The pressure sensor monitors the pressure fluctuation in the container. When the pressure stabilizes at the set threshold, the output valve is opened to obtain high-pressure gas injection.

4. A method for preparing natural gas cluster gas lift, characterized in that, The method is used to perform the natural gas cluster lift process according to any one of claims 1-3, and includes the following steps: The production manifold of the cluster well group is physically connected to the inlet of the three-phase separator. A coalescing plate assembly is installed inside the separator to enhance phase separation. The separated crude associated gas is continuously discharged from the top pipeline, and the liquid phase mixture deposited at the bottom is transported to the storage tank area through the drain valve. The crude associated gas is introduced into the lower air inlet of the plate dehydration tower, allowing it to pass through the bubble cap plate and fully contact the lean triethylene glycol solution. The dry gas discharged from the top of the tower is purified by a filter and then fed into a buffer tank. The water-absorbed rich liquid is then transported to a regeneration kettle for purification and recycling. The dry gas in the buffer tank is pumped into a multi-stage reciprocating compressor unit. After being processed by an intercooler, it is heat-exchanged by the hot fluid produced by the formation through a shell-and-tube heat exchanger. The obtained high-pressure injection gas is then delivered to the high-pressure injection main pipe. The high-pressure gas injection main is connected to the gas distribution manifold. After the flow rate is adjusted by the intelligent needle valve, the gas is injected into the casing gate of each well. This drives the lifted produced fluid to be discharged back to the surface, and the lifted produced fluid is then recycled back to the inlet of the three-phase separator in S1.

5. The method for preparing natural gas clusters via gas lift according to claim 4, characterized in that, The enhanced phase separation process includes: The lifted product fluid entering from the production manifold is guided to the inlet rectifier chamber of the three-phase separator, where large-diameter free bubbles are initially separated. The rectified fluid is passed through a set of corrugated coalescing plates with an inclination angle of 45 to 60 degrees in a laminar flow state to capture and coalesce the tiny oil or water droplets of the dispersed phase. The residence time of the fluid in the settling section of the separator is controlled to be maintained at 15 to 20 minutes to form a clear oil-water interface; By monitoring the height of the oil-water interface in real time using an interface meter installed at the oil-water interface, and adjusting the opening of the oil outlet valve and water outlet valve based on the monitoring data using PID control, the upper layer of crude oil and the lower layer of wastewater are discharged independently.

6. The method for preparing natural gas clusters via gas lift according to claim 4, characterized in that, The specific execution process of the rich liquid purification cycle includes: Collect the triethylene glycol rich liquid that has absorbed water and discharged from the bottom of the plate dehydration tower, and pass it through a lean-rich liquid heat exchanger to exchange heat with the high-temperature lean triethylene glycol solution in a countercurrent manner, so as to preheat the temperature of the rich liquid to 80 to 100 degrees Celsius. The preheated rich liquid is sent to a flash tank and flashed at a low pressure of 0.4 to 0.6 MPa to separate and recover the hydrocarbon gases dissolved in the rich liquid. The rich liquor after flash evaporation is sent to a reboiler, where the heat provided by the burner is used to heat the rich liquor to a boiling temperature of 195 to 204 degrees Celsius, causing the water in it to vaporize and evaporate. Dry stripping gas is introduced into the stripping tower to further remove trace amounts of water remaining in the solvent, restoring the triethylene glycol mass concentration to above 99.0%, thus obtaining the regenerated lean triethylene glycol solution.

7. The method for preparing natural gas clusters via gas lift according to claim 4, characterized in that, The specific execution process of the heat exchange includes: The high-temperature compressed gas discharged from the multi-stage reciprocating compressor unit is introduced into the tube side of the shell-and-tube heat exchanger, and the gas flow velocity in the tube bundle is controlled to be 15 to 20 m / s. The high-temperature lift-up produced fluid from the formation is introduced into the shell side of the shell-and-tube heat exchanger, where it is laterally flushed by the tube bundle under the guidance of baffles, and exchanges heat with the gas in the tube side in a countercurrent manner. Monitor the temperature and pressure difference data at the inlet and outlet of the heat exchanger. When the pressure difference exceeds 1.2 times the design value, start the online cleaning program or switch to the standby heat exchanger to remove the paraffin or scale deposited on the tube wall surface. Adjust the bypass flow rate of the shell-side fluid to precisely control the gas temperature after heat exchange and maintain it between 60 and 80 degrees Celsius.

8. The method for preparing natural gas clusters via gas lift according to claim 4, characterized in that, The specific execution process of the flow regulation includes: Data on formation pressure, water cut, and production index of each well are obtained, and the theoretical gas injection volume required to maintain stable production of the well is calculated in combination with the tubing structure parameters, which serves as the target setpoint for flow rate regulation. High-pressure air is introduced into the valve seat cavity of the intelligent needle valve, and the valve needle is driven to move axially by a servo motor, changing the flow area of ​​the valve port so that the fluid reaches the critical flow state when it flows through the valve port. The actual gas injection flow rate and pressure data are collected in real time using flow meters and pressure transmitters installed after the valve, and then fed back to the central control unit for comparison and analysis with the target set value. The valve needle's stroke position is dynamically adjusted based on the comparison deviation value.

9. The method for preparing natural gas clusters via gas lift according to claim 4, characterized in that, The method further includes an air lift efficiency optimization process, which includes: Collect data on wellhead casing pressure, wellhead oil pressure, daily fluid production, and injected gas volume for each individual well to construct a production database that reflects changes in the operating conditions of gas lift wells; Based on real-time data from the production database, the current gas injection efficiency stability index is calculated using a gas lift performance evaluation model. ; The gas injection efficiency stability index The calculation formula is as follows: ； in, This represents the injection flow rate under standard conditions. Represents the gas injection sleeve pressure. Represents the wellhead oil pressure. Represents daily liquid production. This represents the average density of the gas-liquid mixture within the wellbore. Represents gravitational acceleration. Represents the effective lifting height. Represents the bottom hole temperature. Represents the wellhead temperature; Based on the calculated gas injection efficiency stability index The opening degree of the intelligent needle valve is iteratively corrected, and an alarm is automatically triggered and an adaptive adjustment strategy is executed when the index deviates from the preset optimal range.

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