Real-time monitoring method for liquid accumulation amount in oil pipe of natural gas well and related device

Abstract

The invention belongs to a monitoring method, and provides a real-time monitoring method for the amount of liquid accumulated in an oil pipe of a natural gas well and a related device aiming at the technical problems that whether accurate prediction is carried out or not cannot be judged and dynamic changes cannot be monitored in real time in two methods for judging the state of the liquid accumulated in the gas well at present. The method comprises the following steps: acquiring instantaneous wellhead oil pressure, instantaneous wellhead temperature, instantaneous gas production rate and instantaneous water production rate of a natural gas wellhead in real time, and then respectively determining a gas well water-gas ratio, natural gas phase real density, natural gas real kinematic viscosity, natural gas phase real flow rate, natural gas phase Reynolds number and non-dimensional liquid accumulation amount in an oil pipe; and obtaining the actual liquid phase content according to the non-dimensional liquid accumulation amount in the oil pipe, the diameter of the oil pipe and the depth of the oil pipe. Production structure parameters such as instantaneous gas production, instantaneous water production, instantaneous wellhead oil pressure, instantaneous wellhead temperature and the like which are easy to obtain on site can be directly utilized to obtain a liquid accumulation amount evolution dynamic curve of the gas well in the continuous production process.

Description

Technical Field

[0001] This application belongs to a monitoring method, and specifically relates to a real-time monitoring method for the liquid holdup in the tubing of a natural gas well and related devices. Background Art

[0002] Liquid holdup in gas fields can cause a significant reduction in gas well production, or even shut down the production. Therefore, accurately judging the liquid holdup state of gas wells is crucial for the efficient and stable development of gas fields.

[0003] Currently, there are mainly two methods for judging the liquid holdup state inside gas wells: (1) Predict the critical liquid-carrying flow rate of gas wells and indirectly judge whether the gas wells have started to accumulate liquid. However, among the existing multiple critical liquid-carrying flow rate models, the definitions of critical liquid-carrying are significantly different, making it impossible to horizontally compare the accuracy of different critical liquid-carrying models. In addition, when the gas volume is less than the critical liquid-carrying flow rate, it cannot be proven that the gas well can no longer produce with liquid carried, and when the gas volume is higher than the critical liquid-carrying flow rate, it cannot be guaranteed that there is no liquid holdup in the gas well at this time. The critical liquid-carrying flow rate itself limits the impact of liquid holdup on gas well production to a specific moment rather than a time range. (2) Directly calculate the liquid holdup in the gas well. However, this method requires obtaining parameters such as reservoir parameters that are not easily obtained on-site, and ignores the influence of the key parameter of gas-water ratio on the liquid holdup in the gas well, and also cannot monitor the dynamic change process of the liquid holdup in the wellbore in real time. Summary of the Invention

[0004] In view of the technical problems that the existing two methods for judging the liquid holdup state inside gas wells cannot determine whether accurate predictions are made and cannot monitor the dynamic changes in real time, this application provides a real-time monitoring method for the liquid holdup in the tubing of a natural gas well and related devices.

[0005] To achieve the above object, this application adopts the following technical solutions: In a first aspect, this application proposes a real-time monitoring method for the liquid holdup in the tubing of a natural gas well, including: Real-time collecting the instantaneous wellhead oil pressure, instantaneous wellhead temperature, instantaneous gas production volume, and instantaneous water production volume of the natural gas wellhead; Determining the gas-water ratio of the gas well according to the instantaneous gas production volume and the instantaneous water production volume; Determining the true density of the natural gas gas phase according to the instantaneous wellhead oil pressure and the instantaneous wellhead temperature, in combination with the standard condition density of the natural gas gas phase; Determining the true kinematic viscosity of the natural gas according to the instantaneous wellhead oil pressure and the instantaneous wellhead temperature, in combination with the average relative molecular mass of the natural gas and the true density of the natural gas gas phase; Determining the true flow velocity of the natural gas gas phase according to the tubing diameter, the standard condition density of the corresponding liquid phase of the natural gas, the instantaneous wellhead oil pressure, the instantaneous wellhead temperature, and the instantaneous gas production volume; Determine the Reynolds number of the natural gas gas phase based on the tubing diameter, the true kinematic viscosity of the natural gas, and the true flow velocity of the natural gas gas phase; Determine the dimensionless liquid holdup inside the tubing based on the gas-water ratio of the gas well and the Reynolds number of the natural gas gas phase; Obtain the actual liquid content based on the dimensionless liquid holdup inside the tubing, the tubing diameter, and the tubing depth.

[0006] Further, the method for determining the gas-water ratio of the gas well includes:

[0007] wherein, is the gas-water ratio of the gas well, is the instantaneous water production, is the instantaneous gas production.

[0008] Further, the method for determining the true density of the natural gas gas phase includes:

[0009] wherein, is the true density of the natural gas gas phase, is the instantaneous wellhead oil pressure, is the instantaneous wellhead temperature, is the standard condition density of the natural gas gas phase.

[0010] Further, the method for determining the true kinematic viscosity of the natural gas includes:

[0011] wherein, is the true kinematic viscosity of the natural gas, is the dynamic viscosity of the natural gas gas phase under actual working conditions, is the true density of the natural gas gas phase.

[0012] Further, the method for determining the true flow velocity of the natural gas gas phase includes:

[0013] wherein, is the true flow velocity of the natural gas gas phase, is the apparent flow velocity of the natural gas gas phase, is the standard condition density of the natural gas gas phase, is the standard condition density of the natural gas liquid phase, is the true density of the natural gas liquid phase, is the true density of the natural gas gas phase.

[0014] Further, the method for determining the Reynolds number of the natural gas gas phase includes:

[0015] Among them, is the Reynolds number of the natural gas gas phase, is the true flow velocity of the natural gas gas phase, is the tubing diameter, is the true kinematic viscosity of the natural gas.

[0016] Furthermore, the method for determining the dimensionless liquid holdup inside the tubing includes:

[0017] Among them, is the dimensionless liquid holdup inside the tubing.

[0018] Furthermore, the method for obtaining the actual liquid phase content includes:

[0019] Among them, is the actual liquid phase content, is the tubing depth.

[0020] In a second aspect, the present application proposes a real-time monitoring system for the liquid holdup in the tubing of a natural gas well, including: A data module for real-time collecting the instantaneous wellhead oil pressure, instantaneous wellhead temperature, instantaneous gas production volume, and instantaneous water production volume of the natural gas wellhead; A gas-water ratio module for determining the gas-water ratio of the gas well according to the instantaneous gas production volume and the instantaneous water production volume; A density module for determining the true density of the natural gas gas phase according to the instantaneous wellhead oil pressure and the instantaneous wellhead temperature, in combination with the standard condition density of the natural gas gas phase; A kinematic viscosity module for determining the true kinematic viscosity of the natural gas according to the instantaneous wellhead oil pressure and the instantaneous wellhead temperature, in combination with the average relative molecular mass of the natural gas and the true density of the natural gas gas phase; A flow velocity module for determining the true flow velocity of the natural gas gas phase according to the tubing diameter, the standard condition density of the corresponding liquid phase of the natural gas, the instantaneous wellhead oil pressure, the instantaneous wellhead temperature, and the instantaneous gas production volume; A Reynolds number module for determining the Reynolds number of the natural gas gas phase according to the tubing diameter, the true kinematic viscosity of the natural gas, and the true flow velocity of the natural gas gas phase; A dimensionless module for determining the dimensionless liquid holdup inside the tubing according to the gas-water ratio of the gas well and the Reynolds number of the natural gas gas phase; A liquid phase content module for obtaining the actual liquid phase content according to the dimensionless liquid holdup inside the tubing, the tubing diameter, and the tubing depth.

[0021] In a third aspect, the present application proposes a computer program product, including a computer program which, when executed by a processor, implements the above-mentioned real-time monitoring method for the liquid accumulation amount in the tubing of a natural gas well.

[0022] Compared with the prior art, the present application has the following beneficial effects: The present application proposes a real-time monitoring method for the liquid accumulation amount in the tubing of a natural gas well, which real-time collects the instantaneous wellhead oil pressure, instantaneous wellhead temperature, instantaneous gas production volume, and instantaneous water production volume of the natural gas wellhead, and then respectively determines the gas-water ratio of the gas well, the true density of the natural gas gas phase, the true kinematic viscosity of the natural gas, the true flow velocity of the natural gas gas phase, the Reynolds number of the natural gas gas phase, and the dimensionless liquid accumulation amount inside the tubing. Finally, according to the dimensionless liquid accumulation amount inside the tubing, the tubing diameter, and the tubing depth, the actual liquid phase content is obtained. The present application can directly utilize the production structure parameters such as the instantaneous gas production volume, instantaneous water production volume, instantaneous wellhead oil pressure, and instantaneous wellhead temperature, which are easily obtained on-site, to obtain the evolution dynamic curve of the liquid accumulation amount in the gas well during the continuous production process. It avoids the phenomena that the traditional critical liquid-carrying flow rate model cannot explain, that is, the gas well can still produce normally below the critical liquid-carrying flow rate and there is liquid accumulation in the gas well above the critical liquid-carrying flow rate. It solves the problem that the existing liquid accumulation amount model requires production parameters such as bottom-hole flowing pressure, which cannot be directly obtained on-site. By real-time monitoring the dynamic evolution curve of the liquid accumulation amount in the tubing, it can efficiently evaluate the severity of liquid accumulation and assist production with drainage gas production measures, and finally realize enhanced liquid-carrying in the gas well.

[0023] The present application also proposes a real-time monitoring system for the liquid accumulation amount in the tubing of a natural gas well, as well as a computer program product, which have all the advantages of the above-mentioned real-time monitoring method for the liquid accumulation amount in the tubing of a natural gas well. BRIEF DESCRIPTION OF THE DRAWINGS

[0024] In order to more clearly illustrate the technical solutions of the embodiments of the present application, the following will briefly introduce the drawings required to be used in the embodiments. It should be understood that the following drawings only show some embodiments of the present application, and therefore should not be regarded as limiting the scope. For those of ordinary skill in the art, other related drawings can be obtained based on these drawings without creative efforts.

[0025] Figure 1 It is the first flow schematic diagram of the real-time monitoring method for the liquid accumulation amount in the tubing of the natural gas well of the present application; Figure 2 It is the structural schematic diagram of the gas well; Figure 3 It is the liquid phase content change curve during the production process of the gas well in the embodiment of the present application; Figure 4 It is a schematic diagram of a real-time monitoring system for the liquid accumulation amount in the tubing of the natural gas well of the present application.

[0026] Among them, 1 - tubing, 2 - annulus between tubing and casing, 3 - reservoir, 4 - casing. Detailed implementation manners

[0027] To make the objectives, technical solutions, and advantages of the embodiments of the present application clearer, the technical solutions in the embodiments of the present application will be clearly and completely described below with reference to the accompanying drawings in the embodiments of the present application. Obviously, the described embodiments are some but not all of the embodiments of the present application. Usually, the components of the embodiments of the present application described and illustrated in the accompanying drawings herein can be arranged and designed in various different configurations.

[0028] Therefore, the following detailed description of the embodiments of the present application provided in the accompanying drawings is not intended to limit the scope of the present application claimed, but merely represents selected embodiments of the present application. All other embodiments obtained by those of ordinary skill in the art based on the embodiments of the present application without creative efforts shall fall within the scope of protection of the present application.

[0029] It should be noted that similar reference numerals and letters denote similar items in the following drawings. Therefore, once an item is defined in one drawing, it does not need to be further defined and explained in subsequent drawings.

[0030] In the description of the embodiments of the present application, it should be noted that if terms such as "upper", "lower", "horizontal", "inner", etc. indicate the orientation or positional relationship based on the orientation or positional relationship shown in the drawings, or the orientation or positional relationship in which the inventive product is usually placed during use, it is only for the convenience of describing the present application and simplifying the description, rather than indicating or implying that the device or element referred to must have a specific orientation, be constructed and operated in a specific orientation, and therefore should not be construed as a limitation to the present application. In addition, terms such as "first" and "second" are only used for descriptive distinction and should not be construed as indicating or implying relative importance.

[0031] In addition, if the term "horizontal" appears, it does not mean that the component is required to be absolutely horizontal, but it can be slightly inclined. For example, "horizontal" only means that its direction is more horizontal relative to "vertical", and it does not mean that the structure must be completely horizontal, but it can be slightly inclined.

[0032] In the description of the embodiments of the present application, it should also be noted that unless otherwise clearly specified and limited, if terms such as "set", "installed", "connected", and "connected" are understood in a broad sense. For example, it can be a fixed connection, a detachable connection, or an integral connection; it can be a mechanical connection or an electrical connection; it can be directly connected or indirectly connected through an intermediate medium, and it can be the communication inside two elements. For those of ordinary skill in the art, the specific meanings of the above terms in the present application can be understood according to specific circumstances.

[0033] During the production process of gas fields, due to the existence of formation water and condensate, a large number of gas wells show the phenomenon of high water production. As the reservoir pressure drops, the gas production from the formation decreases, resulting in a decline in the liquid-carrying capacity of the gas phase, which cannot carry the liquid phase to the wellhead, leading to the retention of the liquid phase at the bottom of the well. Thus, problems such as bottom-hole liquid accumulation caused by the loss of gas-phase energy and the decline of gas well production occur. More than half of the gas wells have significantly reduced production or even stopped production due to liquid accumulation, and the number of liquid-accumulating wells in the gas field is still increasing at a rate of 5% per year. Therefore, accurately judging the liquid-accumulation state of gas wells is crucial for the efficient and stable development of gas fields.

[0034] Currently, there are mainly two methods used to judge the liquid-accumulation state inside gas wells: (1) Indirect judgment method based on critical liquid-carrying flow rate: The principle of this method is to indirectly infer whether a gas well has started to accumulate liquid based on predicting the critical liquid-carrying flow rate of the gas well. When the gas flow has sufficient energy to carry the liquid substance to the ground and maintain the normal production of the gas well, the corresponding flow rate is the critical liquid-carrying flow rate. The main problem of this method is that there are multiple critical liquid-carrying flow rate models, and the definitions of critical liquid-carrying by each model vary greatly. Some models focus on considering the physical properties of the fluid, while others pay more attention to the geometric structure of the gas well. This inconsistency makes the calculation results of different models lack comparability and it is difficult to conduct a horizontal evaluation of their accuracy. In addition, the production process of gas wells is very complex. When the gas volume of a gas well is lower than the critical liquid-carrying flow rate, it cannot be determined that the gas well cannot carry liquid for production, because the special structure or other factors in the well may enable the gas well to still maintain a certain degree of liquid-carrying. On the contrary, even if the gas volume is higher than the critical liquid-carrying flow rate, it cannot be excluded that there is liquid accumulation in the gas well. More importantly, the critical liquid-carrying flow rate only represents the state at a specific time point and cannot reflect the dynamic changes of liquid accumulation in the gas well over a period of time, making it difficult to comprehensively and systematically describe the impact of liquid accumulation on gas well production.

[0035] (2) Direct calculation method of liquid-accumulation volume: The principle of this method is to directly calculate the liquid-accumulation volume in the gas well to visually judge the liquid-accumulation state of the gas well. By establishing a mathematical model and combining various parameters of the gas well, the liquid-accumulation volume in the well is calculated, so as to evaluate the production status of the gas well. The main problems of this method are that in actual operation, this method requires obtaining parameters that are difficult to measure on-site, such as reservoir permeability and porosity, which not only increases the difficulty of data collection but also affects the accuracy of the calculation results. In addition, the gas-water ratio, as a key parameter affecting the liquid-accumulation volume of gas wells, is often ignored in the calculation process, resulting in a deviation between the calculation results and the actual situation. Moreover, due to the lack of real-time monitoring means, this method cannot track the dynamic changes of the liquid-accumulation volume in the wellbore in real time, making it difficult to predict the development trend of gas well liquid accumulation in advance, and thus unable to take effective prevention and control measures in a timely manner.

[0036] Therefore, for any production condition, it is necessary to establish a liquid holdup calculation model that includes on-site production structure parameters such as pressure, temperature, gas production volume, pipe diameter, and gas-water ratio, which are easily obtained and can directly affect the change in liquid holdup, so as to monitor the dynamic evolution curve of the liquid holdup in the tubing in real time, enabling timely determination of feasible drainage and gas production measures according to the liquid holdup degree, optimizing the gas well production allocation, and being beneficial to preventing accidents such as gas well shutdowns.

[0037] Based on the above situation, the present application proposes a method and related device for real-time monitoring of the liquid holdup in the tubing of a natural gas well. The following will describe the present application in detail with reference to embodiments and drawings.

[0038] As Figure 1 shown, it is the first flow schematic diagram of the method for real-time monitoring of the liquid holdup in the tubing of a natural gas well in the present application, which may include: S101, collect the instantaneous wellhead oil pressure, instantaneous wellhead temperature, instantaneous gas production volume, and instantaneous water production volume of the natural gas wellhead in real time.

[0039] It should be noted that the instantaneous wellhead oil pressure refers to the pressure value generated by the gas at the natural gas wellhead at a certain moment, which can be collected in real time by a pressure sensor installed at the wellhead. This data reflects the pressure state of the gas at the wellhead and is crucial for judging the working state of the gas well. The instantaneous wellhead temperature is the temperature at the natural gas wellhead at the same moment, which can be obtained by using a temperature sensor. The wellhead temperature affects the physical properties of natural gas, such as density, viscosity, etc. The instantaneous gas production volume is the volume of natural gas produced from the gas wellhead per unit time, which can be measured in real time by a gas flowmeter and directly reflects the gas production capacity of the gas well. The instantaneous water production volume is the volume of water produced at the gas wellhead per unit time, which is collected in real time by a corresponding liquid flowmeter and is an important indicator for measuring the liquid production situation of the gas well.

[0040] These real-time data provide a basis for subsequent calculations and ensure the timeliness and accuracy of monitoring.

[0041] S102, determine the gas-water ratio of the gas well according to the instantaneous gas production volume and the instantaneous water production volume.

[0042] It should be noted that the gas-water ratio of the gas well refers to the volume of water contained in a unit volume of natural gas, which can be calculated by dividing the instantaneous water production volume by the instantaneous gas production volume. The gas-water ratio of the gas well reflects the proportional relationship between gas and water in the fluid produced by the gas well and is a key indicator for analyzing the liquid holdup problem of the gas well.

[0043] S103, determine the true density of the natural gas gas phase according to the instantaneous wellhead oil pressure and the instantaneous wellhead temperature, in combination with the standard condition density of the natural gas gas phase.

[0044] It should be noted that the standard condition density of natural gas in the gas phase refers to the mass of natural gas per unit volume under standard conditions (0°C, 101.325 kPa). The true density of natural gas in the gas phase is the mass of natural gas per unit volume under the actual wellhead oil pressure and temperature conditions. It can be calculated using the ideal gas law, combined with the standard condition density, instantaneous wellhead oil pressure, and instantaneous wellhead temperature. The true density reflects the density characteristics of natural gas under the actual wellhead conditions. Accurately calculating the true density of natural gas in the gas phase can more realistically reflect the physical state of natural gas at the wellhead and improve the accuracy of subsequent calculations.

[0045] S104. Determine the true kinematic viscosity of natural gas based on the instantaneous wellhead oil pressure, instantaneous wellhead temperature, combined with the average relative molecular mass of natural gas and the true density of natural gas in the gas phase.

[0046] Natural gas is a mixture of various gases, and the average relative molecular mass of natural gas is a comprehensive parameter calculated considering the proportions of each component. The true kinematic viscosity of natural gas represents the property of the fluid internal resistance to flow under the actual wellhead conditions. It can be calculated using empirical formulas, combined with the instantaneous wellhead oil pressure, instantaneous wellhead temperature, average relative molecular mass of natural gas, and the true density of natural gas in the gas phase. Determining the true kinematic viscosity helps analyze the flow characteristics of natural gas in the tubing and provides key parameters for calculating the gas-phase flow velocity and Reynolds number.

[0047] S105. Determine the true gas-phase flow velocity of natural gas based on the tubing diameter, standard condition density of the corresponding liquid phase of natural gas, instantaneous wellhead oil pressure, instantaneous wellhead temperature, and instantaneous gas production rate.

[0048] The inner diameter of the tubing in a natural gas well determines the cross-sectional area for the flow of natural gas. The standard condition density of the corresponding liquid phase of natural gas is the density of the liquid phase components in natural gas under standard conditions. The true gas-phase flow velocity of natural gas is the velocity of natural gas flowing in the tubing under the actual wellhead conditions. It can be calculated using relevant fluid mechanics formulas, combined with the above parameters. The true flow velocity reflects the speed of natural gas flowing in the tubing.

[0049] S106. Determine the Reynolds number of natural gas in the gas phase based on the tubing diameter, true kinematic viscosity of natural gas, and true gas-phase flow velocity of natural gas.

[0050] The Reynolds number of natural gas in the gas phase is a dimensionless number used to judge the flow state (laminar flow or turbulent flow) of natural gas in the tubing. The Reynolds number can reflect the flow characteristics of the fluid and plays an important role in analyzing the flow stability of natural gas in the tubing.

[0051] S107. Determine the dimensionless liquid holdup inside the tubing based on the gas-liquid ratio of the gas well and the Reynolds number of natural gas in the gas phase.

[0052] The dimensionless liquid holdup inside the tubing is a relative quantity that does not depend on specific physical units and is used to measure the degree of liquid accumulation in the tubing. By establishing an empirical model, the gas-liquid ratio and the gas-phase Reynolds number of the gas well can be used as input parameters to calculate the dimensionless liquid holdup, which can intuitively reflect the relative liquid accumulation situation inside the tubing. The determination of the dimensionless liquid holdup simplifies the expression of the liquid holdup and facilitates the subsequent comparison of the liquid accumulation situations of different gas wells or the same gas well at different times.

[0053] S108. Obtain the actual liquid phase content based on the dimensionless liquid holdup inside the tubing, the tubing diameter, and the tubing depth.

[0054] The tubing depth is the vertical distance from the wellhead to the bottom of the tubing. The actual liquid phase content is the volume or mass of the liquid actually present in the tubing. By combining the dimensionless liquid holdup inside the tubing with the geometric parameters of the tubing (tubing diameter and tubing depth), the actual liquid phase content can be calculated, and this data directly reflects the scale of liquid accumulation in the tubing.

[0055] Obtaining the actual liquid phase content realizes the real-time and quantitative monitoring of the liquid holdup in the tubing of the gas well, provides strong support for the scientific management and optimized production of the gas well, helps the staff to detect the liquid accumulation problem in time, and take corresponding measures to avoid the reduction or suspension of production of the gas well caused by liquid accumulation.

[0056] This application realizes the real-time monitoring of the liquid holdup in the tubing of the gas well through the real-time acquisition of multiple wellhead parameters and a series of calculations, provides comprehensive and accurate data support for the efficient and stable production of the gas well, helps to detect and solve the liquid accumulation problem of the gas well in time, and improves the production efficiency and economic benefits of the gas well.

[0057] The following further details this application through a specific embodiment of this application: S201. Obtain the inner diameter of the tubing D and the tubing depth H .

[0058] Such as Figure 2As shown in the figure, it is a schematic structural diagram of a gas well. The main structures of the gas well include a wellhead device, tubing 1, casing 4, and reservoir 3, etc. In this embodiment, the wellhead device is used to obtain the instantaneous wellhead oil pressure, instantaneous wellhead temperature, instantaneous gas production rate, and instantaneous water production rate at the natural gas wellhead. The tubing 1 is a pipeline extending from the wellhead to the reservoir 3, and natural gas is transported from the reservoir 3 to the wellhead through this. The casing 4 is sleeved outside the tubing 1 and is generally a multi-layer structure, including surface casing, technical casing, and oil layer casing, etc. The function of the casing 4 is to fix the wellbore wall, prevent formation collapse, seal different pressure intervals and complex formations, and provide protection and support for the tubing 1. The annulus 2 between the tubing 1 and the casing 4 is an annular space. During the production process of the gas well, the annulus 2 can be used to monitor pressure, inject chemical agents, etc. For example, by injecting corrosion inhibitors into the annulus 2, the tubing 1 and the casing 4 can be protected from corrosion, and monitoring the pressure change in the annulus 2 can assist in judging the production status of the gas well. The reservoir 3 is a formation that stores natural gas underground, usually a rock formation with a certain porosity and permeability. Natural gas exists in the reservoir 3 in a free state or an adsorbed state. Under the action of a pressure difference, etc., natural gas flows from the pores and fractures of the reservoir 3 into the wellbore.

[0059] S202, obtain the molecular weights of each component of natural gas using on-line analysis instruments at the natural gas wellhead M i and molar composition y i .

[0060] S203, obtain the standard condition density of the gas phase of natural gas through a standard gas density table ρ G , and obtain the standard condition density of the liquid phase of natural gas through a liquid density table ρ L .

[0061] S204, use the instruments at the natural gas wellhead to collect the instantaneous wellhead oil pressure P x ( t ), the instantaneous wellhead temperature T x ( t ), the instantaneous gas production rate Q gx ( t ) and the instantaneous water production rate Q wx ( t ).

[0062] S205, use the instantaneous gas production rate in step S204 Q gx ( t ) and the instantaneous water production rate Q wx ( t) Calculate the gas-water ratio of the gas well water WGR ( t )

[0063]

[0064] Among them, is the gas-water ratio of the gas well water, is the instantaneous water production, is the instantaneous gas production.

[0065] S206. Utilize the molecular weights of each component of natural gas M i and the molar composition y i to calculate the average relative molecular weight of natural gas M .

[0066]

[0067] Among them, n is the number of components.

[0068] S207. Utilize the obtained standard condition density of the natural gas gas phase ρ G , and the instantaneous wellhead temperature T x ( t ) and the instantaneous wellhead oil pressure P x ( t ) to calculate the true density of the natural gas gas phase ρ G * ( t ).

[0069]

[0070] Among them, is the true density of the natural gas gas phase, is the instantaneous wellhead oil pressure, is the instantaneous wellhead temperature, is the standard condition density of the natural gas gas phase.

[0071] S208. According to the instantaneous wellhead temperature T x ( t ) and the instantaneous wellhead oil pressure P x ( t ), as well as the average relative molecular weight of natural gas M and the true density of the natural gas gas phase ρ G * ( t ) to calculate the true kinematic viscosity of natural gas .

[0072]

[0073]

[0074]

[0075]

[0076]

[0077] wherein, is the true kinematic viscosity of natural gas, is the dynamic viscosity of the actual working condition of the gas phase of natural gas, is the true density of the gas phase of natural gas. is the first coefficient for calculating the true kinematic viscosity of natural gas, is the second coefficient for calculating the true kinematic viscosity of natural gas, is the third coefficient for calculating the true kinematic viscosity of natural gas.

[0078] S209, using the tubing diameter D , the standard condition density of the liquid phase of natural gas ρ L , the instantaneous wellhead temperature T x ( t ) and the instantaneous wellhead oil pressure P x ( t ) and the instantaneous gas production Q gx ( t ), calculate the true flow velocity of the gas phase of natural gas v * SG ( t ).

[0079]

[0080]

[0081] wherein, is the true flow velocity of the gas phase of natural gas, is the apparent flow velocity of the gas phase of natural gas, is the standard condition density of the gas phase of natural gas, is the standard condition density of the liquid phase of natural gas, is the true density of the liquid phase of natural gas, is the true density of the gas phase of natural gas.

[0082] S210, using the inner diameter of the tubing D , the true kinematic viscosity of natural gas and the true gas-phase flow velocity of natural gas v * SG ( t ), calculate the Reynolds number of the natural gas gas phase .

[0083]

[0084] Among them, is the Reynolds number of the natural gas gas phase, is the true gas-phase flow velocity of natural gas, is the tubing diameter, is the true kinematic viscosity of natural gas.

[0085] S211. Using the gas-liquid ratio of the gas well WGR ( t ) and the Reynolds number of the natural gas gas phase , calculate the dimensionless liquid holdup inside the tubing Q ( t ).

[0086]

[0087] Among them, is the dimensionless liquid holdup inside the tubing, representing the volume ratio of the liquid holdup in the tubing at different times, and can directly reflect the severity of the liquid holdup in the tubing at this time.

[0088] S212. Using the dimensionless liquid holdup inside the tubing Q ( t ), as well as the tubing diameter D and the tubing depth H , calculate the actual liquid content Q * ( t ).

[0089]

[0090] Among them, is the actual liquid content, is the tubing depth.

[0091] The purpose of this application is to overcome the shortcomings of existing critical liquid-carrying flow rate models and liquid accumulation prediction models. By using devices such as wellhead flowmeters and pressure gauges to obtain real-time production parameters such as tubing pressure, casing pressure, gas-phase flow rate, and liquid-phase flow rate, and combining with structural parameters such as medium physical properties and tubing dimensions, a set of calculation methods for the liquid-phase content inside a gas well is independently constructed. Through this method, real-time dynamic monitoring of the liquid accumulation volume inside the gas well tubing is achieved, and on this basis, the gas-phase liquid-carrying capacity is enhanced. In practical applications, the degree of wellbore liquid accumulation is judged according to the calculated liquid accumulation volume, and a liquid accumulation volume change curve is drawn. Subsequently, according to the degree and change trend of the liquid accumulation volume, appropriate drainage gas production measures to be intervened in different production periods of the gas well can be determined to assist the gas well production. Furthermore, appropriate drainage gas production measures can be specifically determined to assist the gas well production, optimize the gas well output, and extend the gas well life.

[0092] The following is an example of using the monitoring method of this application: For a vertical gas well in a certain gas field, the tubing is lowered to a depth of 4280 meters and produced with a tubing having an inner diameter of 50.8 mm. The daily water production, daily gas production, average wellhead pressure, and temperature data are shown in Table 1, and the natural gas component table is shown in Table 2. This example well is used to illustrate the calculation of the wellbore liquid accumulation volume and the process of determining appropriate drainage gas production measures to assist the gas well production.

[0093] Table 1 Production dynamic table of a certain gas well

[0094] Table 2 Natural gas components of a certain gas well

[0095] Obtain a tubing diameter of 50.8 mm and a tubing setting depth of 4280 m; Obtain the molecular weights of each component of natural gas M i and molar composition y i as shown in Table 2; Obtain the density of liquid water as 1000 kg / m 3 , the density of standard-condition natural gas as 0.7174 kg / m 3 , the kinematic viscosity of standard-condition natural gas as 3.1×10 -4 m 2 / s; Taking the first day as an example, the gas production of this gas well is 12632 Nm 3 / d, the on-site water production is 2 Nm 3 / d, the wellhead oil pressure is 9.57 MPa, and the wellhead temperature is 9.57 °C; Calculate the following parameters in sequence: The gas-water ratio of the gas well is: ; The average relative molecular mass of natural gas is: 17.29; The true density of the gas phase of natural gas is: 66.32 kg / m³; The true kinematic viscosity of natural gas is: 2.06×10 -5 m 2 / s; The true flow velocity of the gas phase of natural gas is: 7.78 m / s; The Reynolds number of the gas phase of natural gas is: 19,160; The dimensionless liquid holdup inside the tubing is: 0.29; The actual liquid phase content is: 2.51 m³; According to the above calculation process, the liquid holdup of the proportion of the liquid phase occupying the gas well tubing from the 2nd day to the 17th day can be obtained in sequence, as shown in Table 3.

[0096] Table 3 Liquid holdup of the proportion of the liquid phase occupying the gas well tubing from the 2nd day to the 17th day

[0097] As Figure 3 shown, it is the liquid phase content change curve during the production process of the gas well in this example. It can be seen from Figure 3 that in the early stage of gas well production, the liquid holdup is less and increases steadily and slowly. In the middle and late stages of production, the liquid holdup shows a sudden increase trend. In the later stage, the gas well stops production, and the liquid holdup is serious and remains unchanged. Therefore, on-site personnel can judge whether drainage gas production measures need to be intervened to assist production according to the different change trends of the liquid holdup in different production stages of the gas well.

[0098] As Figure 4 shown, it is a schematic diagram of a real-time monitoring system for liquid holdup in the tubing of a natural gas well in this application, which may include: A data module for real-time collecting the instantaneous wellhead oil pressure, instantaneous wellhead temperature, instantaneous gas production, and instantaneous water production of the natural gas wellhead; A gas-water ratio module for determining the gas-water ratio of the gas well according to the instantaneous gas production and instantaneous water production; A density module for determining the true density of the gas phase of natural gas according to the instantaneous wellhead oil pressure and instantaneous wellhead temperature, combined with the standard condition density of the gas phase of natural gas; A kinematic viscosity module for determining the true kinematic viscosity of natural gas according to the instantaneous wellhead oil pressure and instantaneous wellhead temperature, combined with the average relative molecular mass of natural gas and the true density of the gas phase of natural gas; A flow velocity module for determining the true flow velocity of the gas phase of natural gas according to the tubing diameter, the standard condition density of the corresponding liquid phase of natural gas, the instantaneous wellhead oil pressure, the instantaneous wellhead temperature, and the instantaneous gas production; A Reynolds number module, configured to determine the Reynolds number of the gas phase of natural gas according to the tubing diameter, the true kinematic viscosity of natural gas, and the true gas-phase flow velocity of natural gas; A dimensionless module, configured to determine the dimensionless liquid holdup inside the tubing according to the gas-liquid ratio of gas well water and the Reynolds number of the gas phase of natural gas; A liquid-phase content module, configured to obtain the actual liquid-phase content according to the dimensionless liquid holdup inside the tubing, the tubing diameter, and the tubing depth.

[0099] It should be noted that in several embodiments provided in this application, it should be understood that the disclosed device and method can be implemented in other ways. For example, the system embodiments described above are merely illustrative. For example, the division of each module is only a logical function division. In actual implementation, there may be other division methods. For example, multiple modules can be combined or integrated into another device, or some features can 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 a physical unit or multiple physical units, that is, they may be located in one place or distributed to multiple different places. Some or all of the modules can be selected according to actual needs to achieve the purpose of the solution of this embodiment.

[0100] In addition, in each embodiment of the present invention, each module can be integrated in a processing unit, or each module can exist physically alone, or two or more modules can be integrated in one unit. The above integrated unit can be implemented in the form of hardware or in the form of a software functional unit.

[0101] The above embodiments can be implemented in whole or in part by software, hardware (such as circuits), firmware, or any other combination. When implemented using software, the above embodiments can be implemented in whole or in part in the form of a computer program product. The computer program product includes one or more computer instructions or computer programs. When the computer instructions or computer programs are loaded or executed on a computer, the processes or functions described in the embodiments of the present application are generated in whole or in part. The computer can be a general-purpose computer, a special-purpose computer, a computer network, or other programmable devices. The computer instructions can be stored in a computer-readable storage medium or transmitted from one computer-readable storage medium to another. For example, the computer instructions can be transmitted from one website, computer, server, or data center to another website, computer, server, or data center by wired (such as infrared, wireless, microwave, etc.) means. The computer-readable storage medium can be any available medium that can be accessed by a computer or a data storage device such as a server or data center that contains a set of one or more available media. The available media can be magnetic media (such as floppy disks, hard disks, magnetic tapes), optical media (such as DVDs), or semiconductor media. The semiconductor media can be a solid-state drive.

[0102] The foregoing is only a preferred embodiment of the present application and is not intended to limit the present application. For those skilled in the art, various changes and modifications can be made to the present application. Any modification, equivalent replacement, improvement, etc. made within the spirit and principle of the present application shall be included in the protection scope of the present application.

Claims

1. A real-time monitoring method for the liquid accumulation volume in the tubing of a natural gas well, characterized in that, Including: Real-time collection of the instantaneous wellhead oil pressure, instantaneous wellhead temperature, instantaneous gas production volume, and instantaneous water production volume at the natural gas wellhead; Determine the gas-water ratio of the gas well according to the instantaneous gas production volume and instantaneous water production volume; Determine the true density of the natural gas gas phase according to the instantaneous wellhead oil pressure and instantaneous wellhead temperature, combined with the standard condition density of the natural gas gas phase; Determine the true kinematic viscosity of the natural gas according to the instantaneous wellhead oil pressure and instantaneous wellhead temperature, combined with the average relative molecular mass of the natural gas and the true density of the natural gas gas phase; Determine the true flow velocity of the natural gas gas phase according to the tubing diameter, the standard condition density of the corresponding liquid phase of the natural gas, the instantaneous wellhead oil pressure, the instantaneous wellhead temperature, and the instantaneous gas production volume; Determine the Reynolds number of the natural gas gas phase according to the tubing diameter, the true kinematic viscosity of the natural gas, and the true flow velocity of the natural gas gas phase; Determine the dimensionless liquid holdup inside the tubing according to the gas-water ratio of the gas well and the Reynolds number of the natural gas gas phase; Obtain the actual liquid phase content according to the dimensionless liquid holdup inside the tubing, the tubing diameter, and the tubing depth.

2. The real-time monitoring method for the liquid accumulation amount in the tubing of a natural gas well according to claim 1, characterized in that The method for determining the gas-water ratio of the gas well includes: Among them, is the gas-water ratio of the gas well water, is the instantaneous water production, is the instantaneous gas production.

3. The real-time monitoring method for the liquid accumulation amount in the tubing of a natural gas well according to claim 1, characterized in that The method for determining the true density of the natural gas gas phase includes: Among them, is the true density of natural gas in the gas phase, is the instantaneous wellhead oil pressure, is the instantaneous wellhead temperature, is the standard condition density of natural gas in the gas phase.

4. The real-time monitoring method for the liquid accumulation amount in the tubing of a natural gas well according to claim 1, wherein The method for determining the true kinematic viscosity of the natural gas includes: Among them, is the true kinematic viscosity of natural gas, is the dynamic viscosity of the actual gas phase condition of natural gas, is the true density of the gas phase of natural gas.

5. The real-time monitoring method for the liquid accumulation amount in the tubing of a natural gas well according to claim 1, wherein The method for determining the true flow velocity of the natural gas gas phase includes: Among them, is the true gas-phase flow velocity of natural gas, is the apparent gas-phase flow velocity of natural gas, is the standard-condition density of the gas phase of natural gas, is the standard-condition density of the liquid phase of natural gas, is the true density of the liquid phase of natural gas, is the true density of the gas phase of natural gas.

6. The real-time monitoring method for the liquid accumulation amount in the tubing of a natural gas well according to claim 1, wherein The method for determining the Reynolds number of the natural gas gas phase includes: Among them, is the Reynolds number of the natural gas gas phase, is the true flow velocity of the natural gas gas phase, is the tubing diameter, is the true kinematic viscosity of the natural gas.

7. The real-time monitoring method for the liquid accumulation amount in the tubing of a natural gas well according to claim 1, characterized in that The method for determining the dimensionless liquid holdup inside the tubing includes: Among them, is the dimensionless liquid holdup inside the tubing.

8. The real-time monitoring method for the liquid accumulation amount in the tubing of a natural gas well according to claim 1, characterized in that The method for obtaining the actual liquid phase content includes: Among them, is the actual liquid phase content, is the tubing depth.

9. A real-time monitoring system for the liquid accumulation volume in the tubing of a natural gas well, characterized in that, Including: A data module for real-time collection of the instantaneous wellhead oil pressure, instantaneous wellhead temperature, instantaneous gas production volume, and instantaneous water production volume at the natural gas wellhead; A gas-water ratio module for determining the gas-water ratio of the gas well according to the instantaneous gas production volume and instantaneous water production volume; A density module for determining the true density of the natural gas gas phase according to the instantaneous wellhead oil pressure and instantaneous wellhead temperature, combined with the standard condition density of the natural gas gas phase; A kinematic viscosity module for determining the true kinematic viscosity of the natural gas according to the instantaneous wellhead oil pressure and instantaneous wellhead temperature, combined with the average relative molecular mass of the natural gas and the true density of the natural gas gas phase; A flow velocity module for determining the true flow velocity of the natural gas gas phase according to the tubing diameter, the standard condition density of the corresponding liquid phase of the natural gas, the instantaneous wellhead oil pressure, the instantaneous wellhead temperature, and the instantaneous gas production volume; A Reynolds number module for determining the Reynolds number of the natural gas gas phase according to the tubing diameter, the true kinematic viscosity of the natural gas, and the true flow velocity of the natural gas gas phase; A dimensionless module for determining the dimensionless liquid holdup inside the tubing according to the gas-water ratio of the gas well and the Reynolds number of the natural gas gas phase; A liquid phase content module for obtaining the actual liquid phase content according to the dimensionless liquid holdup inside the tubing, the tubing diameter, and the tubing depth.

10. A computer program product, comprising a computer program, characterized in that, When the computer program is executed by a processor, it implements the real-time monitoring method for the liquid holdup in the tubing of a natural gas well as described in any one of claims 1 to 8.

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