A method for evaluating real-time plug flow liquid carrying performance in a natural gas well and related devices

Abstract

The application belongs to the technical field of oil and natural gas liquid discharge gas recovery, and aims at the technical problem that the liquid carrying capacity and dynamic change of a gas well in a non-fully liquid carrying state are lack of effective attention when a critical liquid carrying criterion method is used to monitor liquid carrying and diagnose liquid accumulation of the gas well, and proposes a real-time evaluation method for slug flow liquid carrying performance in a natural gas well and related devices. Based on real-time multiphase flow parameters, the liquid carrying state of the gas well is determined by using a flooding mechanism. If the gas well is in a fully liquid carrying state, the liquid carrying efficiency of the gas well is directly determined. If the gas well is in a non-fully liquid carrying state, the time and space average liquid carrying flow of the slug flow and the time and space average liquid accumulation flow of the slug flow are calculated based on the time and space inhomogeneity characteristics of the slug flow, and then the liquid carrying efficiency of the gas well in the non-fully liquid carrying state is calculated. The application can accurately evaluate and monitor the actual liquid carrying performance of the gas well under different multiphase flow parameters in real time, and breaks through the limitation of the traditional critical criterion which only distinguishes the liquid carrying state.

Description

Technical Field

[0001] This application belongs to the field of oil and gas drainage and gas production technology, specifically involving a method and related device for real-time evaluation of the liquid-carrying performance of slug flow in natural gas wells. Background Technology

[0002] In natural gas extraction, formation water production within the wellbore is a key factor affecting production stability. When the well is in a low water-cut stage or during the early stages of production with high gas yields, natural gas can carry liquid to the wellhead using its own kinetic energy, maintaining normal production. However, as the water cut increases or production declines in the later stages, the produced liquid cannot be fully carried by the gas flow, leading to liquid accumulation within the wellbore. This accumulation significantly hinders natural gas flow, causing reduced production and, in severe cases, water flooding and well closure. Therefore, accurately assessing the well's self-carrying capacity under different water cut conditions and at any production stage, monitoring the natural gas liquid-carrying status and accumulation within the wellbore in real time, and implementing targeted optimization measures based on this information are crucial for ensuring stable natural gas production.

[0003] Chinese invention patent CN113468826A discloses a method for predicting the critical fluid-carrying flow rate of shale gas horizontal wells based on the actual liquid film distribution, and provides a prediction model for the critical fluid-carrying flow rate of inclined pipes based on the actual liquid film shape distribution; Chinese invention patent CN113343607A discloses a method for calculating the critical fluid-carrying gas flow velocity based on the fluid film motion law of the pipe wall, and derives a critical fluid-carrying gas flow velocity model based on the liquid film force balance analysis; Chinese invention patent application CN116933687A discloses a method, system and equipment for tracking the critical fluid-carrying flow velocity and determining the liquid accumulation throughout the entire life cycle of a gas well with full well inclination, and comprehensively considers the phase inhomogeneity on a spatial scale to establish a method for predicting the critical fluid-carrying flow velocity throughout the entire life cycle of a gas well with full well inclination. However, existing technologies for monitoring and diagnosing liquid carrying capacity in gas wells primarily employ a critical liquid carrying criterion method. This method uses whether the gas production rate or gas phase flow rate reaches a critical value as the judgment standard: when the critical value is reached, the gas well is considered to be in a fully liquid-carrying state, with no liquid accumulation in the wellbore; when it is below the critical value, it is determined to be in a partially liquid-carrying state, with liquid accumulation in the wellbore. However, this method still has technical limitations, as it uses only the critical liquid-carrying flow rate or flow rate as a single criterion to define the conditions for fully liquid carrying capacity, lacking effective attention and quantitative assessment of the liquid carrying capacity and dynamic changes in the partially liquid-carrying state. Summary of the Invention

[0004] This application addresses the technical problem that current methods for monitoring and diagnosing liquid accumulation in gas wells using critical liquid-carrying criteria lack effective attention to the liquid-carrying capacity and dynamic changes under incomplete liquid-carrying conditions. It proposes a real-time evaluation method and related device for the liquid-carrying performance of slug flow in natural gas wells.

[0005] To achieve the above objectives, this application adopts the following technical solution:

[0006] Firstly, this application provides a method for real-time evaluation of the fluid-carrying capacity of slug flow in a natural gas well, comprising:

[0007] Obtain real-time multiphase flow parameters of gas wells;

[0008] Based on real-time multiphase flow parameters, the flooding mechanism is used to determine the liquid-carrying state of the gas well. If the critical condition for flooding is met, the gas well is in a fully liquid-carrying state; otherwise, the gas well is in a partially liquid-carrying state.

[0009] If the gas well is in a fully liquid-carrying state, the liquid-carrying efficiency of the gas well is 1; if the gas well is in a partially liquid-carrying state, the spatiotemporal average liquid-carrying flow rate and the spatiotemporal average liquid accumulation flow rate of the slug flow are calculated based on the rising liquid plug and falling liquid film of the slug flow, as well as the spatiotemporal non-uniformity characteristics of the rising liquid plug and falling liquid film of the slug flow.

[0010] Based on the spatiotemporal average liquid carrying capacity and the spatiotemporal average liquid accumulation capacity of the slug flow, the liquid carrying efficiency of the gas well under incomplete liquid carrying conditions is calculated.

[0011] Furthermore, the real-time multiphase flow parameters include gas apparent velocity, liquid apparent velocity, wellbore inner diameter, gas actual density, and liquid actual density.

[0012] Furthermore, the method for determining the liquid-carrying state of a gas well using the flooding mechanism includes:

[0013] Calculate the rising speed of the Taylor bubble :

[0014]

[0015] in, For the apparent velocity of the gas, For the apparent velocity of the liquid, D The inner diameter of the wellbore. g It is the acceleration due to gravity. g =9.81 N / kg;

[0016] The porosity of the Taylor bubble segment was calculated using the Newton-Raphson iteration method.

[0017] Calculate the liquid film thickness by combining the porosity of the Taylor bubble segment;

[0018] Calculate the velocity of the falling liquid film based on the liquid film thickness:

[0019]

[0020] In the formula, The velocity of the falling liquid film, δ f The thickness of the falling liquid film. g It is the acceleration due to gravity. This represents the actual density of the liquid. This represents the actual density of the gas.

[0021] By combining the rising velocity of the Taylor bubble and the falling liquid film velocity, as well as real-time multiphase flow parameters, the liquid-carrying state of the gas well can be determined.

[0022] Furthermore, the method for determining the liquid-carrying state of a gas well by combining the rising velocity and falling liquid film velocity of the Taylor bubble with real-time multiphase flow parameters includes:

[0023] Determine whether the following expression is true:

[0024]

[0025] If so, the gas well is in a fully liquid-carrying state; otherwise, the gas well is in a partially liquid-carrying state.

[0026] in, The velocity is a dimensionless gas phase conversion. As an empirical coefficient, For dimensionless liquid phase converted velocity:

[0027]

[0028]

[0029] in, This represents the actual density of the gas. This is the actual density of the liquid. Let be the rising velocity of the Taylor bubble. The velocity of the falling liquid film.

[0030] Furthermore, the method for calculating the spatiotemporal average liquid-carrying capacity and the spatiotemporal average liquid accumulation capacity of the slug flow includes:

[0031] Define a slug unit, which includes a Taylor bubble, a liquid film surrounding the Taylor bubble, and two adjacent liquid plugs;

[0032] Calculate the gas content of the liquid plug based on real-time multiphase flow parameters;

[0033] The instantaneous flow rate of the liquid plug is calculated based on the gas content and rising velocity of the liquid plug; the rising velocity of the liquid plug is equal to the rising velocity of the Taylor bubble.

[0034]

[0035]

[0036] in, The instantaneous flow rate of the liquid plug. The cross-sectional area of ​​the wellbore. Let be the rising velocity of the liquid plug. The gas content of the liquid plug;

[0037] Calculate the instantaneous flow rate of the descending liquid film based on the porosity of the Taylor bubble section and the velocity of the falling liquid film:

[0038]

[0039] in, To reduce the instantaneous flow rate of the liquid film, The cross-sectional area of ​​the wellbore. The velocity of the falling liquid film, The porosity of the Taylor bubble segment;

[0040] By combining the gas holdup of the liquid plug, the average gas holdup of the slug unit, the porosity of the Taylor bubble segment, the length of the slug unit, the axial length of the liquid plug, and the axial length of the Taylor bubble, the liquid plug time weight and the Taylor bubble time weight of the slug flow are calculated respectively.

[0041] The spatiotemporal average liquid-carrying flow rate of the slug flow is calculated based on the slug time weight and the instantaneous flow rate of the slug; and the spatiotemporal average liquid accumulation flow rate of the slug flow is calculated based on the Taylor bubble time weight and the instantaneous flow rate of the falling liquid film.

[0042] The method for calculating the liquid carrying efficiency of a gas well under incomplete liquid carrying conditions includes:

[0043] The total liquid volume of the slug unit is obtained by summing the spatiotemporal average liquid carrying capacity and the spatiotemporal average liquid accumulation capacity of the slug flow.

[0044] Based on the total fluid volume of the slug unit and the spatiotemporal average fluid carrying capacity of the slug flow, the fluid carrying efficiency of the gas well under incomplete fluid carrying conditions is calculated.

[0045] Furthermore, the method for calculating the gas well fluid carrying efficiency under incomplete fluid carrying conditions based on the total fluid volume of the slug unit and the spatiotemporal average fluid carrying rate of the slug flow includes:

[0046]

[0047] in, This represents the liquid carrying efficiency of a gas well under incomplete liquid carrying conditions. The spatiotemporal average liquid carrying capacity of the slug flow is given. The spatiotemporal average accumulation flow rate of the slug flow is given. This represents the total fluid volume of the slug unit. For slug flow, the time weight of the liquid plug is used. For Taylor bubble time weights, The instantaneous flow rate of the rising hydraulic plug. To reduce the instantaneous flow rate of the liquid film.

[0048] Furthermore, the method for calculating the slug flow time weight and the Taylor bubble time weight respectively includes:

[0049]

[0050]

[0051] in, For slug flow, the time weight of the liquid plug is used. This represents the axial length of the liquid plug. The length of the slug unit. The average porosity of the slug unit. The porosity of the Taylor bubble segment. The gas content of the liquid plug. For Taylor bubble time weights, denoted as the axial length of the Taylor bubble.

[0052] Secondly, this application proposes a real-time evaluation system for the fluid-carrying performance of slug flow in natural gas wells, comprising:

[0053] The parameter module is used to obtain real-time multiphase flow parameters of the gas well;

[0054] The first judgment module is used to judge the liquid-carrying state of the gas well based on the real-time multiphase flow parameters and the flooding mechanism. If the critical condition for flooding is met, the gas well is in a fully liquid-carrying state; otherwise, the gas well is in a partially liquid-carrying state.

[0055] The second judgment module is used to perform the judgment: if the gas well is in a fully liquid-carrying state, the liquid-carrying efficiency of the gas well is 1; if the gas well is in a partially liquid-carrying state, based on the rising liquid plug and falling liquid film of the slug flow, as well as the spatiotemporal non-uniformity characteristics of the rising liquid plug and falling liquid film of the slug flow, the spatiotemporal average liquid-carrying flow rate and the spatiotemporal average liquid accumulation flow rate of the slug flow are calculated respectively.

[0056] The calculation module is used to calculate the liquid carrying efficiency of a gas well under incomplete liquid carrying conditions based on the spatiotemporal average liquid carrying flow rate of the slug and the spatiotemporal average liquid accumulation flow rate of the slug flow.

[0057] Thirdly, this application proposes an electronic device, including a memory, a processor, and a computer program stored in the memory and executable on the processor, characterized in that the processor executes the computer program to implement the steps of the above-mentioned method for real-time evaluation of the fluid carrying capacity of a slug flow in a natural gas well.

[0058] Fourthly, this application proposes a computer-readable storage medium storing a computer program that, when executed by a processor, implements the steps of the above-described method for real-time evaluation of the fluid-carrying performance of a slug flow in a natural gas well.

[0059] Compared with the prior art, this application has the following beneficial effects:

[0060] This application proposes a real-time evaluation method for the liquid-carrying performance of slug flow in natural gas wells. Based on real-time multiphase flow parameters, it uses the flooding mechanism to determine the liquid-carrying state of the gas well. If the critical condition for flooding is met, the gas well can be determined to be in a fully liquid-carrying state, and the liquid-carrying efficiency can be directly determined. If it is in a partially liquid-carrying state, based on the spatiotemporal non-uniformity of slug flow, the spatiotemporal average liquid-carrying flow rate and the spatiotemporal average liquid accumulation flow rate of the slug flow are calculated. Then, based on the spatiotemporal average liquid-carrying flow rate and the spatiotemporal average liquid accumulation flow rate of the slug flow, the liquid-carrying efficiency of the gas well under the partially liquid-carrying state is calculated. This application can accurately reflect the actual liquid-carrying efficiency of the gas well under different multiphase flow parameters, breaking through the limitation of traditional critical criteria that only distinguish between fully liquid-carrying and partially liquid-carrying states. It realizes continuous and quantitative evaluation and dynamic monitoring of the liquid-carrying capacity at any production stage throughout the entire life cycle of the gas well. Therefore, reasonable and feasible production systems and drainage and gas production processes can be formulated to effectively ensure stable gas well production. This application can significantly improve the ability to predict and handle liquid accumulation problems during gas field development, reduce the risk of production reduction and operating costs caused by liquid accumulation, and has important engineering practical significance for ensuring stable and increased natural gas production.

[0061] This application also proposes a real-time evaluation system for the fluid-carrying performance of slug flow in natural gas wells, an electronic device, and a computer-readable storage medium, which possesses all the advantages of the aforementioned real-time evaluation method for the fluid-carrying performance of slug flow in natural gas wells. Attached Figure Description

[0062] To more clearly illustrate the technical solutions of the embodiments of this application, the accompanying drawings used in the embodiments will be briefly introduced below. It should be understood that the following drawings only show some embodiments of this application and should not be regarded as a limitation of the scope. For those skilled in the art, other related drawings can be obtained based on these drawings without creative effort.

[0063] Figure 1This is a schematic diagram of the first process of the real-time evaluation method for the fluid-carrying capacity of slug flow in natural gas wells according to this application.

[0064] Figure 2 This is a schematic diagram of the second process for the real-time evaluation method of fluid-carrying capacity of slug flow in natural gas wells in this application;

[0065] Figure 3 This is a schematic diagram of a complete slug unit in an embodiment of this application;

[0066] Figure 4 This is a schematic diagram of a real-time evaluation system for the fluid-carrying performance of slug flow in a natural gas well, as described in this application. Detailed Implementation

[0067] To make the objectives, technical solutions, and advantages of the embodiments of this application clearer, the technical solutions of the embodiments of this application will be clearly and completely described below with reference to the accompanying drawings. Obviously, the described embodiments are only some embodiments of this application, and not all embodiments. The components of the embodiments of this application described and shown in the accompanying drawings can generally be arranged and designed in various different configurations.

[0068] Therefore, the following detailed description of the embodiments of this application provided in the accompanying drawings is not intended to limit the scope of the claimed application, but merely to illustrate selected embodiments of the application. All other embodiments obtained by those skilled in the art based on the embodiments of this application without inventive effort are within the scope of protection of this application.

[0069] It should be noted that similar labels and letters in the following figures indicate similar items. Therefore, once an item is defined in one figure, it does not need to be further defined and explained in subsequent figures.

[0070] In the description of the embodiments of this application, it should be noted that if terms such as "upper," "lower," "horizontal," or "inner" indicate the orientation or positional relationship based on the orientation or positional relationship shown in the accompanying drawings, or the orientation or positional relationship commonly used when the product of the invention is in use, they are only for the convenience of describing this application and simplifying the description, and do not indicate or imply that the device or element referred to must have a specific orientation, or be constructed and operated in a specific orientation, and therefore should not be construed as a limitation on this application. In addition, terms such as "first" and "second" are only used to distinguish descriptions and should not be construed as indicating or implying relative importance.

[0071] Furthermore, the use of the term "horizontal" does not imply that the component must be absolutely horizontal, but rather that it can be slightly tilted. For example, "horizontal" simply means that its direction is more horizontal than "vertical," and does not mean that the structure must be completely horizontal, but can be slightly tilted.

[0072] In the description of the embodiments of this application, it should also be noted that, unless otherwise explicitly specified and limited, the terms "set," "install," "connect," and "link" should be interpreted broadly. For example, they can refer to a fixed connection, a detachable connection, or an integral connection; they can refer to a mechanical connection or an electrical connection; they can refer to a direct connection or an indirect connection through an intermediate medium; and they can refer to the internal connection of two components. Those skilled in the art can understand the specific meaning of the above terms in this application according to the specific circumstances.

[0073] Natural gas extraction is a core area of ​​the energy industry, widely used in the development of various gas reservoirs, including conventional and unconventional ones (such as shale gas and coalbed methane). Its production process directly impacts the stability and economic efficiency of energy supply. Formation water production is a common phenomenon during the gas well production cycle. Specifically, formation water refers to the formation water, condensate, and other liquid substances produced from the formation along with natural gas during reservoir development. For low-water-cut gas wells (i.e., wells where the proportion of liquid production to natural gas production is relatively low), or wells in the early stages of production, the natural gas production is high, and the gas flow itself has sufficient kinetic energy to carry the produced liquid upwards within the wellbore, ultimately ensuring its smooth discharge at the wellhead and maintaining normal production. It should be noted that the wellbore is the cylindrical channel connecting the underground gas reservoir to the surface wellhead, serving as the transport channel for natural gas and produced liquids. However, as the gas well production time increases, the reservoir energy is gradually depleted, and the well enters the later stages of production, at which point the gas production rate decreases significantly. Meanwhile, some gas wells are high-water-cut wells, producing large amounts of liquid. In these cases, the gas flow energy of the natural gas is insufficient to support the carrying capacity of all the liquid, resulting in the liquid produced from the formation not being completely carried out of the wellhead by the gas flow, thus accumulating in the wellbore and forming liquid accumulation. Therefore, accurate assessment of the liquid-carrying status of gas wells and real-time monitoring of liquid accumulation are crucial for ensuring stable gas well production and avoiding production losses. Especially for gas wells with different water cuts and different production stages, the development of targeted liquid-carrying optimization measures relies heavily on reliable monitoring and assessment data. This technical requirement has significant practical implications in the development of various gas reservoirs.

[0074] In natural gas extraction, wellbore fluid accumulation is one of the main problems affecting well production efficiency. When fluid forms in the wellbore, the gravity of the liquid impedes the flow of natural gas, leading to a significant decrease in gas production and reduced output. As the amount of fluid increases, the pressure generated by the fluid column also gradually increases. When the pressure exceeds the reservoir's own gas supply pressure, it can directly cause the well to be flooded and shut down, resulting in severe economic losses for natural gas extraction. More importantly, the water cut and production stage of a gas well are dynamic. Low-water-cut wells may gradually transform into high-water-cut wells as production progresses, and the high-production state in the early stages of production will naturally transition to a low-production state in the later stages. The fluid-carrying capacity of a well varies significantly under different conditions, which necessitates full life-cycle coverage for fluid-carrying status assessment and fluid accumulation monitoring. If the fluid-carrying status of a gas well at different stages cannot be grasped in a timely and accurate manner, it is impossible to predict the risk of fluid accumulation in advance and to formulate effective countermeasures, leading to recurring fluid accumulation problems and seriously affecting the overall efficiency of reservoir development. In addition, the problem of liquid accumulation is particularly prominent in high water-cut gas wells and gas wells in the later stages of production. The liquid-carrying conditions of these gas wells are more complex, the liquid accumulation rate is faster, and the requirements for the accuracy and real-time performance of monitoring and evaluation technologies are higher. The limitations of existing technologies in dealing with these complex working conditions are also more obvious.

[0075] To address the problems caused by fluid accumulation in wellbores, the industry has gradually developed technologies for monitoring and diagnosing fluid carrying capacity in gas wells. Among these, the critical fluid carrying criterion method is widely used. The core logic of this method is to determine a critical fluid carrying velocity or critical fluid carrying flow rate as the basis for judging the fluid carrying state of the gas well. When the actual gas phase velocity or actual gas production of the gas well reaches this critical value, the gas well is considered to be in a fully fluid-carrying state, and no fluid will accumulate in the wellbore. Conversely, when the actual gas phase velocity or gas production is lower than this critical value, it is determined to be in a partially fluid-carrying state, and fluid accumulation is expected in the gas well.

[0076] However, existing technologies based on critical liquid-carrying criteria have significant limitations and cannot meet the actual needs of assessing and monitoring the liquid-carrying status throughout the entire lifecycle of gas wells. The core flaw of these technologies lies in their focus solely on determining the fully liquid-carrying state, simply categorizing gas well liquid-carrying states into fully liquid-carrying and incomplete liquid-carrying states, neglecting in-depth research and quantitative analysis of the incomplete liquid-carrying state. Most gas wells face declining gas production in the later stages of production, generally being in an incomplete liquid-carrying state. These wells often require drainage and gas-production measures such as bubble drainage and gas lift to maintain production. Because existing technologies cannot quantitatively assess and monitor key parameters such as liquid accumulation volume, accumulation rate, and well liquid-carrying efficiency in the incomplete liquid-carrying state, field personnel struggle to accurately judge the liquid accumulation trend and precisely determine the timing and intensity of drainage and gas-production measures. This affects the effectiveness of the measures and may even lead to additional production losses or increased costs due to inappropriate measures.

[0077] Based on the above, this application proposes a method and related device for real-time evaluation of the fluid-carrying performance of slug flow in natural gas wells. The following is a detailed description of this application in conjunction with embodiments and accompanying drawings.

[0078] like Figure 1 The diagram shown is a first flowchart illustrating the real-time evaluation method for the liquid-carrying capacity of slug flow in natural gas wells according to this application, which may include:

[0079] S101, obtain real-time multiphase flow parameters of the gas well.

[0080] It should be noted that real-time multiphase flow parameters refer to key parameters reflecting the flow characteristics during the gas-liquid two-phase flow process within the gas wellbore. These include, for example, apparent gas velocity, apparent liquid velocity, wellhead pressure, wellhead temperature, actual gas density, and actual liquid density. Real-time multiphase flow parameters provide fundamental data reflecting the gas well's liquid-carrying capacity and flow state. Only by accurately acquiring these parameters can accurate judgments of the gas well's liquid-carrying state and calculations of its liquid-carrying efficiency be performed subsequently. In practical applications, wellhead pressure and temperature can be obtained through wellhead sensors. Actual gas and liquid densities can be obtained through sampling and testing, or calculated based on measured pressure and temperature data at the wellhead and converted to density under standard conditions. Apparent gas and liquid velocities can be collected in real-time by wellbore sensors, or obtained using surface metering equipment to acquire gas and liquid production data at the wellhead, which can then be combined with wellhead pressure and wellbore inner diameter for calculation.

[0081] S102, based on real-time multiphase flow parameters, uses the flooding mechanism to determine the liquid-carrying state of the gas well. If the critical condition for flooding is met, the gas well is in a fully liquid-carrying state; otherwise, the gas well is in a partially liquid-carrying state.

[0082] It should be noted that the flooding mechanism refers to the critical state in which the liquid phase is carried by the gas phase when the gas and liquid phases flow in a vertical pipe. When the gas phase velocity is sufficiently high, flooding occurs, and the liquid phase is carried by the gas phase to form a stable upward flow, preventing backflow and deposition at the bottom of the well. The critical condition for flooding is the threshold value of the multiphase flow parameters at which flooding occurs. When the actual multiphase flow parameters reach or exceed this threshold, the gas well can achieve complete liquid carrying. Correspondingly, the state of complete liquid carrying is the flow state in which the gas flow can carry all the produced liquid, and no liquid accumulation occurs in the wellbore. The state of incomplete liquid carrying is the flow state in which the gas flow cannot carry all the produced liquid, and some liquid accumulates in the wellbore, forming liquid accumulation.

[0083] Flooding is the critical state in which the liquid phase in a vertical gas-liquid two-phase pipe flow is completely carried away. The critical parameters at which flooding occurs can serve as the core basis for determining whether a gas well can completely carry liquid. By comparing the actual multiphase flow parameters with the flooding critical conditions, the liquid-carrying state of a gas well can be accurately classified, overcoming the limitation of traditional critical liquid-carrying criteria that rely on only a single parameter. In practical applications, based on the multiphase flow parameters of the gas well, a mature flooding critical condition calculation model can be used to calculate the corresponding flooding critical parameters for that gas well. Then, the actual multiphase flow parameters are compared with the calculated flooding critical parameters. If the actual parameters are greater than or equal to the critical parameters, the critical conditions for flooding are met, and the well is determined to be in a completely liquid-carrying state; otherwise, it is determined to be in a partially liquid-carrying state.

[0084] This application enables accurate qualitative judgment of the liquid-carrying state of gas wells. Compared with the traditional critical liquid-carrying criteria, the flooding mechanism is more in line with the actual flow characteristics of multiphase flow in gas wells, and the judgment results are more accurate.

[0085] S103, if the gas well is in a fully liquid-carrying state, the liquid-carrying efficiency of the gas well is 1; if the gas well is in a partially liquid-carrying state, based on the rising liquid plug and falling liquid film of the slug flow, as well as the spatiotemporal non-uniformity characteristics of the rising liquid plug and falling liquid film of the slug flow, the spatiotemporal average liquid-carrying flow rate and the spatiotemporal average liquid accumulation flow rate of the slug flow are calculated respectively.

[0086] It should be noted that the liquid-carrying efficiency of a gas well refers to the ratio of the actual amount of liquid carried by the gas flow to the total amount of liquid produced by the formation. It is a core indicator for quantifying the liquid-carrying capacity of a gas well, and its value typically ranges from 0 to 1. Slug flow is a common flow pattern in gas-liquid two-phase flow, characterized by the intermittent distribution of liquid and gas in the form of liquid plugs and long bubbles (Taylor bubbles), respectively. Taylor bubbles push the liquid plugs upward, while a stable liquid film flows downward around the Taylor bubbles. The liquid in the rising liquid plugs is effectively carried, and the descending liquid film eventually forms liquid accumulation at the bottom of the well. The intermittent movement of the liquid plugs and long bubbles causes significant differences in the flow parameters of slug flow in both the temporal and spatial dimensions, i.e., it exhibits obvious spatiotemporal inhomogeneity. The spatiotemporal average liquid-carrying capacity of slug flow refers to the average flow rate of liquid actually carried by the slug flow within a certain time period and a certain wellbore length, taking into account spatiotemporal inhomogeneity. The spatiotemporal average liquid accumulation capacity of slug flow refers to the average flow rate of liquid that the slug flow failed to carry and deposited in the wellbore within a certain time period and a certain wellbore length, taking into account spatiotemporal inhomogeneity.

[0087] In a fully liquid-carrying state, the gas flow can carry all the produced liquid, so the liquid-carrying efficiency of a gas well is theoretically 1. However, in a partially liquid-carrying state, the gas-liquid flow often exhibits slug flow, and its spatiotemporal inhomogeneity causes the liquid carrying and accumulation to have dynamic characteristics, which cannot be calculated using simple proportional relationships. Therefore, it is necessary to obtain averaged parameters based on the spatiotemporal inhomogeneity of slug flow by statistically analyzing liquid carrying and accumulation data within a certain spatiotemporal range, providing a quantitative basis for subsequent efficiency calculations.

[0088] In practical applications, for a fully liquid-carrying state, the gas well's liquid-carrying efficiency is directly assigned as 1. For a partially liquid-carrying state, slug flow parameters at different times and locations in the wellbore can be obtained first using multiphase flow monitoring equipment. Then, based on these parameters, a combination of time-weighted averaging and spatial-weighted averaging methods can be used to calculate the spatiotemporal average liquid-carrying flow rate and the spatiotemporal average liquid accumulation flow rate of the slug flow per unit time and per unit wellbore length. These are then summed to obtain the total liquid volume within that spatiotemporal range. Alternatively, slug flow numerical simulation software can be used to simulate the spatiotemporal distribution data of the slug flow by inputting real-time multiphase flow parameters. Statistical analysis can then be used to calculate the corresponding spatiotemporal average liquid-carrying flow rate and the spatiotemporal average liquid accumulation flow rate. Finally, the gas well's liquid-carrying efficiency can be calculated using the relative relationships between the liquid-carrying flow rate, the liquid accumulation flow rate, and the total liquid volume.

[0089] This application realizes the transition from qualitative to quantitative analysis of liquid-carrying status. In particular, for the incomplete liquid-carrying status, by exploring the spatiotemporal non-uniformity of slug flow, quantifiable liquid-carrying and liquid accumulation parameters are obtained. This breaks the limitation of traditional technology, which can only make qualitative judgments on the incomplete liquid-carrying status, and provides key data for accurately calculating the liquid-carrying efficiency of gas wells.

[0090] S104. Based on the spatiotemporal average liquid carrying capacity and the spatiotemporal average liquid accumulation capacity of the slug flow, the liquid carrying efficiency of the gas well under the condition of incomplete liquid carrying is calculated.

[0091] It should be noted that under slug flow conditions, the total liquid volume is equal to the sum of the spatiotemporal average liquid carrying flow rate and the spatiotemporal average liquid accumulation flow rate. The liquid carrying efficiency of a gas well is essentially the ratio of the actual liquid carrying volume to the total liquid volume. Therefore, by using the ratio of these two average parameters, the liquid carrying efficiency of a gas well under incomplete liquid carrying conditions can be directly calculated, thus achieving a quantitative assessment of the liquid carrying performance.

[0092] This application ultimately achieves the quantitative calculation of the liquid carrying efficiency of gas wells under incomplete liquid carrying conditions, obtaining intuitive and comparable quantitative indicators. This upgrades the assessment of the liquid carrying capacity of gas wells from whether liquid accumulates to the amount of liquid accumulated and the level of liquid carrying efficiency, providing a direct basis for on-site personnel to accurately judge the risk of liquid accumulation and formulate targeted drainage and gas production measures.

[0093] This application first acquires real-time multiphase flow parameters of gas wells using various monitoring devices or simulation methods to provide data support for evaluation. Then, based on the flooding mechanism, it compares the real-time multiphase flow parameters with flooding critical conditions to classify the well into a fully liquid-carrying state and an incompletely liquid-carrying state, solving the problem of inaccurate qualitative judgments in traditional criteria. Finally, for the fully liquid-carrying state, the gas well's liquid-carrying efficiency is directly assigned a value of 1. For the incompletely liquid-carrying state, the spatiotemporal non-uniformity of slug flow is utilized to calculate the spatiotemporal average liquid-carrying flow rate and the spatiotemporal average liquid accumulation flow rate of the slug flow, thereby obtaining a quantitative gas well liquid-carrying efficiency. Therefore, this application not only covers the liquid-carrying state of gas wells at different production stages and under different water-cut conditions, but also achieves a leap from qualitative judgment to quantitative evaluation, filling the gap in existing technologies regarding the lack of quantitative analysis of incompletely liquid-carrying states, and constructing a comprehensive, accurate, and practical gas well liquid-carrying performance evaluation system.

[0094] like Figure 2 The diagram shown is a second flowchart illustrating the real-time evaluation method for the fluid-carrying capacity of slug flow in natural gas wells according to this application, which may include:

[0095] S201 collects real-time multiphase flow parameters from the gas well.

[0096] In this embodiment, the real-time multiphase flow parameters of the gas well include the apparent gas velocity. apparent velocity of liquid , wellbore inner diameter D Actual density of liquid and actual density of gas .

[0097] S202, Calculate the rising velocity of the Taylor bubble. .

[0098]

[0099] in, For the apparent velocity of the gas, For the apparent velocity of the liquid, D The inner diameter of the wellbore. g It is the acceleration due to gravity. g =9.81N / kg.

[0100] S203, the porosity of the Taylor bubble segment is calculated using the Newton-Raphson iteration method. .

[0101] In the Taylor bubble segment:

[0102]

[0103] in, The velocity of the falling liquid film, This represents the average velocity of the gas-liquid mixture. Furthermore:

[0104]

[0105] but, .

[0106] The rising speed of the Taylor bubble and falling liquid film velocity Substituting the solution into the formula, we construct an iterative solution function for the porosity of the Taylor bubble segment. for:

[0107] ( >0.25)

[0108] Iterative value retrieval:

[0109]

[0110] in, For the first The porosity of the Taylor bubble segment obtained in the next iteration For the first The porosity of the Taylor bubble segment obtained in the next iteration The porosity iterative solution function is in The function value at that point, The porosity iterative solution function is in The derivative of the function value at point [0, 1].

[0111] Calculate the numerical derivative:

[0112] ( h = 10 -6 )

[0113] in, The porosity iterative solution function is in The derivative of the function value at point , The porosity iterative solution function is in The function value at that point, For iterative solution of the function in The function value at that point, This is the difference value.

[0114] Set the convergence condition as follows: The iteration stops when the time is right. The porosity iterative solution function is in The function value at that location.

[0115] During the iterative calculation process, initial value for: =0.8.

[0116] S204, Calculate the thickness of the falling liquid film around the Taylor bubble. .

[0117]

[0118] S205, Calculate the velocity of the falling liquid film around the Taylor bubble. .

[0119]

[0120] S206, judging the liquid-carrying state of gas wells based on the critical conditions for flooding.

[0121]

[0122] in, The velocity is a dimensionless gas phase conversion. This is an empirical coefficient related to the Taylor bubble length; based on numerous experiments, its value can be 0.5. The velocity is the dimensionless liquid phase conversion velocity.

[0123] If the above formula is satisfied, the gas well is in a fully liquid-carrying state with no risk of liquid accumulation, and the gas well's liquid-carrying efficiency is [high / high]. If the above formula is not satisfied, the gas well is in a state of incomplete liquid carrying, indicating a risk of liquid accumulation. Therefore, the liquid carrying efficiency of the gas well under the state of incomplete liquid carrying is calculated to further evaluate the liquid carrying capacity.

[0124] Specifically:

[0125]

[0126]

[0127] S207, calculate the liquid carrying efficiency of a gas well under incomplete liquid carrying conditions.

[0128] like Figure 3 The diagram shown is a schematic of a complete slug unit. Figure 3 In the diagram, A represents the liquid plug, B represents the wall, C represents the falling liquid film, and D represents the Taylor bubble. Assuming the flow is fully developed, under certain pipe structure and dimensions, and constant gas-liquid flow velocities, the key flow parameters of slug flow, such as the lengths of the liquid plug and Taylor bubble, and the velocities of the liquid plug and liquid film, are approximately constant.

[0129] Taking the bottom slug unit of the pipeline as the research object, a slug unit consists of a Taylor bubble, a liquid film surrounding the Taylor bubble, and two adjacent liquid plugs. When the gas and liquid phases in the pipeline are in a slug flow pattern, the liquid phase rises in the form of a liquid plug under the push of the Taylor bubble, which is the liquid carrying process. At the same time, since the Taylor bubble cannot completely occupy the pipeline space, combined with the gas-liquid velocity difference, part of the liquid phase in the liquid plug falls in the annular space between the Taylor bubble and the pipeline wall in the form of a liquid film, forming liquid accumulation. Therefore, the gas well liquid carrying efficiency of the slug unit can be defined as: rising liquid plug flow rate / (rising liquid plug flow rate + falling liquid film flow rate) at any given time interval.

[0130] (1) Calculate the velocity of the liquid plug. The liquid plug rises under the push of the Taylor bubble. Therefore, the rising velocity of the liquid plug is equal to the rising velocity of the Taylor bubble:

[0131]

[0132] in, Let be the rising velocity of the liquid plug. denoted as the rising speed of the Taylor bubble.

[0133] (2) Calculate the gas content of the liquid plug :

[0134]

[0135] In this embodiment, c 1 = 0.033, c 2 = 1.25.

[0136] (3) Calculate the instantaneous flow rate of the slug. The rising slug flow rate is the instantaneous liquid-carrying flow rate of the slug. Since the slug contains air bubbles, the calculation of the instantaneous flow rate of the slug should exclude the gas phase inside the slug. for:

[0137]

[0138]

[0139] in, The instantaneous flow rate of the liquid plug. This represents the cross-sectional area of ​​the wellbore.

[0140] (4) Calculate the instantaneous flow rate of the descending liquid film. The instantaneous flow rate of the descending liquid film in the slug unit is the instantaneous flow rate of the slug flow accumulation fluid. The calculation method is as follows:

[0141]

[0142] (5) The average porosity of the slug unit was calculated using the empirical correlation between Akagawa and Sakaguchi. :

[0143] .

[0144] (6) Calculate the time weight of the slug flow. Taylor bubble time weights .

[0145] In slug flow, the flow is intermittent, with liquid plugs and liquid films alternating, and their distribution varies with time and space. Instantaneous flow rate cannot characterize long-term flow characteristics and the overall system properties, while spatiotemporal average flow rate combines temporal fluctuations and spatial distribution, eliminating instantaneous fluctuations and local differences in the flow, and reflecting the overall average characteristics of the flow.

[0146] In slug flow conditions, the slug flow liquid plug time weight Taylor bubble time weights (The time ratios of the liquid plug and the liquid film flowing through the same observation point are as follows:)

[0147]

[0148]

[0149] in, This represents the axial length of the liquid plug. The length of the slug unit. denoted as the axial length of the Taylor bubble.

[0150] The length of a slug element is equal to the sum of the axial length of the liquid plug and the axial length of the Taylor bubble:

[0151]

[0152] Specifically, , Calculated using the following formula:

[0153]

[0154]

[0155] (7) Calculate the spatiotemporal average liquid carrying flow rate and the spatiotemporal average liquid accumulation flow rate of the slug.

[0156] Spatiotemporal mean liquid carrying capacity of a slug in response to spatiotemporal inhomogeneities in slug flow Spatial-temporal mean flow rate of slug Calculated using the following formula:

[0157]

[0158]

[0159] (8) Calculate the total fluid volume of the slug unit. The total fluid volume of the slug unit is the sum of the slug's spatiotemporal average fluid carrying capacity and the slug's spatiotemporal average fluid accumulation capacity:

[0160]

[0161] (9) Calculate the liquid carrying efficiency of a gas well under incomplete liquid carrying conditions. η .

[0162] The slug flow well fluid carrying efficiency is the proportion of effectively carried liquid to the total fluid volume of the slug flow. Considering the flow characteristics of the liquid plug and liquid film, the slug flow well fluid carrying efficiency is the ratio of the spatiotemporal average fluid carrying rate of the slug over a certain period to the total fluid volume of the slug unit. Furthermore, the well fluid carrying efficiency is less than 1 under incomplete fluid carrying conditions. Therefore:

[0163]

[0164] Among them, gas well fluid carrying efficiency η The fluid carrying efficiency of a gas well is positively correlated with its autonomous fluid carrying capacity. η The higher the value, the stronger the gas well's ability to carry liquid autonomously.

[0165] This application can calculate the liquid-carrying efficiency of gas wells under both fully liquid-carrying and partially liquid-carrying states. The method described in this application can cover gas wells with any water content and at any production stage throughout their entire lifecycle. Based on the liquid-carrying efficiency calculation in this application, a quantitative assessment and real-time monitoring of the liquid-carrying capacity at any production stage throughout the gas well's lifecycle is achieved. Dynamic calculation of the liquid-carrying efficiency enables precise quantitative assessment of the liquid-carrying performance of gas wells at different production stages. Real-time data feedback can form a liquid-carrying status monitoring system, providing data support for gas well production control. This fills the industry gap of lacking a scientific method for assessing the liquid-carrying status of gas wells in non-continuous liquid-carrying states, and provides direct evidence for adjusting production systems and optimizing drainage and gas production measures for high water-cut gas wells and gas wells in the later stages of production. By incorporating gas well liquid-carrying efficiency into the dynamic management system of gas wells, the ability to predict and handle liquid accumulation problems during gas field development can be significantly improved, reducing the risk of production reduction and operating costs caused by liquid accumulation. This has significant engineering practical significance for ensuring stable and increased natural gas production.

[0166] The following are three examples of using this application for real-time evaluation of the fluid-carrying performance of slug flow in natural gas wells. Example 1 is a fully fluid-carrying state, while Examples 2 and 3 are incomplete fluid-carrying states:

[0167] Example 1 Input parameter: Real-time apparent gas velocity u sg =10 m / s, real-time apparent velocity of the liquid u sl =0.1m / s, wellbore inner diameter D = 0.062m, actual gas density ρ g = 20kg / m 3 Actual density of liquid ρ l =1000kg / m 3 gravitational acceleration g = 9.8m / s 2 .

[0168] Example 2 Input parameters: Real-time apparent gas velocity u sg = 2m / s, real-time apparent velocity of the liquid u sl = 0.1m / s, wellbore inner diameter D = 0.062m, actual gas density ρ g = 20kg / m 3 Actual density of liquid ρ l =1000kg / m 3 gravitational acceleration g= 9.8m / s 2 .

[0169] Example 3 Input parameters: Real-time apparent gas velocity u sg =1 m / s, real-time apparent velocity of liquid u sl = 0.1m / s, wellbore inner diameter D = 0.062m, actual gas density ρ g = 20kg / m 3 Actual density of liquid ρ l =1000kg / m 3 gravitational acceleration g = 9.8m / s 2 .

[0170] The calculation results are shown in Table 1:

[0171] Table 1 Real-time evaluation results of liquid carrying capacity for each example

[0172]

[0173] like Figure 4 The diagram shown is a schematic of a real-time evaluation system for the fluid-carrying performance of slug flow in a natural gas well, which may include:

[0174] The parameter module is used to obtain real-time multiphase flow parameters of the gas well;

[0175] The first judgment module is used to judge the liquid-carrying state of the gas well based on the real-time multiphase flow parameters and the flooding mechanism. If the critical condition for flooding is met, the gas well is in a fully liquid-carrying state; otherwise, the gas well is in a partially liquid-carrying state.

[0176] The second judgment module is used to perform the judgment: if the gas well is in a fully liquid-carrying state, the liquid-carrying efficiency of the gas well is 1; if the gas well is in a partially liquid-carrying state, based on the rising liquid plug and falling liquid film of the slug flow, as well as the spatiotemporal non-uniformity characteristics of the rising liquid plug and falling liquid film of the slug flow, the spatiotemporal average liquid-carrying flow rate and the spatiotemporal average liquid accumulation flow rate of the slug flow are calculated respectively.

[0177] The calculation module is used to calculate the liquid carrying efficiency of a gas well under incomplete liquid carrying conditions based on the spatiotemporal average liquid carrying flow rate of the slug and the spatiotemporal average liquid accumulation flow rate of the slug flow.

[0178] It should be noted that, in the several embodiments provided in this application, it should be understood that the disclosed apparatus and methods can be implemented in other ways. For example, the system embodiments described above are merely illustrative; for instance, the division of each block is only a logical functional division, and in actual implementation, there may be other division methods. For example, multiple blocks may be combined or integrated into another device, or some features may be ignored or not executed. The modules described as separate components may or may not be physically separated. The components shown as modules may be one or more physical units, that is, they may be located in one place or distributed in multiple different places. Some or all of the modules can be selected to achieve the purpose of the solution in this embodiment according to actual needs.

[0179] Furthermore, in the various embodiments of the present invention, the modules can be integrated into one processing unit, or each module can exist physically separately, or two or more modules can be integrated into one unit. The integrated unit described above can be implemented in hardware or as a software functional unit.

[0180] This application also provides an electronic device, which may include one or more processors, memory and communication interfaces.

[0181] The memory, communication interface, and processor are coupled together. For example, the memory, communication interface, and processor can be coupled together via a bus.

[0182] The communication interface is used for data transmission with other devices. The memory stores computer program code. This computer program code includes computer instructions, which, when executed by the processor, cause the electronic device to perform the steps of the aforementioned method for real-time evaluation of the fluid-carrying capacity of slug flows in natural gas wells.

[0183] The processor can be a processor or controller, such as a Central Processing Unit (CPU), a general-purpose processor, a Digital Signal Processor (DSP), an Application-Specific Integrated Circuit (ASIC), a Field-Programmable Gate Array (FPGA), or other programmable logic devices, transistor logic devices, hardware components, or any combination thereof. It can implement or execute the various exemplary logic blocks, modules, and circuits described in conjunction with this disclosure. The processor can also be a combination that implements computing functions, such as a combination of one or more microprocessors, a combination of a DSP and a microprocessor, etc. The processor can be used to support an electronic device in performing the method steps provided in the above embodiments.

[0184] The bus can be a Peripheral Component Interconnect (PCI) bus or an Extended Industry Standard Architecture (EISA) bus, etc. These buses can be categorized as address buses, data buses, control buses, etc.

[0185] This application provides a computer-readable storage medium storing a computer program. When the computer program is executed by a processor, it implements the steps of the above-described method for real-time evaluation of the fluid-carrying performance of a slug flow in a natural gas well.

[0186] The computer-readable storage media involved in this application include random access memory (RAM), memory, read-only memory (ROM), electrically programmable ROM, electrically erasable programmable ROM, registers, hard disks, removable disks, CD-ROMs, or any other form of storage media known in the art.

[0187] The above are merely preferred embodiments of this application and are not intended to limit this application. Various modifications and variations can be made to this application by those skilled in the art. Any modifications, equivalent substitutions, improvements, etc., made within the spirit and principles of this application should be included within the protection scope of this application.

Claims

1. A method for real-time evaluation of the fluid-carrying performance of slug flow in natural gas wells, characterized in that, include: Obtain real-time multiphase flow parameters of gas wells; The real-time multiphase flow parameters include gas apparent velocity, liquid apparent velocity, wellbore inner diameter, gas actual density, and liquid actual density. Based on real-time multiphase flow parameters, the flooding mechanism is used to determine the liquid-carrying state of the gas well. If the critical condition for flooding is met, the gas well is in a fully liquid-carrying state; otherwise, the gas well is in a partially liquid-carrying state. The method for determining the liquid-carrying state of a gas well using the flooding mechanism includes: Calculate the rising speed of the Taylor bubble : in, For the apparent velocity of the gas, For the apparent velocity of the liquid, D The inner diameter of the wellbore. g It is the acceleration due to gravity. g =9.81 N / kg; The porosity of the Taylor bubble segment is calculated using the Newton-Raphson iteration method; the iterative solution function for the porosity of the Taylor bubble segment is as follows: for ， ＞0.25 in, The average velocity of the gas-liquid mixture; Calculate the liquid film thickness by combining the porosity of the Taylor bubble segment; Calculate the velocity of the falling liquid film based on the liquid film thickness: In the formula, The velocity of the falling liquid film, δ f The thickness of the falling liquid film. g It is the acceleration due to gravity. This is the actual density of the liquid. This represents the actual density of the gas. By combining the rising velocity of the Taylor bubble and the falling liquid film velocity, along with real-time multiphase flow parameters, the liquid-carrying state of the gas well can be determined: Determine whether the following expression is true: If so, the gas well is in a fully liquid-carrying state; otherwise, the gas well is in a partially liquid-carrying state. in, The velocity is a dimensionless gas phase conversion. As an empirical coefficient, For dimensionless liquid phase converted velocity: in, This represents the actual density of the gas. This represents the actual density of the liquid. Let be the rising velocity of the Taylor bubble. The velocity of the falling liquid film; If the gas well is in a fully liquid-carrying state, the liquid-carrying efficiency of the gas well is 1; if the gas well is in a partially liquid-carrying state, the spatiotemporal average liquid-carrying flow rate and the spatiotemporal average liquid accumulation flow rate of the slug flow are calculated based on the rising liquid plug and falling liquid film of the slug flow, as well as the spatiotemporal non-uniformity characteristics of the rising liquid plug and falling liquid film of the slug flow. Based on the spatiotemporal average liquid carrying capacity and the spatiotemporal average liquid accumulation capacity of the slug flow, the liquid carrying efficiency of the gas well under incomplete liquid carrying conditions is calculated.

2. The method for real-time evaluation of the fluid-carrying capacity of slug flow in a natural gas well according to claim 1, characterized in that, The method for calculating the spatiotemporal average liquid-carrying capacity and the spatiotemporal average liquid accumulation capacity of the slug flow includes: Define a slug unit, which includes a Taylor bubble, a liquid film surrounding the Taylor bubble, and two adjacent liquid plugs; Calculate the gas content of the liquid plug based on real-time multiphase flow parameters; The instantaneous flow rate of the liquid plug is calculated based on the gas content and rising velocity of the liquid plug; the rising velocity of the liquid plug is equal to the rising velocity of the Taylor bubble. in, The instantaneous flow rate of the liquid plug. The cross-sectional area of ​​the wellbore. Let be the rising velocity of the liquid plug. The gas content of the liquid plug; Calculate the instantaneous flow rate of the descending liquid film based on the porosity of the Taylor bubble section and the velocity of the falling liquid film: in, To reduce the instantaneous flow rate of the liquid film, The cross-sectional area of ​​the wellbore. The velocity of the falling liquid film, The porosity of the Taylor bubble segment; By combining the gas holdup of the liquid plug, the average gas holdup of the slug unit, the porosity of the Taylor bubble segment, the length of the slug unit, the axial length of the liquid plug, and the axial length of the Taylor bubble, the liquid plug time weight and the Taylor bubble time weight of the slug flow are calculated respectively. The spatiotemporal average liquid-carrying flow rate of the slug flow is calculated based on the slug time weight and the instantaneous flow rate of the slug; and the spatiotemporal average liquid accumulation flow rate of the slug flow is calculated based on the Taylor bubble time weight and the instantaneous flow rate of the falling liquid film. The method for calculating the liquid carrying efficiency of a gas well under incomplete liquid carrying conditions includes: The total liquid volume of the slug unit is obtained by summing the spatiotemporal average liquid carrying capacity and the spatiotemporal average liquid accumulation capacity of the slug flow. Based on the total fluid volume of the slug unit and the spatiotemporal average fluid carrying capacity of the slug flow, the fluid carrying efficiency of the gas well under incomplete fluid carrying conditions is calculated.

3. The method for real-time evaluation of the fluid-carrying capacity of slug flow in a natural gas well according to claim 2, characterized in that, The method for calculating the liquid carrying efficiency of a gas well under incomplete liquid carrying conditions based on the total liquid volume of the slug unit and the spatiotemporal average liquid carrying rate of the slug flow includes: in, This represents the liquid carrying efficiency of a gas well under incomplete liquid carrying conditions. The space-time average liquid carrying capacity of the slug flow is given. The spatiotemporal average accumulation flow rate of the slug flow is given. This represents the total fluid volume of the slug unit. For slug flow, the time weight of the liquid plug is used. For Taylor bubble time weights, The instantaneous flow rate of the rising hydraulic plug. To reduce the instantaneous flow rate of the liquid film.

4. The method for real-time evaluation of the fluid-carrying performance of slug flow in a natural gas well according to claim 3, characterized in that, The method for calculating the slug flow time weight and the Taylor bubble time weight respectively includes: in, For slug flow, the time weight of the liquid plug is used. This represents the axial length of the liquid plug. The length of the slug unit. The average porosity of the slug unit. The porosity of the Taylor bubble segment. The gas content of the liquid plug. For Taylor bubble time weights, denoted as the axial length of the Taylor bubble.

5. A real-time evaluation system for the fluid-carrying performance of slug flow in a natural gas well, characterized in that, include: The parameter module is used to obtain real-time multiphase flow parameters of the gas well; The real-time multiphase flow parameters include gas apparent velocity, liquid apparent velocity, wellbore inner diameter, gas actual density, and liquid actual density. The first judgment module is used to judge the liquid-carrying state of the gas well based on the real-time multiphase flow parameters and the flooding mechanism. If the critical condition for flooding is met, the gas well is in a fully liquid-carrying state; otherwise, the gas well is in a partially liquid-carrying state. The method for determining the liquid-carrying state of a gas well using the flooding mechanism includes: Calculate the rising speed of the Taylor bubble : in, For the apparent velocity of the gas, For the apparent velocity of the liquid, D The inner diameter of the wellbore. g It is the acceleration due to gravity. g =9.81 N / kg; The porosity of the Taylor bubble segment is calculated using the Newton-Raphson iteration method; the iterative solution function for the porosity of the Taylor bubble segment is as follows: for: ， ＞0.25 in, The average velocity of the gas-liquid mixture; Calculate the liquid film thickness by combining the porosity of the Taylor bubble segment; Calculate the velocity of the falling liquid film based on the liquid film thickness: In the formula, The velocity of the falling liquid film, δ f The thickness of the falling liquid film. g It is the acceleration due to gravity. This is the actual density of the liquid. This represents the actual density of the gas. By combining the rising velocity of the Taylor bubble and the falling liquid film velocity, along with real-time multiphase flow parameters, the liquid-carrying state of the gas well can be determined: Determine whether the following expression is true: If so, the gas well is in a fully liquid-carrying state; otherwise, the gas well is in a partially liquid-carrying state. in, The velocity is a dimensionless gas phase conversion. As an empirical coefficient, For dimensionless liquid phase converted velocity: in, This represents the actual density of the gas. This represents the actual density of the liquid. Let be the rising velocity of the Taylor bubble. The velocity of the falling liquid film; The second judgment module is used to perform the judgment: if the gas well is in a fully liquid-carrying state, the liquid-carrying efficiency of the gas well is 1; if the gas well is in a partially liquid-carrying state, based on the rising liquid plug and falling liquid film of the slug flow, as well as the spatiotemporal non-uniformity characteristics of the rising liquid plug and falling liquid film of the slug flow, the spatiotemporal average liquid-carrying flow rate and the spatiotemporal average liquid accumulation flow rate of the slug flow are calculated respectively. The calculation module is used to calculate the liquid carrying efficiency of a gas well under incomplete liquid carrying conditions based on the spatiotemporal average liquid carrying flow rate of the slug and the spatiotemporal average liquid accumulation flow rate of the slug flow.

6. An electronic device comprising a memory, a processor, and a computer program stored in the memory and executable on the processor, characterized in that, When the processor executes the computer program, it implements the steps of the real-time evaluation method for the fluid-carrying performance of a slug flow in a natural gas well as described in any one of claims 1-4.

7. A computer-readable storage medium storing a computer program, characterized in that, When the computer program is executed by the processor, it implements the steps of the real-time evaluation method for the fluid carrying capacity of a slug flow in a natural gas well as described in any one of claims 1-4.

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