Positive and negative gas lift synergistic pressure reduction and yield increase process for natural gas

Abstract

The invention relates to the technical field of natural gas extraction, in particular to a natural gas positive and negative gas lift synergistic pressure reduction and yield increase process which comprises the steps that gas injection stages are divided based on the numerical range of the annulus liquid level height, and the positive gas lift proportion is adjusted, confirming the positive gas lift proportion of each moment in the first stage; in the second stage, on the basis of the dispersion degree of the annular pressure of the well bottom and the oil pipe pressure, discrete changes of the gas-liquid mixing density of all the sampling points at all the moments are combined, a differential coefficient is obtained, and the positive gas lift proportion at all the moments of the second stage is adjusted; in the third stage, the numerical distribution of the annular pressure and the oil pipe pressure at the well bottom is analyzed, and the positive gas lift proportion at each moment in the third stage is obtained; and if the positive gas lift proportion of any stage of gas injection is reduced to a preset value, adopting reverse gas lift to exploit natural gas subsequently. The invention aims to improve the gas production efficiency and stabilize the gas well pressure.

Description

Technical Field

[0001] The present application relates to the technical field of natural gas extraction, and in particular to a natural gas positive and negative gas lift coordinated pressure reduction and production increase process. Background Art

[0002] In the field of natural gas extraction, the extraction of high liquid column, low pressure and low permeability gas fields faces many challenges. These geological conditions make it extremely difficult for natural gas to flow underground, and the extraction efficiency is greatly restricted. During the extraction process, the formation energy is insufficient, which makes it difficult to discharge the accumulated liquid in the wellbore (mainly a mixture of formation water and condensate oil), which gradually accumulates to form a high liquid column, thereby blocking the gas flow channel, and finally causing the gas well to stop blowing, seriously affecting the production capacity and economic benefits of the gas field.

[0003] In the document "Study on Gas Lift Method of Natural Gas Compressor in Sulige Gas Field", Changqing Sulige Gas Field was taken as an example. When the height of the wellbore liquid column was greater than 2500m, both positive and negative gas lift could not induce blowout and discharge liquid. Therefore, a combined pressure reduction and liquid gas lift recovery process was proposed. Under the condition of the maximum exhaust pressure of the natural gas compressor of 25MPa, by introducing a high-pressure gas source, gas injection and combined pressure were implemented on the construction well tubing and casing annulus, part of the accumulated liquid was temporarily pressed back into the formation, and then the gas well was gas lifted according to the conventional method.

[0004] However, this staged operation has a significant switching gap, which causes the formation pressure to rise after the pressure-closing stage, causing the liquid column to rebound, which greatly reduces the results of the previous drainage. At the same time, the injection of a large amount of high-pressure gas not only causes a serious waste of gas sources, but also forces the liquid into the low-permeability formation during the pressure-closing stage, which will cause pore blockage and water lock effect, causing irreversible damage to the formation and reducing the formation permeability. In addition, the traditional process relies on experience to judge the switching timing, with a long response delay, causing large pressure fluctuations, further affecting the stability of mining. Summary of the invention

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

[0006] An embodiment of the present application provides a natural gas positive and negative 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 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;

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

[0009] 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 of the gas-liquid mixed density at all sampling points at each moment, the differential coefficient is obtained, and the positive gas lift ratio at each moment in the second stage is adjusted using the PID control algorithm;

[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 is reduced to a preset value, reverse gas lift will be used for subsequent natural gas production.

[0012] Among them, the gas-liquid mixed 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 time, 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 time, 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 time is recorded as a second sum;

[0015] The ratio of the first sum value to the second sum value is used to obtain the gas-liquid mixed density at each sampling point at each time.

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

[0017] The specific formula for confirming the positive energy lifting ratio at each moment in the first stage is: Among them, k y,1 represents the positive gas lift ratio in the first stage; a represents the preset maximum gas injection ratio of the tubing; b represents the preset liquid column adjustment coefficient; H represents the measured liquid column height; H1 represents the first liquid column threshold; H max Indicates the initial liquid level height of annulus 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 and 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 lifting ratio at each moment in the third stage is: Among them, k y,3 represents the positive energy ratio at each moment in the third stage, k y0,3 represents the initial positive air lift ratio in 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 confirms the positive gas lift ratio at each moment by the change of the annular liquid level height, and its beneficial effect is that in the initial stage of gas injection, the change of the annular liquid level reflects the driving effect of the gas, which helps to adjust the positive gas lift ratio in time and ensure the effective lifting and recovery of oil and gas; in the second stage of gas injection, the gas lift ratio is adjusted mainly by the discrete degree of the bottom hole annular pressure and the tubing pressure, and the discrete change of the gas-liquid mixed density, and its beneficial effect is to optimize the effect of gas injection and avoid excessive or insufficient gas injection. By accurately controlling the positive gas lift ratio, the reduction in recovery efficiency caused by wellhead pressure fluctuations is avoided, and the flow and recovery 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 confirm the optimal gas lift ratio through pressure distribution to avoid waste of resources caused by excessive gas injection; the adjustment at each stage in the present application helps to reduce bottom hole pressure, avoid waste, improve gas recovery efficiency and stabilize gas well pressure; different adjustment methods in the gas injection stage achieve the optimal mixing of gas and liquid by accurately controlling the gas lift ratio, thereby maximizing the recovery efficiency and output of natural gas. BRIEF DESCRIPTION OF THE DRAWINGS

[0030] Figure 1 A flow chart of a natural gas positive and negative 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; wherein 1 is the oil pipe, 2 is the annulus, 3 is the casing, and 4 is the liquid surface;

[0032] Figure 3 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 the present application, words such as "exemplary", "or", "for example" and the like are used to indicate examples, illustrations or descriptions. Any embodiment or design described as "exemplary" or "for example" in the embodiments of the present application should not be interpreted as being more preferred or more advantageous than other embodiments or designs. Specifically, the use of words such as "exemplary", "or", "for example" and the like is intended to present related 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 present application. The terms used in the specification of the present application are only for the purpose of describing specific embodiments and are not intended to limit the present application.

[0035] It should also be noted that the terms "first" and "second" in this application and its drawings are used to distinguish similar objects, rather than to describe a specific order or sequence. The method disclosed in the embodiments of the present application or the method shown in the flow chart includes one or more steps for implementing the method. Without departing from the scope of protection of this application, the execution order 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 present application embodiment 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, the formation pressure drops, and the natural gas flow rate is insufficient to carry the liquid in the wellbore to the surface. The liquid accumulates at the bottom of the well to form a liquid column, blocking the gas flow channel, causing the gas well to be "flooded" and shut down. The accumulation of liquid increases the bottom-hole back pressure, reduces gas production, and even completely shuts down 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 ground, 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 schematic diagram of the gas well is shown in FIG. Figure 2 As shown, Figure 2 The liquid level in the tubing is equal to the liquid level in the annulus.

[0041] The pressure gradient and liquid level in the wellbore are collected by distributed optical fiber sensors. The deployment method is that the outer wall of the oil pipe is laid along the longitudinal direction of the oil pipe, and a virtual sensor point is arranged every 0.5m to obtain the pressure signal at this position and monitor the pressure gradient of the oil pipe; the inner wall of the annulus is laid spirally along the casing annulus to monitor the annulus pressure gradient and the annulus liquid level. In this embodiment, the sampling frequency of the signal is 10Hz, and the accuracy is ±0.1MPa for pressure and ±0.5m for liquid level.

[0042] The tubing pressure gradient indicates the pressure change rate of the gas and liquid mixed flow in the tubing along the well depth, and the annular pressure gradient indicates the pressure change rate of the fluid in the tubing and casing annulus. The function of the pressure gradient is to reflect the gas-liquid flow state in the wellbore and is used to determine the location of the liquid accumulation and the lifting efficiency. The liquid level indicates the vertical distance from the top boundary of the liquid accumulation in the annular part of the wellbore to the wellhead, which can determine the minimum gas injection pressure required for gas lift.

[0043] The volume flow of gas and liquid is collected 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, the accuracy is ±1%, and the gas-liquid mixed density is calculated by the volume flow. The formula is: Among them, Q q , Q y Respectively represent the volume flow rate of gas and liquid, ρ q , y 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 Record it as the first product; Q y ×ρ y Record it as the second product; Q q ×ρ q +Q y ×ρ y Recorded as the first sum; Q q +Q y Recorded as the second sum.

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

[0045] In the early stage of gas injection, the liquid level in the wellbore is usually high, the gas-liquid mixture density is large, and the bottom hole pressure exceeds the normal production pressure range of the gas well. Therefore, a gas injection method with positive and negative gas lift coordination is adopted to inject gas into the tubing and annulus at the same time to quickly reduce the liquid column.

[0046] At this time, the main method is to inject gas through the tubing. Because the gas is injected from the tubing, the wellbore liquid column is directly displaced. Due to the small cross-sectional area of ​​the tubing, the liquid column drops faster, and the liquid level can be quickly reduced in the initial stage. When injecting gas through the tubing, the gas directly pushes the liquid column in the tubing up, avoiding the sudden release of the annular liquid back pressure to the formation, thereby reducing the risk of water channeling or sand production. When injecting gas into the annulus, it mixes with the accumulated liquid at the bottom of the well to form a low-density slug flow, which is easy to cause formation pressure fluctuations.

[0047] Although gas injection in the tubing is dominant, gas injection in the annulus is still required to speed up 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 Indicates the positive gas lift ratio in the first stage; a indicates the maximum gas injection ratio of the tubing, which can be fitted according to historical data. The value in this embodiment is 0.7; b indicates the liquid column adjustment coefficient, which is used to control the speed of adjusting the gas injection ratio. The larger the value, the faster the adjustment. The range is (0,1). The value in this embodiment is 0.2; H indicates the measured liquid column height; H1 indicates 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 annulus 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 of the gas-liquid mixed density at all sampling points at each moment, the differential coefficient is obtained, and the positive gas lift ratio at each moment in the second stage is adjusted using the PID control algorithm.

[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 continues to be adjusted linearly, although the liquid column is reduced, the gas-liquid mixed density fluctuates violently at this time, which easily forms slug flow and leads to low gas production efficiency of the gas well.

[0052] Slug flow refers to the situation in a vertical pipe where, as the bubble flow mixture continues to flow upward, the pressure gradually decreases, the gas continues to expand, the gas content increases, and small bubbles collide and aggregate to form large bubbles with a diameter close to the pipe diameter. When the bubbles occupy most of the pipe cross-section, a flow structure of one section of liquid and one section of gas is formed. The reason for this is that when the gas-liquid flow rate ratio is too small, the gas-liquid stratification in the wellbore causes intermittent slug flow, which will cause a decrease in liquid carrying efficiency.

[0053] At this time, the purpose of adjusting the gas injection ratio is to maintain the gas-liquid mixed density at a critical value while ensuring the liquid column drops, thereby improving the liquid carrying efficiency. It is suitable to use the PID algorithm for control, and quickly adjust the gas injection ratio according to the real-time fluctuation requirements of the gas-liquid two-phase flow density. Because in the PID algorithm, the proportional term can directly respond to the current error, the integral term can correct the gas-liquid ratio offset through the accumulated error, and the differential term can intervene in the liquid column rebound or gas channeling in advance by predicting the change trend, making the gas injection ratio adjustment more in line with the actual situation.

[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 adaptively adjusted based on the changes in the gas-liquid mixed density and the bottom hole pressure, because it can suppress sudden changes based on fluctuations to avoid under-adjustment or over-adjustment. 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 Respectively represent the standard deviation and average value of the bottom hole pressure at 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. 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 slug flow, and the larger the differential coefficient in the PID should be, the more the fluctuation can be suppressed by adjusting the gas injection ratio, thereby improving the gas production efficiency when 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, h represents the collected gas-liquid mixed density, ρ0 represents the critical density, and the value in this embodiment is 250kg / m 3 , determined by the Turner model. The PID control algorithm is a well-known technology, which 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 time, the liquid column height is at a relatively low and stable level, and the gas-liquid mixture density is also maintained near the critical density, which indicates that the gas-liquid mixed flow has a good liquid carrying capacity and can ensure the normal gas production of the gas well. The gas-liquid mixture density no longer fluctuates violently, so the 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 the exploitation continues, the formation energy is gradually consumed. In order to maintain the stable production of the gas well and improve the exploitation efficiency, the gas injection ratio still needs to be adjusted according to the actual situation. In particular, when it is found that the effect of positive lift (tubing gas injection) is gradually weakening, and reverse lift (annulus gas injection) can more effectively utilize the remaining energy of the formation and maintain the stable production of the gas well, it is necessary to gradually reduce the positive gas lift ratio to a certain extent and completely adopt reverse lift for production.

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

[0061] It should be noted that the bottom hole 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 bottom hole 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 is reduced 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, a number of 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 conventional pressing process and this embodiment is shown in the following table:

[0070]

[0071] From the comparison in the table, it can be seen that under the traditional combined pressure process, if the gas source pressure is reduced, the injection amount can be reduced, but the liquid column height will increase significantly and the natural gas production will decrease. If the positive and negative gas lift synergistic process is used during the gas injection process, the oil pipe and the annulus are injected with gas at the same time, and the gas injection ratio is controlled, when the method in Example 1 is used, the liquid column can be quickly reduced to achieve lifting and resumption of production.

[0072] And the effectiveness of the gas injection ratio control of the 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 figure: 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 flowchart and block diagram in the accompanying drawings show the possible architecture, function and operation of the system, method and computer program product according to the embodiment 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 module, the program segment or a part of the code contains one or more executable instructions for realizing the specified logical function. In some alternative implementations, the function marked in the box can also occur in a different order from the order marked in the accompanying drawings. For example, two continuous 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 flowchart and the block diagram in the accompanying drawings, the operations or steps corresponding to different boxes can also occur in a different order from the order disclosed in the description, and sometimes there is no specific order between different operations or steps. For example, two continuous 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 functions or actions, 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 protection scope of the present application.

Claims

1. A natural gas positive and negative 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 each moment; obtain the gas-liquid mixed density at each sampling point at each moment based on the gas density and liquid density, combined with the gas volume flow rate and the liquid volume flow rate; in the first stage of gas injection, confirm the positive gas lift ratio at each moment in the first stage based on the degree of change of the annular liquid level; in the second stage of gas injection, obtain the differential coefficient based on the discrete degree of the annular pressure at the bottom of the well and the tubing pressure, combined with the discrete changes of the gas-liquid mixed density at all sampling points at each moment, and use the PID control algorithm to adjust the positive gas lift ratio at each moment in the second stage; 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; If the positive gas lift ratio at any stage of gas injection is reduced to a preset value, reverse gas lift will be used for subsequent natural gas production.

2. A natural gas positive and negative gas lift coordinated pressure reduction and production increase process as claimed in claim 1, characterized in that: The gas-liquid mixed 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 time, 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 time, 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 time is recorded as a second sum; The ratio of the first sum value to the second sum value is used to obtain the gas-liquid mixed density at each sampling point at each time.

3. A natural gas positive and negative gas lift coordinated pressure reduction and production increase process as claimed in claim 1, characterized in that: 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.

4. A natural gas positive and negative gas lift coordinated pressure reduction and production increase process as claimed in claim 1, characterized in that: The specific formula for confirming the positive air lift ratio at each moment in the first stage is: Among them, k y,1 represents the positive gas lift ratio in the first stage; a represents the preset maximum gas injection ratio of the tubing; b represents the preset liquid column adjustment coefficient; H represents the measured liquid column height; H1 represents the first liquid column threshold; H max Indicates the initial liquid level height of annulus gas injection.

5. A natural gas positive and negative gas lift coordinated pressure reduction and production increase process as claimed in claim 2, characterized in that: 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.

6. A natural gas positive and negative gas lift coordinated pressure reduction and production increase process as claimed in 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 mixed density at each moment and the previous moment to obtain the differential coefficient, including: Calculate the ratio of the standard deviation of the gas-liquid mixed density of all sampling points at each moment to the average value, which is recorded as the first ratio; calculate the ratio of the standard deviation of the bottom hole pressure of all sampling points at each moment to the average value, which is recorded as the second ratio; and use the normalized value of the sum of the first ratio and the second ratio as the differential coefficient at each moment.

7. A natural gas positive and negative gas lift coordinated pressure reduction and production increase process as claimed in claim 6, 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.

8. A natural gas positive and negative gas lift coordinated pressure reduction and production increase process as claimed in 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.

9. A natural gas positive and negative gas lift coordinated pressure reduction and production increase process as claimed in claim 5, characterized in that: The third stage of gas injection is specifically a time period corresponding to when the annular liquid level height is less than a preset second liquid column threshold.

10. A natural gas positive and negative gas lift coordinated pressure reduction and production increase process as claimed in claim 1, characterized in that: The specific formula for obtaining the positive energy lifting ratio at each moment in the third stage is: Among them, k y,3 represents the positive energy ratio at each moment in the third stage, k y0,3 represents the initial positive air lift ratio in 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.

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