A natural gas positive and negative gas lift coordinated pressure reduction and production increase process

Abstract

The present application relates to the field of natural gas extraction technology, and specifically to a natural gas positive and negative gas lift coordinated pressure reduction and production increase process, which includes: dividing the gas injection stages based on the numerical range of the annular liquid level height and adjusting the positive gas lift ratio: in the first stage, based on the degree of change in the annular liquid level height, determining the positive gas lift ratio at each moment of the first stage; in the second stage, based on the discrete degree of the annular pressure at the bottom of the well and the tubing pressure, combined with the discrete changes in the gas-liquid mixture density at all sampling points at each moment, obtaining a differential coefficient, and adjusting the positive gas lift ratio at each moment of the second stage; in the third stage, analyzing the numerical distribution of the annular pressure at the bottom of the well and the tubing pressure to obtain the positive gas lift ratio at each moment of the third stage; if the positive gas lift ratio at any stage of gas injection decreases to a preset value, reverse gas lift is subsequently used for natural gas extraction. The present application aims to improve gas extraction efficiency and stabilize gas well pressure.

Description

Technical Field

[0001] The present application relates to the field of natural gas extraction technology, and specifically to a natural gas forward and reverse gas lift coordinated pressure reduction and production increase process. Background Art

[0002] Natural gas extraction faces numerous challenges in fields with high liquid columns, low pressure, and low permeability. These geological conditions make the flow of natural gas underground extremely difficult, significantly limiting extraction efficiency. During the extraction process, insufficient formation energy prevents the wellbore from draining the accumulated liquid (primarily a mixture of formation water and condensate). This accumulation forms a high liquid column, which in turn blocks the flow path and ultimately stops the well from flowing, severely impacting the field's production capacity and economic benefits.

[0003] The paper "Study on Gas Lift Methods for Natural Gas Compressors in the Sulige Gas Field" uses the Changqing Sulige Gas Field as an example. When the wellbore liquid column height exceeds 2500 m, both direct and reverse gas lift methods are unable to induce fluid flow and discharge. Therefore, a combined pressure-reducing gas lift process is proposed to restore production. Under the maximum discharge pressure of the natural gas compressor of 25 MPa, a high-pressure gas source is introduced to inject and pressurize the wellbore tubing and casing annulus, temporarily pushing some of the accumulated fluid back into the formation. Then, conventional gas lift is performed on the gas well.

[0004] However, this phased operation involves significant switching gaps, which causes formation pressure to rebound after the closing phase, triggering a rebound in the liquid column and significantly compromising the initial drainage results. Furthermore, the large amount of high-pressure gas injected during the closing phase not only wastes the gas source, but also forces the liquid into the low-permeability formation during the closing phase, causing pore blockage and water lock, resulting in irreversible damage to the formation and reducing permeability. Furthermore, the traditional process relies on empirical judgment to determine switching timing, resulting in long response delays, causing large pressure fluctuations, and further impacting production stability. Summary of the Invention

[0005] In view of the above, it is necessary to provide a natural gas forward and reverse gas lift coordinated pressure reduction and production increase process to solve the above problems.

[0006] One embodiment of the present application provides a natural gas forward and reverse gas lift coordinated pressure reduction and production increase process, the process comprising:

[0007] Collect the tubing pressure, annular pressure, and annular liquid level at all sampling points in the gas well at all times; based on the gas density and liquid density, combined with the gas volume flow rate and liquid volume flow rate, obtain the gas-liquid mixed density at each sampling point at each time;

[0008] In the first stage of gas injection, the positive gas lift ratio at each moment in the first stage is determined based on the degree of change in the annular liquid level;

[0009] In the second stage of gas injection, the differential coefficient is obtained based on the discrete degree of the annular pressure at the bottom of the well and the tubing pressure, combined with the discrete changes in the gas-liquid mixture density at all sampling points at each moment. The PID control algorithm is used to adjust the positive gas lift ratio at each moment in the second stage.

[0010] In the third stage of gas injection, the numerical distribution of the annular pressure at the bottom of the well and the tubing pressure are analyzed to obtain the positive gas lift ratio at each moment in the third stage;

[0011] If the positive gas lift ratio at any stage of gas injection decreases to a preset value, reverse gas lift will be used for subsequent natural gas production.

[0012] Among them, the gas-liquid mixture density at each sampling point at each time is obtained, specifically:

[0013] Calculate the product of the gas density and the gas volume flow rate at each sampling point at each moment, and record it as the first product; calculate the product of the liquid density and the liquid volume flow rate at each sampling point at each moment, and record it as the second product;

[0014] The sum of the first product and the second product is recorded as a first sum; the sum of the gas volume flow rate and the liquid volume flow rate at each sampling point at each moment is recorded as a second sum;

[0015] The ratio of the first sum value to the second sum value is used as the gas-liquid mixture density at each sampling point at each moment.

[0016] The first stage of gas injection is specifically a time period corresponding to when the annular liquid level height is greater than or equal to a preset first liquid column threshold.

[0017] The specific formula for determining the positive energy lifting ratio at each moment in the first stage is: Among them, k y,1 Indicates the positive gas lift ratio in the first stage; a indicates the preset maximum gas injection ratio of the tubing; b indicates the preset liquid column adjustment coefficient; H indicates the measured liquid column height; H1 indicates the first liquid column threshold; H max Indicates the initial liquid level height of annular gas injection.

[0018] The second stage of gas injection is specifically a time period corresponding to when the annular liquid level is between a preset first liquid column threshold and a preset second liquid column threshold; wherein the first liquid column threshold is greater than the second liquid column threshold.

[0019] The discrete degree of the annular pressure and the tubing pressure at the bottom of the well is combined with the discrete change of the gas-liquid mixture density at each moment compared with the previous moment to obtain the differential coefficient, including:

[0020] Calculate the ratio of the standard deviation of the gas-liquid mixture density of all sampling points at each moment to the average value, and record it as the first ratio;

[0021] The ratio of the standard deviation of the bottom hole pressure of all sampling points at each moment to the average value is recorded as the second ratio;

[0022] A normalized value of the sum of the first ratio and the second ratio is used as a differential coefficient at each moment.

[0023] The bottom hole pressure is specifically the average of the tubing pressure and the annulus pressure at the lowest sampling point of the gas well.

[0024] The PID control algorithm is used to adjust the positive air lift ratio at each moment in the second stage, specifically:

[0025] For the second stage of gas injection, the PID control algorithm is used to obtain the positive gas lift ratio adjustment value at each moment according to the differential coefficient, and the difference between the positive gas lift ratio at the previous moment and the positive gas lift ratio adjustment value is used as the positive gas lift ratio at each moment.

[0026] The third stage of gas injection is specifically a time period during which the annular liquid level height is less than a preset second liquid column threshold.

[0027] The specific formula for obtaining the positive energy ratio at each moment in the third stage is: Among them, k y,3 represents the proportion of positive energy at each moment in the third stage, k y0,3 represents the initial positive lift ratio of the third stage; P t represents the bottom hole pressure at each moment in the third stage; P max Indicates the maximum bottom hole pressure at all times before each moment.

[0028] This application has at least the following beneficial effects:

[0029] In the first stage of gas injection, the present application mainly determines the positive gas lift ratio at each moment by the change in the annular liquid level. The beneficial effect is that in the initial stage of gas injection, the change in the annular liquid level reflects the pushing effect of the gas, which helps to timely adjust the positive gas lift ratio and ensure effective oil and gas production. In the second stage of gas injection, the gas lift ratio is adjusted mainly by relying on the discrete degree of the bottomhole annular pressure and the tubing pressure, as well as the discrete change in the gas-liquid mixture density. The beneficial effect is that the effect of gas injection is optimized and excessive or insufficient gas injection is avoided. By precisely controlling the positive gas lift ratio, the reduction in production efficiency caused by wellhead pressure fluctuations is avoided, and the flow and production rate of oil and gas are optimized. In the third stage of gas injection, excessive gas injection will cause waste, so it is necessary to determine the optimal gas lift ratio through pressure distribution to avoid resource waste caused by excessive gas injection. The adjustments at each stage in the present application help to reduce bottomhole pressure, avoid waste, improve gas production efficiency and stabilize gas well pressure. The different adjustment methods in the gas injection stage achieve optimal mixing of gas and liquid by precisely controlling the gas lift ratio, thereby maximizing natural gas production efficiency and output. BRIEF DESCRIPTION OF THE DRAWINGS

[0030] Figure 1 A flow chart of a natural gas forward and reverse gas lift coordinated pressure reduction and production increase process provided in this application;

[0031] Figure 2 A schematic diagram of a gas well cross section provided in this application; 1 is the oil pipe, 2 is the annulus, 3 is the casing, and 4 is the liquid level;

[0032] Figure 3 This is a graph showing the changes in the ratio of tubing gas injection and reverse gas lift during the gas injection process provided in this application. DETAILED DESCRIPTION

[0033] In the description of the embodiments of this application, words such as "exemplary," "or," and "for example" are used to indicate examples, illustrations, or descriptions. Any embodiment or design described as "exemplary" or "for example" in the embodiments of this application should not be construed as being preferred or advantageous over other embodiments or designs. Rather, the use of words such as "exemplary," "or," and "for example" is intended to present the relevant concepts in a concrete manner.

[0034] Unless otherwise defined, all technical and scientific terms used herein have the same meaning as those commonly understood by those skilled in the art in the art of this application. The terms used in the specification of this application are only for the purpose of describing specific embodiments and are not intended to limit this application.

[0035] It should also be noted that the terms "first" and "second" in this application and its accompanying drawings are used to distinguish similar objects, rather than to describe a specific order or precedence. The methods disclosed in the embodiments of this application or the methods shown in the flowcharts include one or more steps for implementing the methods. Without departing from the scope of protection of this application, the order of execution of multiple steps can be interchanged with each other, and some steps can also be deleted.

[0036] Unless defined otherwise, all technical and scientific terms used herein have the same meaning as commonly understood by one of ordinary skill in the art to which this application belongs.

[0037] The embodiment of the present application proposes a natural gas positive and negative gas lift coordinated pressure reduction and production increase process, which is applied to the field of natural gas extraction technology. Figure 1 , the process comprises:

[0038] S1: Collect the tubing pressure, annular pressure, and annular liquid level at all sampling points in the gas well at each time; based on the gas density and liquid density, combined with the gas volume flow rate and liquid volume flow rate, obtain the gas-liquid mixed density at each sampling point at each time.

[0039] This application takes into account that in the middle and late stages of gas well production, formation pressure drops, and the natural gas flow rate is insufficient to carry the liquid in the wellbore to the surface. Liquid accumulates at the bottom of the well, forming a liquid column, blocking the gas flow path, causing the gas well to "flood" and stop production. This accumulated liquid increases the bottomhole back pressure, reducing gas production, or even completely stopping production.

[0040] By injecting high-pressure gas into the wellbore, the density of the liquid column and the bottom hole pressure are reduced, a gas-liquid mixed flow is formed, and the accumulated liquid is lifted to the surface, thus restoring the self-flowing ability of the gas well. The injected high-pressure gas mixes with the wellbore liquid to form a low-density gas-liquid two-phase flow, reducing the back pressure of the liquid column on the formation. In the positive lift, high-pressure gas is injected from the oil pipe and the liquid is discharged from the annulus; in the reverse lift, high-pressure gas is injected from the annulus and the liquid is discharged from the oil pipe. The cross-sectional diagram of the gas well is shown as follows: Figure 2 As shown, Figure 2 The liquid level in the tubing is equal to the liquid level in the annulus.

[0041] Distributed fiber optic sensors are deployed longitudinally along the outer wall of the tubing, with virtual sensing points placed every 0.5 m to acquire pressure signals at those locations and monitor the tubing pressure gradient. Distributed fiber optic sensors are also deployed spirally along the inner wall of the casing annulus to monitor the annular pressure gradient and liquid level. In this example, the signal sampling frequency is 10 Hz, with an accuracy of ±0.1 MPa for pressure and ±0.5 m for liquid level.

[0042] The tubing pressure gradient indicates the rate of change in pressure of the gas-liquid mixture within the tubing along the depth of the wellbore. The annular pressure gradient indicates the rate of change in pressure within the annulus between the tubing and casing. The pressure gradient reflects the flow of gas and liquid within the wellbore and is used to determine the location of liquid accumulation and lift efficiency. The liquid level, representing the vertical distance from the top of the liquid accumulation in the annular space within the wellbore to the wellhead, determines the minimum injection pressure required for gas lift.

[0043] The volume flow of gas and liquid is collected separately by V-cone flowmeter, which is deployed at the oil pipe shoe, that is, the connection between the oil pipe and the formation. The sampling frequency is 10Hz and the accuracy is ±1%. The gas-liquid mixed density is calculated by the volume flow. The formula is: Among them, Q q , Q y Represent the volume flow rate of gas and liquid respectively, ρ q , ρ y Represent the density of gas and liquid respectively. In this embodiment, the gas is natural gas and the liquid is a mixture of formation water and condensate oil. The collected gas-liquid mixture density is used to measure the liquid carrying capacity of the gas-liquid mixture. The lower the density, the easier it is to lift. q ×ρ q Denote it as the first product; y ×ρ y Denote as the second product; Q q ×ρ q +Q y ×ρ y Recorded as the first sum value; Q q +Q y Recorded as the second sum.

[0044] S2: In the first stage of gas injection, the positive gas lift ratio at each moment in the first stage is determined based on the degree of change in the annular liquid level.

[0045] In the early stages of gas injection, the liquid level in the wellbore is typically high, the gas-liquid mixture density is high, and the bottomhole pressure exceeds the normal production pressure range of the gas well. Therefore, a coordinated gas injection method of forward and reverse gas lift is used, injecting gas simultaneously into the tubing and annulus to rapidly reduce the liquid column.

[0046] At this time, tubing gas injection is the primary method. Because gas is injected through the tubing, the wellbore liquid column is directly displaced. Due to the smaller cross-sectional area of ​​the tubing, the liquid column descends more rapidly, allowing the liquid level to drop rapidly in the initial stages. During tubing gas injection, the gas directly pushes the liquid column upward within the tubing, preventing the sudden release of annular liquid back pressure on the formation, thereby reducing the risk of water channeling or sand production. During annular gas injection, it mixes with the accumulated liquid at the bottom of the well, forming a low-density slug flow that can easily cause formation pressure fluctuations.

[0047] Although gas injection in the tubing is dominant, gas injection in the annulus is still required to accelerate the reduction of the liquid column. On the other hand, when gas is injected into the tubing, the slippage effect of the gas-liquid two-phase flow may cause a decrease in lifting efficiency. At the same time, gas injection prevents gas-liquid stratification and avoids casing damage caused by excessive pressure difference between the annulus and the tubing.

[0048] Therefore, in order to quickly reduce the liquid column in the early stage of gas injection, the gas injection ratio is adjusted according to the height of the liquid column. The formula is: where k y,1 represents the positive gas lift ratio in the first stage; a represents the maximum gas injection ratio of the tubing, which can be fitted based on historical data. In this embodiment, the value is 0.7; b represents the liquid column adjustment coefficient, which is used to control the speed of gas injection ratio adjustment. The larger the value, the faster the adjustment. The range is (0, 1). In this embodiment, the value is 0.2; H represents the measured liquid column height; H1 represents the first liquid column threshold, which is used to switch the gas injection ratio control method, that is, when the liquid column height is less than H1, the gas injection ratio adjustment method is switched. The value of H1 is between 30% and 40% of the initial liquid column height. In this embodiment, the value is 1000m; H max Indicates the initial liquid level height of annular gas injection.

[0049] It should be noted that the sum of the positive air lift ratio and the negative air lift ratio at each stage and at each moment is equal to 1, that is, the negative air lift ratio is k h =1-k y .

[0050] S3: In the second stage of gas injection, based on the discrete degree of the annular pressure at the bottom of the well and the tubing pressure, combined with the discrete changes in the gas-liquid mixture density at all sampling points at each moment, the differential coefficient is obtained, and the PID control algorithm is used to adjust the positive gas lift ratio at each moment in the second stage.

[0051] After the liquid column drops rapidly, that is, when the liquid column height is less than the first liquid column threshold, if the gas injection ratio is continued to be adjusted linearly, although the liquid column is reduced, the gas-liquid mixture density at this time fluctuates violently, which easily forms slug flow and leads to low gas production efficiency of the gas well.

[0052] Slugging occurs when a bubbly mixture continues to flow upward in a vertical pipe. As the pressure gradually decreases, the gas expands, the gas holdup increases, and small bubbles collide and coalesce to form larger bubbles with diameters approaching the pipe diameter. When the bubbles occupy most of the pipe's cross-section, a flow structure with liquid and gas segments forms. This occurs when a low gas-liquid velocity ratio creates gas-liquid stratification within the wellbore, leading to intermittent slugging and reduced liquid-carrying efficiency.

[0053] The goal of adjusting the gas injection ratio at this point is to maintain the gas-liquid mixture density at a critical value while ensuring the liquid column descends, thereby improving liquid-carrying efficiency. PID control is suitable for this purpose, allowing rapid adjustment of the gas injection ratio based on real-time fluctuations in the gas-liquid two-phase flow density. This is because the proportional term in the PID algorithm directly responds to current errors, the integral term corrects gas-liquid ratio deviations by accumulating errors, and the differential term predicts changing trends to proactively intervene in liquid column rebound or gas crossflow. This makes gas injection ratio adjustments more realistic.

[0054] The main goal of this stage is to maintain a stable gas-liquid ratio and avoid slugging. The differential coefficient of the PID can be adapted based on the changes in the gas-liquid mixture density and the bottom hole pressure. This is because it can suppress sudden changes based on fluctuations and avoid under-adjustment or overshoot. The calculation formula for the differential coefficient is: Among them, K d Represents the differential coefficient; norm() represents the normalization function; , ρ h,avg Respectively represent the standard deviation and average value of all gas-liquid mixture densities at each moment; σ P 、P avg Represent the standard deviation and average value of bottom hole pressure at each moment. The bottom hole pressure refers to the average value of tubing pressure and annulus pressure at the lowest virtual sensing point collected by the sensor. Recorded as the first ratio; Recorded as the second ratio.

[0055] It should be understood that the differential coefficient can be adaptively adjusted according to the changes in the gas-liquid mixture density environment in the wellbore. The larger the differential coefficient, the greater the fluctuation of the gas-liquid mixture density at the bottom of the well, and the greater the fluctuation of the bottom hole pressure, the easier it is to cause slugging flow. In this case, the differential coefficient in the PID should be increased, and the fluctuation can be suppressed by adjusting the gas injection ratio, thereby improving the gas production efficiency while adjusting the gas injection ratio.

[0056] According to the adaptive differential coefficient, the PID control algorithm is used to obtain the adjustment value Δk of the gas injection ratio of the second stage oil pipe at each moment compared with the previous moment. y,2 , to adjust the gas injection ratio. In this embodiment, the proportional coefficient K of the PID control algorithm p The value is 0.2, the integral coefficient K i The value is 0.5, ρ h represents the collected gas-liquid mixture density, ρ0 represents the critical density, which is 250 kg / m 3 , determined by the Turner model. PID control algorithm is a well-known technology and will not be described in detail in this application.

[0057] S4: In the third stage of gas injection, the numerical distribution of the annular pressure at the bottom of the well and the tubing pressure is analyzed to obtain the positive gas lift ratio at each moment in the third stage.

[0058] When the liquid column drops to the preset second liquid column threshold H2, the liquid accumulation in the wellbore is significantly improved. At this point, the liquid column height is at a low and stable level, and the gas-liquid mixture density is maintained near the critical density. This indicates that the gas-liquid mixture flow has good liquid-carrying capacity, ensuring normal gas production in the gas well. The gas-liquid mixture density no longer fluctuates violently, so PID-based gas injection ratio adjustment is no longer applicable. The value of H2 is 10% to 20% of H1. In this embodiment, the second liquid column threshold H2 is 100m.

[0059] However, as production continues, formation energy gradually depletes. To maintain stable production and improve production efficiency, the gas injection ratio still needs to be adjusted according to actual conditions. In particular, when it is found that the effect of positive lift (tubing gas injection) is gradually weakening, and reverse lift (annular gas injection) can more effectively utilize the remaining formation energy and maintain stable production of the gas well, it is necessary to gradually reduce the positive gas lift ratio to a certain level and then fully adopt reverse lift for production.

[0060] Since bottom hole pressure is related to formation capacity, the third stage of this application considers adjustment based on bottom hole pressure. The formula is: Among them, k y,3 represents the proportion of positive energy at each moment in the third stage, k y0,3 represents the initial positive air lift ratio of the third stage, that is, the positive air lift ratio at the last moment of the second stage; P t represents the bottom hole pressure at each moment in the third stage; P max Indicates the maximum bottom hole pressure at all times before each moment; the bottom hole pressure refers to the average value of the tubing pressure and annulus pressure at the lowest virtual sensing point collected by the sensor.

[0061] It should be noted that the bottomhole pressure does not necessarily decrease as gas production progresses, because the combined pressure gas injection presses the liquid in the wellbore into the bottom layer. As the positive gas lift ratio continues to decrease, the liquid will flow back, causing the bottomhole pressure to fluctuate. Therefore, the gas injection ratio adjustment of the oil pipe at this stage will also fluctuate, that is, the slope of the positive gas lift ratio curve will fluctuate instead of constantly decreasing.

[0062] S5: If the positive gas lift ratio at any stage of gas injection decreases to a preset value, reverse gas lift will be used for subsequent natural gas production.

[0063] In this embodiment, the preset value is 0.05.

[0064] In order to verify the validity of this application, several comparative examples are set, specifically:

[0065] Comparative Example 1: The gas injection pressure is 25 MPa, and the gas injection ratio is not adjusted during the gas lift process.

[0066] Comparative Example 2: The gas injection pressure is 18 MPa, and the gas injection ratio is not adjusted during the gas lift process.

[0067] Comparative Example 3: The gas injection pressure is 12 MPa, and the gas injection ratio is not adjusted during the gas lift process.

[0068] Except for the explanation, the process flow and parameters of Comparative Examples 1, 2 and 3 are consistent with those of this embodiment.

[0069] The comparison between the traditional pressing process and this embodiment is shown in the following table:

[0070]

[0071] As shown in the table, lowering the gas source pressure under the traditional combined-pressure process can reduce the amount of gas injected, but the liquid column height increases significantly, leading to a decrease in natural gas production. However, using a coordinated process of forward and reverse gas lift during the injection process, injecting gas into both the tubing and the annulus simultaneously while controlling the injection ratio, using the method described in Example 1, can rapidly reduce the liquid column and restore production.

[0072] And the effectiveness of the gas injection ratio control of this scheme is verified by the change diagram of the ratio of gas injection and reverse gas lift in the gas injection process of the embodiment, as shown in the following example. Figure 3 As shown. Figure 3 It can be seen that as the gas injection continues, the gas injection ratio is adjusted in real time, the positive gas lift ratio continues to decrease, the reverse gas lift ratio continues to increase, and the sum is 1, thus achieving the purpose of synergistic pressure reduction and production increase by positive and reverse gas lift.

[0073] The flowcharts and block diagrams in the accompanying drawings show the possible architecture, functions and operations of the systems, methods and computer program products according to the embodiments of the present application. In this regard, each box in the flowchart or block diagram can represent a module, a program segment or a part of the code, and the part of the module, program segment or code contains one or more executable instructions for realizing the specified logical function. In some alternative implementations, the functions marked in the box can also occur in an order different from that marked in the accompanying drawings. For example, two consecutive boxes can actually be executed substantially in parallel, and they can sometimes be executed in the opposite order, which can depend on the functions involved. In the description corresponding to the flowcharts and block diagrams in the accompanying drawings, the operations or steps corresponding to different boxes can also occur in an order different from that disclosed in the description, and sometimes there is no specific order between different operations or steps. For example, two consecutive operations or steps can actually be executed substantially in parallel, and they can sometimes be executed in the opposite order, which can depend on the functions involved. Each block in the block diagrams and / or flowcharts, and combinations of blocks in the block diagrams and / or flowcharts, may be implemented by a dedicated hardware-based system that performs the specified function or action, or may be implemented by a combination of dedicated hardware and computer instructions.

[0074] The above embodiments are only used to illustrate the technical solutions of the present application, rather than to limit them. Although the present application has been described in detail with reference to the aforementioned embodiments, those skilled in the art should understand that they can still modify the technical solutions described in the aforementioned embodiments, or make equivalent replacements for some of the technical features therein. These modifications or replacements do not deviate the essence of the corresponding technical solutions from the scope of the technical solutions of the embodiments of the present application, and should all be included in the scope of protection of the present application.

Claims

1. A natural gas forward and reverse gas lift coordinated pressure reduction and production increase process, characterized in that: The process includes: Collect the tubing pressure, annular pressure, and annular liquid level at all sampling points in the gas well at all times; based on the gas density and liquid density, combined with the gas volume flow rate and liquid volume flow rate, obtain the gas-liquid mixed density at each sampling point at each time; In the first stage of gas injection, the positive gas lift ratio at each moment of the first stage is determined based on the degree of change in the annular liquid level. The first stage of gas injection is specifically the time period corresponding to the annular liquid level being greater than or equal to a preset first liquid column threshold. The specific formula for determining the positive gas lift ratio at each moment of the first stage is: ,in, Indicates the positive gas lift ratio in the first stage; a indicates the preset maximum gas injection ratio in the tubing; b indicates the preset liquid column adjustment coefficient; H indicates the measured liquid column height; Indicates the first liquid column threshold; Indicates the initial liquid level height of annular gas injection; In the second stage of gas injection, the differential coefficient is obtained based on the discrete degree of the annular pressure at the bottom of the well and the tubing pressure, combined with the discrete changes in the gas-liquid mixture density at all sampling points at each moment, and the positive gas lift ratio at each moment of the second stage is adjusted using a PID control algorithm. The second stage of gas injection specifically corresponds to the time period corresponding to the annular liquid level height being between a preset first liquid column threshold and a preset second liquid column threshold, wherein the first liquid column threshold is greater than the second liquid column threshold. In the third stage of gas injection, the numerical distribution of the annular pressure and the tubing pressure at the bottom of the well is analyzed to obtain the positive gas lift ratio at each moment of the third stage. The third stage of gas injection is specifically the time period corresponding to the annular liquid level being less than the preset second liquid column threshold. The specific formula for obtaining the positive gas lift ratio at each moment of the third stage is: ,in, Indicates the proportion of positive energy at each moment in the third stage, represents the initial positive qi lift ratio in the third stage; represents the bottom hole pressure at each moment in the third stage; Indicates the maximum bottom hole pressure at all times before each moment; If the positive gas lift ratio at any stage of gas injection decreases to a preset value, reverse gas lift will be used for subsequent natural gas production.

2. A natural gas forward and reverse gas lift coordinated pressure reduction and production increase process according to claim 1, characterized in that: The gas-liquid mixture density at each sampling point at each time is obtained, specifically: Calculate the product of the gas density and the gas volume flow rate at each sampling point at each moment, and record it as the first product; calculate the product of the liquid density and the liquid volume flow rate at each sampling point at each moment, and record it as the second product; The sum of the first product and the second product is recorded as a first sum; the sum of the gas volume flow rate and the liquid volume flow rate at each sampling point at each moment is recorded as a second sum; The ratio of the first sum value to the second sum value is used as the gas-liquid mixture density at each sampling point at each moment.

3. The natural gas forward and reverse gas lift coordinated pressure reduction and production increase process according to claim 1, characterized in that: The discrete degree of the annular pressure and the tubing pressure at the bottom of the well is combined with the discrete change of the gas-liquid mixture density at each moment compared with the previous moment to obtain the differential coefficient, including: Calculate the ratio of the standard deviation of the gas-liquid mixture density of all sampling points at each moment to the average value, and record it as the first ratio; The ratio of the standard deviation of the bottom hole pressure of all sampling points at each moment to the average value is recorded as the second ratio; A normalized value of the sum of the first ratio and the second ratio is used as a differential coefficient at each moment.

4. A natural gas forward and reverse gas lift coordinated pressure reduction and production increase process according to claim 3, characterized in that: The bottom hole pressure is specifically the average of the tubing pressure and the annulus pressure at the lowest sampling point of the gas well.

5. The natural gas forward and reverse gas lift coordinated pressure reduction and production increase process according to claim 1, characterized in that: The PID control algorithm is used to adjust the positive air lift ratio at each moment in the second stage, specifically: For the second stage of gas injection, the PID control algorithm is used to obtain the positive gas lift ratio adjustment value at each moment according to the differential coefficient, and the difference between the positive gas lift ratio at the previous moment and the positive gas lift ratio adjustment value is used as the positive gas lift ratio at each moment.

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