Method, device and equipment for determining gas well horizontal section liquid loading information

Abstract

The application discloses a method, device and equipment for determining gas well horizontal section liquid loading information. The method comprises the following steps: obtaining gas well data of a target gas well; determining gas phase flow data and liquid phase flow data of the horizontal section of the target gas well according to the gas well data; determining no-slip holdup data and transient holdup data of the horizontal section of the target gas well according to the gas well data, the gas phase flow data and the liquid phase flow data; and determining liquid loading information of the horizontal section of the target gas well based on the no-slip holdup data and the transient holdup data. In the application, the gas phase flow data and the liquid phase flow data of the horizontal section can be calculated based on the gas well data, which provides a basis for determining the liquid loading information of the horizontal section. The liquid loading information of the horizontal section of the target gas well can be determined through the no-slip holdup data and the transient holdup data, which can more truly reflect the actual production situation of the target gas well and can more accurately and effectively determine the liquid loading information of the gas well horizontal section.

Description

TECHNICAL FIELD

[0001] The present application relates to the technical field of gas well drainage gas recovery, and particularly relates to a method, device and equipment for determining liquid loading information of a horizontal section of a gas well. BACKGROUND

[0002] A horizontal well is one of well types for shale gas exploitation. Compared with a conventional gas reservoir horizontal well, a shale gas horizontal well has an ultra-long horizontal section of 1500-3000 m, and is in an up-dip / down-dip structure due to the influence of longitudinal distribution of a shale reservoir. In the middle and later stages of production of the horizontal well, the bottom hole flowing pressure drops significantly, the production pressure difference decreases, and the liquid carrying capacity of gas gradually decreases, so the horizontal well will be in a low production stage for a long time. Field wellbore liquid level measurement data show that most of the well liquid levels are below the tubing shoe, indicating that, due to the influence of various factors such as the complex structure of the horizontal section, low gas production and low pressure, some gas wells have serious liquid loading in the horizontal section. Therefore, it is necessary to accurately determine the liquid loading position and liquid loading amount of the horizontal section of a shale gas well so as to facilitate drainage and recovery.

[0003] At present, the research on liquid loading of a horizontal well is mostly focused on vertical sections and inclined sections, and the influence of the complex structure (up-dip, down-dip and undulation) of the horizontal section on the gas-liquid two-phase flow law is less studied, especially the determination method for judging whether liquid loading occurs in the horizontal section of a wellbore, and the liquid loading position and liquid loading cross-sectional area.

[0004] It can be seen that the prior art cannot accurately and effectively determine the liquid loading information of the horizontal section of a gas well. SUMMARY

[0005] The purpose of the embodiments of the present application is to provide a method, device and equipment for determining liquid loading information of a horizontal section of a gas well, so as to solve the problem of being unable to accurately and effectively determine the liquid loading information of the horizontal section of a gas well.

[0006] To solve the above technical problem, a first aspect of the present specification provides a method for determining liquid loading information of a horizontal section of a gas well, comprising:

[0007] obtaining gas well data of a target gas well;

[0008] determining gas phase flow data and liquid phase flow data of the horizontal section of the target gas well according to the gas well data;

[0009] determining no-slip holdup data and transient holdup data of the horizontal section of the target gas well according to the gas well data, the gas phase flow data and the liquid phase flow data;

[0010] determining liquid loading information of the horizontal section of the target gas well based on the no-slip holdup data and the transient holdup data.

[0011] In some embodiments, determining, according to the gas well data, gas phase flow data and liquid phase flow data of the horizontal section of the target gas well comprises:

[0012] determining, based on the wellbore trajectory data, the pipe string data and the gas well production data in the gas well data, a relationship between flow pressure of the target gas well and depth of the target gas well;

[0013] determining, based on the relationship and the depth of the horizontal section of the target gas well, flow pressure data of the horizontal section of the target gas well;

[0014] determining, based on the flow pressure and the gas well data, the gas phase flow velocity data and the liquid phase flow velocity data.

[0015] In some embodiments, determining, according to the gas well data, the gas phase flow data and the liquid phase flow data, no-slip liquid holdup data of the horizontal section of the target gas well comprises:

[0016] determining, based on the pipe string data in the gas well data, a horizontal liquid holdup rate of the horizontal section of the target gas well when no inclination occurs;

[0017] performing experimental analysis on a flow process of the target gas well based on the gas phase flow data, the liquid phase flow data and the pipe string data, and collecting flow data in the experimental process;

[0018] determining, based on the flow data, no-slip liquid holdup rate data of the target gas well and inclination angle data of the horizontal section of the target gas well corresponding to the no-slip liquid holdup rate data;

[0019] determining, based on the horizontal liquid holdup rate, the no-slip liquid holdup rate data and the inclination angle data of the horizontal section, a relationship between no-slip liquid holdup rate and inclination angle and horizontal liquid holdup rate of the horizontal section of the target gas well as the no-slip liquid holdup data.

[0020] In some embodiments, the horizontal liquid holdup rate is determined by the following formula:

[0021]

[0022]

[0023] wherein H L(0) represents the horizontal liquid holdup rate, a represents an angle corresponding to a liquid film of the horizontal section of the target gas well, h L represents a liquid film height of the horizontal section of the target gas well, and D represents an inner diameter of a pipe of the horizontal section of the target gas well.

[0024] In some embodiments, the no-slip liquid holdup rate is determined by the following formula:

[0025] H L(s) = H L(0) [1 + a(sinθ) 3 + b(sinθ) 2 + c sinθ];

[0026] wherein a, b, c represent the coefficients of the polynomial obtained by fitting, H L(0) represents the horizontal liquid holdup, H L(s) represents the no-slip liquid holdup.

[0027] In some embodiments, according to the gas well data, the gas phase flow data and the liquid phase flow data, determining the transient liquid holdup data of the horizontal section of the target gas well comprises:

[0028] Based on the pipe string data in the gas well data, establishing a gas-liquid flow model of the target gas well;

[0029] Based on the gas-liquid flow model, the gas phase flow data and the liquid phase flow data, simulating the gas-liquid flow process of the target gas well to obtain the transient liquid holdup data of the target gas well.

[0030] In some embodiments, based on the no-slip liquid holdup data and the transient liquid holdup data, determining the liquid loading information of the horizontal section of the target gas well comprises:

[0031] If the no-slip liquid holdup data of any position of the horizontal section of the target gas well is greater than or equal to the transient liquid holdup data, the target gas well does not exist liquid loading;

[0032] If the no-slip liquid holdup data of any position of the horizontal section of the target gas well is less than the transient liquid holdup data, the target gas well exists liquid loading.

[0033] In some embodiments, based on the no-slip liquid holdup data and the transient liquid holdup data, determining the liquid loading information of the horizontal section of the target gas well comprises:

[0034] In the case where it is determined that the no-slip liquid holdup data of the current position of the horizontal section of the target gas well is less than the transient liquid holdup data, it is determined that the current position of the horizontal section of the target gas well exists liquid loading;

[0035] Based on the no-slip liquid holdup data, the transient liquid holdup data and the pipe string data in the gas well data, determining the liquid loading cross-sectional area of the current position.

[0036] In some embodiments, the liquid loading cross-sectional area is determined by the following formula:

[0037]

[0038] wherein, A a represents the cross-sectional area of the liquid accumulation, H L(t) represents the transient liquid holdup of the current position at time t, H L(s) represents the no-slip liquid holdup of the current position, D represents the inner diameter of the pipe of the horizontal section of the target gas well.

[0039] The second aspect of the present specification provides a device for determining liquid accumulation information of a horizontal section of a gas well, comprising:

[0040] a data acquisition module configured to acquire gas well data of a target gas well;

[0041] a flow data determination module configured to determine gas phase flow data and liquid phase flow data of the horizontal section of the target gas well according to the gas well data;

[0042] a liquid holdup data determination module configured to determine no-slip liquid holdup data and transient liquid holdup data of the horizontal section of the target gas well according to the gas well data, the gas phase flow data and the liquid phase flow data;

[0043] a liquid accumulation information determination module configured to determine liquid accumulation information of the horizontal section of the target gas well based on the no-slip liquid holdup data and the transient liquid holdup data.

[0044] The third aspect of the present specification provides an electronic device, comprising a memory and a processor, the processor and the memory are communicatively connected, the memory stores computer instructions, and the processor executes the computer instructions to implement the steps of the method of any one of the first aspect.

[0045] The fourth aspect of the present specification provides a computer storage medium, which stores computer program instructions, and the computer program instructions are executed to implement the steps of the method of any one of the first aspect.

[0046] The method for determining gas well horizontal section liquid loading information provided by the embodiment of the present specification determines the gas phase flow data and liquid phase flow data of the horizontal section of the target gas well according to the gas well data of the target gas well, and then determines the no-slip liquid holdup data and transient liquid holdup data of the horizontal section of the target gas well according to the gas well data, the gas phase flow data and the liquid phase flow data, and determines the liquid loading information of the horizontal section of the target gas well based on the no-slip liquid holdup data and the transient liquid holdup data. In the present application, after the gas well data of the target gas well is obtained, the gas phase flow data and the liquid phase flow data of the horizontal section of the target gas well can be calculated based on the gas well data, which provides a basis for determining the liquid loading information of the horizontal section of the target gas well. After the gas phase flow data and the liquid phase flow data of the horizontal section of the target gas well are determined, the no-slip liquid holdup data and the transient liquid holdup data of the horizontal section of the target gas well can be determined, and then the liquid loading information of the horizontal section of the target gas well is determined through the no-slip liquid holdup data and the transient liquid holdup data of the horizontal section of the target gas well, which can more truly reflect the actual production situation of the target gas well and can more accurately and effectively determine the liquid loading information of the gas well horizontal section, thereby providing support for the drainage gas production process design of the target gas well. BRIEF DESCRIPTION OF DRAWINGS

[0047] In order to more clearly illustrate the technical solutions in the embodiments of the present application or the prior art, the drawings needed to be used in the embodiments or the prior art description will be briefly introduced. Obviously, the drawings in the following description are only some embodiments described in the present application, and other drawings can also be obtained by those skilled in the art without creative labor.

[0048] Figure 1 Fig. 1 shows a schematic diagram of the method for determining gas well horizontal section liquid loading information provided by the embodiment of the present application;

[0049] Figure 2 Fig. 2 shows a schematic diagram of the wellbore trajectory of the target gas well provided by the embodiment of the present application;

[0050] Figure 3 Fig. 3 shows a schematic diagram of the gas-liquid two-phase flow process of the horizontal section of the target gas well provided by the embodiment of the present application;

[0051] Figure 4 Fig. 4 shows a schematic diagram of the wellbore pressure profile of the shale gas well provided by the embodiment of the present application;

[0052] Figure 5 Fig. 5 shows a schematic diagram of the no-slip liquid holdup rate profile curve provided by the embodiment of the present application;

[0053] Figure 6 Fig. 6 shows a schematic diagram of the transient liquid holdup rate profile curve provided by the embodiment of the present application;

[0054] Figure 7 Fig. 3 shows a schematic diagram of the liquid accumulation position provided by the embodiment of the present application;

[0055] Figure 8 Fig. 4 shows a schematic diagram of the no-slip holdup rate profile curve and the transient holdup rate profile curve provided by the embodiment of the present application;

[0056] Figure 9 Fig. 5 shows a schematic diagram of the determination device of the gas well horizontal section liquid accumulation information provided by the embodiment of the present application;

[0057] Figure 10 Fig. 6 shows a schematic diagram of the electronic device provided by the embodiment of the present application. DETAILED DESCRIPTION

[0058] In order to enable persons skilled in the art to better understand the technical solutions in the present application, the technical solutions in the embodiments of the present application will be described clearly and completely below in conjunction with the accompanying drawings in the embodiments of the present application. Obviously, the described embodiments are only some of the embodiments of the present application, but not all the embodiments. Based on the embodiments in the present application, all other embodiments obtained by persons skilled in the art without creative labor should fall within the scope of protection of the present application.

[0059] As described above, at present, the research on the liquid accumulation of the horizontal well is mostly on the vertical section and the inclined section as the research object, and the influence of the complex structure (inclined upward, inclined downward and undulating) of the horizontal section on the gas-liquid two-phase flow law is less researched, especially the determination method of whether the wellbore of the horizontal section has liquid accumulation, the liquid accumulation position and the liquid accumulation cross-sectional area is relatively lacking, and the liquid accumulation information of the horizontal section of the gas well cannot be accurately and effectively determined.

[0060] In order to solve the above problems, the embodiment of the present application provides a determination method of the liquid accumulation information of the horizontal section of a gas well, which specifically comprises: obtaining the gas well data of a target gas well; determining the gas phase flow data and the liquid phase flow data of the horizontal section of the target gas well according to the gas well data; determining the no-slip holdup data and the transient holdup data of the horizontal section of the target gas well according to the gas well data, the gas phase flow data and the liquid phase flow data; and determining the liquid accumulation information of the horizontal section of the target gas well based on the no-slip holdup data and the transient holdup data.

[0061] After the gas well data of the target gas well is acquired in the present application, the gas phase flow data and the liquid phase flow data of the horizontal section of the target gas well can be calculated based on the gas well data, thereby providing a basis for determining the liquid loading information of the horizontal section of the target gas well. After the gas phase flow data and the liquid phase flow data of the horizontal section of the target gas well are determined, the no-slip holdup data and the transient holdup data of the horizontal section of the target gas well can be determined, and then the liquid loading information of the horizontal section of the target gas well can be determined through the no-slip holdup data and the transient holdup data of the horizontal section of the target gas well, so that the actual production situation of the target gas well can be more truly reflected, the liquid loading information of the horizontal section of the gas well can be more accurately and effectively determined, and support can be provided for the drainage gas recovery process design of the target gas well.

[0062] The method for determining the liquid loading information of the horizontal section of the gas well provided by the embodiments of the present application will be described in detail below with reference to the accompanying drawings.

[0063] Figure 1 As shown in the figure, the method for determining the liquid loading information of the horizontal section of the gas well provided by the embodiments of the present application is shown. As shown in the figure, the method can include: Figure 1

[0064] S101: Acquire the gas well data of a target gas well.

[0065] It can be understood that the gas well data of the target gas well can include the well trajectory data, the pipe string data and the gas well production data of the target gas well. The well trajectory data can be the path passed through by the target gas well from the surface wellhead position to the underground target area. The pipe string data can be the data related to the downhole pipe string of the target gas well, which can include, for example, the inner diameter of the pipe sleeve, the depth of the oil pipe, the inner diameter of the oil pipe, etc. The gas well production data can be the data collected in the process of oil and gas production of the target gas well, which can include, for example, the gas production rate, the water production rate, the wellhead oil pressure, the bottom hole temperature, the liquid density, the gas density, etc. of the target gas well. In some embodiments, the pipe string data and the gas well production data of the target gas well can also include other related data, which is not limited in the present application.

[0066] S102: Determine the gas phase flow data and the liquid phase flow data of the horizontal section of the target gas well according to the gas well data.

[0067] It can be understood that the gas phase flow data can be the superficial gas velocity of the horizontal section of the target gas well, and the liquid phase flow data can be the superficial liquid velocity of the horizontal section of the target gas well.

[0068] It can be understood that the target gas well can include a vertical section and a horizontal section, as shown in the figure, Figure 2 ​Fig. 1 shows a schematic diagram of a wellbore trajectory of a target gas well provided by an embodiment of the present application. In the diagram, C represents a surface wellhead position of the target gas well, A and B represent two target points of the target gas well, the wellbore trajectory between C and A represents a vertical section of the target gas well, and the wellbore trajectory between A and B represents a horizontal section of the target gas well.

[0069] In some embodiments, considering that the horizontal section of the target gas well is difficult to collect and the collected data is not accurate and reliable, an embodiment of the present application calculates the flow pressure of the target point A by using the collected gas well data of the vertical section of the target gas well, takes the flow pressure of the target point A as the flow pressure of the horizontal section of the target gas well, and calculates the gas phase flow data and the liquid phase flow data of the horizontal section of the target gas well based on the calculated flow pressure.

[0070] In some embodiments, in step S102, the gas phase flow data and the liquid phase flow data of the horizontal section of the target gas well are determined based on the gas well data, including:

[0071] determining a relationship between the flow pressure of the target gas well and the depth of the target gas well based on the wellbore trajectory data, the string data and the gas well production data in the gas well data;

[0072] determining the flow pressure data of the horizontal section of the target gas well based on the relationship and the depth of the horizontal section of the target gas well;

[0073] determining the gas phase flow velocity data and the liquid phase flow velocity data based on the flow pressure and the gas well data.

[0074] It can be understood that the flow pressure of the target gas well is the mixed flow pressure of the gas-liquid two-phase flow of the target gas well.

[0075] In some embodiments, a wellbore pressure drop model can be used to simulate the relationship between the flow pressure of the target gas well and the depth, and then the wellbore pressure drop model can be combined with the wellbore trajectory data, the string data and the gas well production data of the target gas well to obtain the relationship between the flow pressure of the target gas well and the depth. The calculation process of the flow pressure of the horizontal section of the target gas well based on the wellbore pressure drop model will be further introduced below, and will not be repeated here.

[0076] In some embodiments, the gas phase flow velocity data and the liquid phase flow velocity data are determined based on the flow pressure and the gas well data, including:

[0077] the liquid phase flow velocity data is determined based on the liquid production rate in the gas well data;

[0078] determining, based on the temperature in the gas well data, the flow pressure data, a gas volume fraction of the target gas well;

[0079] determining, based on the gas volume fraction, a liquid production rate in the gas well data, the gas phase flow velocity data.

[0080] It can be understood that after the flow pressure of the horizontal section is calculated, the apparent gas flow rate of the target gas well can be calculated as the gas phase flow velocity data of the target gas well and the apparent liquid flow rate of the target gas well can be calculated as the liquid phase flow velocity data of the target gas well based on the gas well production data of the target gas well. In some embodiments, the apparent gas flow rate and the apparent liquid flow rate can be calculated based on the gas production rate, the water production rate, the bottom hole temperature, the liquid density, the inner diameter of the tubing, the inner diameter of the casing and the flow pressure of the target gas well. The above calculation process will be described in detail below in combination with specific formulas, and will not be repeated here.

[0081] In some embodiments, the bottom hole temperature, the inner diameter of the tubing and the like at different positions in the horizontal section of the target gas well can be different, and the apparent gas flow rate and the apparent liquid flow rate at different positions in the horizontal section calculated based on the calculation can be different. The apparent gas flow rate and the apparent liquid flow rate of each segment can be calculated based on the division of the horizontal section of the target gas well into multiple segments, and the apparent liquid flow rate and the apparent gas flow rate of the multiple segments can be taken as the gas phase flow velocity data and the liquid phase flow velocity data of the horizontal section of the target gas well, respectively.

[0082] In some embodiments, the horizontal section of the target gas well can be divided into multiple segments based on a preset segment length, and the apparent gas flow rate and the apparent liquid flow rate of each segment can be calculated. In some embodiments, the horizontal section of the target gas well can be divided into multiple segments based on the positions of the production data acquisition devices arranged in the horizontal section of the target gas well, and the apparent gas flow rate and the apparent liquid flow rate of each segment can be calculated. In other embodiments, the horizontal section of the target gas well can also be divided based on other information of the horizontal section of the target gas well, such as the inner diameter of the pipe string, and the like, which is not limited in the present application.

[0083] S103: determining, based on the gas well data, the gas phase flow data and the liquid phase flow data, the no-slip liquid holdup data and the transient liquid holdup data of the horizontal section of the target gas well.

[0084] It can be understood that, due to the difference in oil and gas density, when the gas rises faster than the liquid (crude oil) during the upward flow of the gas-liquid mixture in the horizontal section of the target gas well, the gas will pass through the liquid, which can be referred to as slippage. The measured data of the gas well when the liquid loading occurs is studied in the embodiments of the present application, and it is found that whether the liquid loading occurs, the liquid loading position, the liquid loading cross-sectional area and other information are related to the no-slip liquid holding data and the transient liquid holding data of the horizontal section of the gas well. Therefore, the no-slip liquid holding data and the transient liquid holding data of the target gas well are calculated to determine the liquid loading information of the target gas well. The no-slip liquid holding data can specifically include the no-slip liquid holding rate, which can be the liquid holding rate of the target gas well without slippage in the horizontal section. The transient liquid holding data can include the transient liquid holding rate of the target gas well at multiple times, which can be the liquid holding rate of the target gas well at a certain time.

[0085] In some embodiments, the horizontal section of the target gas well is divided into multiple segments, and the calculated gas phase flow velocity data and liquid phase flow velocity data include apparent gas flow rate and apparent liquid flow rate of each segment. Further, the no-slip liquid holding data and the transient liquid holding data of the horizontal section of the target gas well determined according to the gas well data, the gas phase flow data and the liquid phase flow data include no-slip liquid holding rate of multiple segments and transient liquid holding rate of multiple segments at multiple times. That is, the no-slip liquid holding rate can represent the liquid holding rate of a segment of the horizontal section of the target gas well without slippage, and the transient liquid holding rate can represent the liquid holding rate of a segment of the horizontal section of the target gas well at a certain time.

[0086] In some embodiments, the no-slip liquid holding data of the horizontal section of the target gas well is determined according to the gas well data, the gas phase flow data and the liquid phase flow data, including:

[0087] Based on the pipe string data in the gas well data, the horizontal liquid holding rate of the horizontal section of the target gas well when no inclination occurs is determined;

[0088] Based on the gas phase flow data, the liquid phase flow data and the pipe string data, the flow process of the target gas well is analyzed experimentally, and the flow data in the experimental process is collected;

[0089] Based on the flow data, the no-slip liquid holding rate data of the target gas well and the inclination angle data of the horizontal section of the target gas well corresponding to the no-slip liquid holding rate data are determined;

[0090] Based on the horizontal liquid holding rate, the no-slip liquid holding rate data and the inclination angle data of the horizontal section, the relationship between the no-slip liquid holding rate of the horizontal section of the target gas well and the inclination angle and the horizontal liquid holding rate is determined as the no-slip liquid holding data.

[0091] It can be understood that the horizontal liquid holdup can be the liquid holdup when the inclination angle of the horizontal section of the target gas well relative to the horizontal plane is 0. Considering that the actual well trajectory angle of the horizontal section of the target gas well will change, and the inclination angle of the pipe of the horizontal section of the target gas well will also change, the relationship between the no-slip liquid holdup of the target gas well and the inclination angle and the horizontal liquid holdup of the horizontal section of the target gas well can be obtained based on the horizontal liquid holdup when the inclination angle of the horizontal section of the target gas well is 0 and the inclination angle data of the target gas well. It can be understood that in the embodiments of the present application, when the no-slip liquid holdup of the horizontal section of the target gas well is determined, the change of the inclination angle of the horizontal section of the target gas well is considered, and a more accurate and reliable no-slip liquid holdup can be obtained.

[0092] In some embodiments, the horizontal liquid holdup of the target gas well is studied, and it is found that the horizontal liquid holdup of the horizontal section of the target gas well is related to the liquid film height and the pipe inner diameter of the horizontal section of the target gas well, and further, the relationship between the no-slip liquid holdup of the horizontal section of the target gas well and the inclination angle, the liquid film height and the pipe inner diameter can be determined. The study of the relationship between the horizontal liquid holdup of the target gas well and the liquid film height and the pipe inner diameter of the horizontal section of the target gas well will be described in detail below, and will not be repeated here.

[0093] In some embodiments, based on the gas well data, the gas phase flow data and the liquid phase flow data, the transient liquid holdup data of the horizontal section of the target gas well is determined, including:

[0094] Based on the pipe string data in the gas well data, a gas-liquid flow model of the target gas well is established;

[0095] Based on the gas-liquid flow model, the gas phase flow data and the liquid phase flow data, the gas-liquid flow process of the target gas well is simulated to obtain the transient liquid holdup data of the target gas well.

[0096] In some embodiments, based on the Computational Fluid Dynamics (CFD) software, a hexahedral structured grid is generated to divide the global grid and set the boundary layer grid at the pipe wall, a multiphase flow model (for example, the volume of fluid (VOF) model) and a turbulence model (for example, the RNG k-ε model) are selected as the gas-liquid flow model of the target gas well to simulate the gas-liquid two-phase flow process of the wellbore of the horizontal section of the target gas well, and the transient liquid holdup rate collected in the simulation process is derived.

[0097] S104: Based on the no-slip liquid holdup data and the transient liquid holdup data, the liquid loading information of the horizontal section of the target gas well is determined.

[0098] It can be understood that the liquid loading information of the horizontal section of the target gas well can include whether the horizontal section of the target gas well is liquid loading, the position of the liquid loading, and the liquid loading cross-sectional area. The liquid loading cross-sectional area can be understood as the cross-sectional area of the pipeline occupied by the liquid loading.

[0099] It can be understood that, in the embodiments of the present application, the liquid loading information of the horizontal section of the target gas well is determined by using the no-slip liquid holdup data and the transient liquid holdup data of the horizontal section of the target gas well, which can more truly reflect the actual production situation of the target gas well, and can more accurately and effectively determine the liquid loading information of the horizontal section of the gas well, thereby providing support for the drainage gas recovery process design of the target gas well.

[0100] In some embodiments, the horizontal section of the target gas well is divided into multiple segments, and the determined liquid loading information of the horizontal section of the target gas well can include whether each segment is liquid loading, the position of the segment with liquid loading (i.e., the liquid loading position), and the liquid loading cross-sectional area of the segment with liquid loading.

[0101] In some embodiments, the liquid loading information of the horizontal section of the target gas well is determined based on the no-slip liquid holdup data and the transient liquid holdup data, and includes:

[0102] If the no-slip liquid holdup data of any position of the horizontal section of the target gas well is greater than or equal to the transient liquid holdup data, the target gas well does not have liquid loading.

[0103] If the no-slip liquid holdup data of any position of the horizontal section of the target gas well is less than the transient liquid holdup data, the target gas well has liquid loading.

[0104] In some embodiments, the liquid loading information of the horizontal section of the target gas well is determined based on the no-slip liquid holdup data and the transient liquid holdup data, and includes:

[0105] In a case where the no-slip liquid holdup data of the current position of the horizontal section of the target gas well is less than the transient liquid holdup data, it is determined that the current position of the horizontal section of the target gas well has liquid loading.

[0106] Based on the no-slip liquid holdup data, the transient liquid holdup data, and the pipe string data in the gas well data, the liquid loading cross-sectional area of the current position is determined.

[0107] The flow pressure and the gas-liquid two-phase flow parameters of the horizontal section of the target gas well will be further introduced below in combination with the formula.

[0108] In some embodiments, the relationship between the flow pressure and the depth of the target gas well can be simulated by using a wellbore pressure drop model, and the wellbore pressure drop model can be represented by the following formula:

[0109]

[0110] wherein p can represent the flow pressure of the target gas well, in Pa; z can represent the depth, in m; p m may represent the mixture density of the gas-liquid mixture in the target gas well, in kg / m 3 ; θ can represent the inclination angle, in °; v m may represent the mixture superficial velocity of the gas-liquid mixture in the target gas well, in m / s; D represents the pipe diameter of the target gas well, in m; g represents the gravitational acceleration, in m / s 2 ; f can represent the friction factor, dimensionless.

[0111] In some embodiments, the mixture superficial velocity v m of the gas-liquid mixture in the target gas well in the above formula (1) can be represented by the following formula:

[0112] v m = v sg + v sl Formula (2)

[0113] wherein v sg may represent the superficial gas flow velocity of the vertical section of the target gas well, in m / s; v sl may represent the superficial liquid flow velocity of the vertical section of the target gas well, in m / s.

[0114] In some embodiments, the mixture density p m of the gas-liquid mixture in the target gas well in the above formula (1) can be represented by the following formula:

[0115] p m = p l H L + p g (1 - H L ) Formula (3)

[0116] wherein p l may represent the liquid density of the vertical section of the target gas well, in kg / m 3 ; p g may represent the gas density of the vertical section of the target gas well, in kg / m 3 ; H L may represent the liquid holdup of the vertical section of the target gas well.

[0117] In some embodiments, the friction factor f of the target gas well in the above formula (1) can be obtained by using the calculation method in the Mukherjee-Brill model, and the friction factor f can be represented by the following formula:

[0118]

[0119]

[0120] Where e can represent absolute roughness, which is dimensionless; D can represent the pipe diameter of the target gas well, in meters; N Re It can represent the no-slip Reynolds number, which is dimensionless; ρ ns It can represent the density of non-slip mixtures, with units of kg / m³. 3 μ ns It can represent the viscosity of a non-slip mixture, with units of Pa·s; v m It can represent the apparent mixing velocity of the gas-liquid mixture within the target gas well, with units of m / s.

[0121] In some embodiments, the apparent gas flow rate and apparent fluid flow rate can be calculated based on the gas production, water production, bottom hole temperature, fluid density, tubing inner diameter, casing inner diameter, and flow pressure of the target gas well. The apparent gas flow rate v in the horizontal section of the target gas well is also calculated. sg and apparent fluid flow rate v sl It can be determined using the following formula:

[0122]

[0123]

[0124]

[0125] Among them, Q g This can represent the gas production of the target gas well during the time period T, in units of 10. 4 m 3 / d;B g D can represent the natural gas volume fraction of the target gas well; Q can represent... l It can represent the production volume of the target gas well during the time period T, with the unit being m³. 3 / d;t sc t can represent the temperature under standard conditions; t can represent the bottom hole temperature; p can represent the calculated gas-liquid two-phase flow pressure in the horizontal section of the target gas well; p sc It can represent atmospheric pressure, with the unit being MPa; Z can represent the natural gas deviation coefficient.

[0126] The following section, in conjunction with the accompanying drawings, will further explain the calculation methods for the horizontal liquid holdup and the non-slippage liquid holdup of the target gas well.

[0127] Figure 3 The diagram shown is a schematic diagram of the gas-liquid two-phase flow process in the horizontal section of the target gas well pipeline provided in an embodiment of this application.

[0128] like Figure 3As shown in FIG. 1, it can be seen that the gas phase in the horizontal section of the target gas well flows upwards inside the pipe, while the liquid phase mainly flows continuously in the form of a liquid film at the bottom of the pipe, and the shear force of the gas phase with the pipe wall, the shear force of the liquid phase with the pipe wall, and the shear force of the gas-liquid interface are all opposite to the flow direction of the gas-liquid two-phase in the pipe.

[0129] Neglecting the change of the gas and liquid phase velocities along the pipeline and using force balance method, the gas and liquid phase momentum equations can be established, and the following formula is obtained:

[0130]

[0131] wherein dp / dx can represent the pressure gradient, Pa / m; τ wg can represent the shear force of the gas phase with the pipe wall, N / m 2 ; τ wl can represent the shear force of the liquid phase with the pipe wall, N / m 2 ; τ i can represent the shear force of the gas-liquid interface, N / m 2 ; S g can represent the wet perimeter of the gas phase, m; S l can represent the wet perimeter of the liquid phase, m; S i can represent the length of the gas-liquid interface of the pipe cross section, m; and θ can represent the inclination angle of the pipe (positive for upward inclination and negative for downward inclination), rad.

[0132] Without considering the surface tension and the hydrostatic pressure gradient of the liquid phase, the pressure gradient terms in the two-phase momentum equations are equal, and based on formula (9), the pressure gradient term can be eliminated to obtain the following formula:

[0133]

[0134] When the inclination angle of the horizontal section of the pipe is 0, i.e. the horizontal section of the pipe is a horizontal pipe, the angle term of formula (10) is 0, and the momentum equation of the horizontal pipe can be obtained, as shown in the following formula:

[0135]

[0136] In the above formula, some parameters can be represented by the following formula:

[0137]

[0138] wherein f wg can represent the Fanning friction factor of the gas phase, and can be calculated by the single-term Blasius formula, i.e. wherein the Reynolds number Re g = ρ g Dv g / μ g ; f wlThe liquid-phase Fanning friction factor can be represented, and can be calculated by the Blasius formula, i.e. wherein the Reynolds number Re l = p l Dv l / m l ; f i The gas-liquid interface Fanning friction factor can be represented.

[0139] In combination with Andritsos, which considers the horizontal pipe flow regime transition under the condition that the pipe diameter is less than 127 mm, it is proposed to use the transition apparent gas flow rate from stratified flow to wavy flow as the gas-liquid interface Fanning friction factor discrimination standard, and then the relationship between the gas-liquid interface Fanning friction factor and the gas-phase Fanning friction factor is obtained as follows:

[0140]

[0141] wherein h L represents the liquid film height of the horizontal section of the target gas well, and v sgt represents the transition apparent gas flow rate from stratified flow to wavy flow.

[0142] By expanding the geometric parameters in the above formula (11), it can be found that the geometric parameters S g , S l , S i , A g , and A l are all related to the ratio of the liquid film height and the pipe inner diameter. The momentum equation of the horizontal pipe can be represented as a function of the ratio of the liquid film height and the pipe inner diameter, i.e. formula (11) can be represented as:

[0143]

[0144] In some embodiments, in combination with the above formula (14), and based on the geometric relationship shown by b in Figure 3 , the formula of the horizontal liquid holdup can be obtained, and the horizontal liquid holdup can be determined by the following formula:

[0145]

[0146] wherein H L(0) represents the horizontal liquid holdup, a represents the angle corresponding to the liquid film of the horizontal section of the target gas well, h L represents the liquid film height of the horizontal section of the target gas well, and D represents the inner diameter of the pipe of the horizontal section of the target gas well.

[0147] In some embodiments, the horizontal section of the target gas well can be a pipe with a length less than 10 m, and the flow process of the target gas well can be analyzed based on the gas phase flow data and the liquid phase flow data, the flow data in the experimental process can be collected, and based on the flow data, the no-slip holdup rate data of the target gas well and the corresponding inclination angle data of the horizontal section of the target gas well can be determined. Further, based on the horizontal holdup rate, the no-slip holdup rate data and the inclination angle data of the horizontal section, the inclined pipe holdup rate suitable for the horizontal section of the target gas well can be obtained by fitting the correction angle coefficient based on the horizontal pipe.

[0148] In some embodiments, the no-slip holdup rate of the horizontal section of the target gas well obtained by fitting can be represented by the following formula:

[0149] H L(s) =H L(0) [1+a(sinθ) 3 +b(sinθ) 2 +c sinθ] Formula (16)

[0150] Wherein, a, b, c represent the coefficients of the polynomial obtained by fitting, that is, the coefficients of the inclination angle, H L(0) represents the horizontal holdup rate, H L(s) represents the no-slip holdup rate.

[0151] It can be understood that the above formula (16) is an example of the expression of the no-slip holdup rate provided by the present application, and in other embodiments, the expression of the no-slip holdup rate can also include higher power sinθ terms, which are not limited by the present application.

[0152] It can be understood that the no-slip holdup rate provided by the embodiments of the present application considers the change of the well trajectory angle of the actual horizontal section of the shale gas well, wherein the involved parameters can be obtained by calculation formula, which is simple, convenient and fast, and has high accuracy.

[0153] In some embodiments, the liquid flow rate in the wellbore includes the liquid amount flowing to the wellhead and the remaining liquid amount in the wellbore (dead circulation in the wellbore without being lifted to the wellhead), and to determine whether a certain position is liquid-accumulating, the actual liquid amount at the position and the liquid amount brought to the wellhead can be calculated, wherein the liquid amount divided by the cross-sectional area is the holdup rate. The actual liquid amount can be represented by the transient holdup rate, and the liquid amount brought to the wellhead can be represented by the no-slip holdup rate.

[0154] In some embodiments, if the non-slippage fluid holdup data at the current location of the horizontal segment of the target gas well is less than the transient fluid holdup data, it is determined that fluid accumulation exists at the current location of the horizontal segment of the target gas well, and the cross-sectional area of ​​the fluid accumulation is determined by the following formula:

[0155]

[0156] Among them, A a H represents the cross-sectional area of ​​the liquid accumulation. L(t) H represents the transient liquid holdup at the current position at time t. L(s) The non-slippage liquid holdup is indicated by D, and D represents the inner diameter of the horizontal section of the pipeline in the target gas well.

[0157] The following example uses an actual shale gas well as the target gas well. Figure 1 The method for determining the liquid accumulation information in the horizontal section of a gas well will be further introduced.

[0158] The method for determining the liquid accumulation information in the horizontal section of the gas well in this embodiment specifically includes the following steps:

[0159] S1. Obtain shale gas well data. This may include: shale gas wellbore trajectory, downhole tubing data, and well production data. The shale gas wellbore trajectory data can be as follows: Figure 2 As shown; downhole tubing data may include: casing inner diameter D = 0.125m, tubing depth L = 3500m, inner diameter d = 0.05066m; gas well production data may include: gas production Q g =3×10 4 m 3 / d, water production Q l =5m 3 / d、Wellhead oil pressure p wh =5.7MPa, bottom hole temperature t=97.6℃, liquid density ρ l =1000kg / m 3 wait;

[0160] S2. Calculate the gas-liquid two-phase flow parameters in the horizontal section, including gas phase flow parameter data and liquid phase flow parameter data. Specifically, this may include calculating the gas-liquid two-phase flow pressure in the horizontal section, as well as calculating the apparent gas velocity and apparent liquid velocity.

[0161] Specifically, the wellbore pressure drop model using formulas (1) to (5) mentioned above can be used to describe the relationship between the flow pressure and depth of the gas well. Based on the obtained gas well data, the relationship between the gas-liquid two-phase flow pressure and depth of the shale gas well can be constructed, as shown in the figure. Figure 4 A schematic diagram of the pressure profile of a shale gas wellbore.

[0162] Depend on Figure 4It can be seen that the gas-liquid two-phase flow pressure of the shale gas well gradually decreases with the increase of the depth of the shale gas well, and the combination of Figure 2 It can be seen that when the depth of the shale gas well no longer changes, that is, in the horizontal section of the shale gas well, the gas-liquid two-phase flow pressure is basically stable and unchanged, and the pressure value here can be used as the gas-liquid two-phase flow pressure of the horizontal section of the shale gas well.

[0163] After calculating the gas-liquid two-phase flow pressure of the horizontal section of the shale gas well, the apparent gas flow rate and the apparent liquid flow rate of the horizontal section of the shale gas well can be calculated based on the gas production rate, the water production rate, the bottom hole temperature, the liquid density, the inner diameter of the tubing, the inner diameter of the casing and other parameters obtained in step S1 and the calculated horizontal section gas-liquid two-phase flow pressure.

[0164] In this embodiment, the gas production rate and the liquid production rate within one day are taken as an example, and the day is converted into seconds, so that the time T in formula (6) and formula (7) is 24*60*60=86400, and the apparent gas flow rate v sg and the apparent liquid flow rate v sl in formula (6) and formula (7) can be further expressed as:

[0165]

[0166]

[0167] Taking 20℃ as the standard temperature, and converting the Celsius temperature into the thermodynamic temperature, the natural gas volume fraction B g in formula (8) in the foregoing can be further expressed as:

[0168]

[0169] Specifically, the apparent gas flow rate v sg and the apparent liquid flow rate v sl of the shale gas well can be calculated based on the above formula (18)-formula (20) in combination with the measured data of the horizontal section of the shale gas well.

[0170] S3, calculating the no-slip holdup rate of the horizontal section of the shale gas well, specifically can include:

[0171] (1) calculating the horizontal holdup rate of the shale gas well, specifically can combine the full text Figure 3 and formula (15) derived from formula derivation to calculate the horizontal holdup rate H L(0) of the shale gas well.

[0172] (2) after calculating the horizontal holdup rate of the shale gas well, the pipeline with a length less than 10m can be used to simulate the subsection of the horizontal section of the shale gas well, and the apparent gas flow rate vsg and apparent flow rate v sl , the flow process of the shale gas well is based on the horizontal pipe holdup experiment, the flow data in the experiment process is collected, the corresponding no-slip holdup data and the corresponding inclination angle data are calculated, the relationship between the no-slip holdup H L(s) and the inclination angle is fitted and established, which is specifically as follows:

[0173] H L(s) = H L(0) [1-32.56(sinθ) 3 +7.04(sinθ) 2 +10.08sinθ] Formula (21)

[0174] Wherein, the values -32.56, 7.04 and 10.08 can correspond to the coefficients a, b and c in the formula (16) above. It can be understood that the values in the above formula (21) are taken as an example in this embodiment, and different values can be taken in other embodiments, or more terms of sinθ, higher power polynomials can be used, and the present application does not limit this.

[0175] Based on the above formula (21), combined with the actual inclination angle, liquid film height, pipe diameter and other data of the horizontal section of the shale gas well, the no-slip holdup data of the horizontal section of the shale gas well and the well trajectory data of the shale gas well can be obtained, and the specific Figure 5 The schematic diagram of the no-slip holdup profile curve and the well trajectory curve is shown. Figure 5 The horizontal distance of the horizontal section of the shale gas well from the wellhead is represented by the abscissa, and the no-slip holdup of the shale gas well is represented by the ordinate.

[0176] S4, calculate the transient holdup of the horizontal section. Specifically, the global grid can be divided based on the CFD software to generate hexahedral structured grid and set boundary layer grid at the pipe wall, VOF multiphase flow model and RNG k-ε turbulence model are selected to simulate the gas-liquid two-phase flow process of the horizontal section wellbore and export the simulated transient holdup H L(t) , the horizontal section well trajectory and the transient holdup profile are simulated, as shown in Figure 6 .

[0177] S5, predict the liquid accumulation position and liquid accumulation cross-sectional area of the shale gas well. Specifically, the simulated transient holdup H L(t) and the no-slip holdup H L(s) are compared to determine the liquid accumulation position, and the difference between the two is calculated to obtain the cross-sectional area A a occupied by the liquid accumulation at the position by combining the formula (17) above.

[0178] In some embodiments, the non-slippage holdup profile, transient holdup profile, and wellbore trajectory can be plotted on the same graph to obtain... Figure 7 The liquid holdup profile curve shown is as follows. Figure 7 As shown, the horizontal axis represents the horizontal distance of the shale gas well's horizontal section from the wellhead, and the vertical axis represents the shale gas well's liquid holdup. (Reference) Figure 7 As shown, based on the positional relationship between the non-slip liquid holding capacity profile curve and the transient liquid holding capacity profile curve in the figure, that is, if it is determined that the transient liquid holding capacity profile curve is above the non-slip liquid holding capacity profile curve, it can be determined that there is liquid accumulation at the corresponding location. Figure 7 It can be determined that liquid accumulation exists in the shale gas wells within horizontal distances of 1620–1700 m and 2040–2110 m, respectively. The liquid accumulation areas can be described as follows: Figure 7 The area shown is within the dashed box.

[0179] After determining the location of fluid accumulation in the horizontal section of a shale gas well, the cross-sectional area occupied by the fluid at that location can be obtained by calculating the difference between the two values, based on formula (17) mentioned earlier. For example, using... Figure 8 Taking the cross-sectional area occupied by the liquid at the dashed line as an example, the transient liquid holdup H at the dashed line can be calculated. L(t) With no slippage retention rate H L(s) The difference, multiplied by πD 2 / 4 gives the cross-sectional area occupied by the accumulated liquid at that location.

[0180] This application also provides a device for determining liquid accumulation information in the horizontal section of a gas well. Figure 9 The diagram shown is a schematic representation of a device for determining liquid accumulation information in the horizontal section of a gas well, as provided in an embodiment of this application. Figure 9 As shown, the device 900 for determining liquid accumulation information in the horizontal section of the gas well may include:

[0181] The data acquisition module 901 is used to acquire gas well data of the target gas well.

[0182] The flow data determination module 902 is used to determine the gas phase flow data and liquid phase flow data of the horizontal section of the target gas well based on the gas well data.

[0183] The liquid holding data determination module 903 is used to determine the non-slippage liquid holding data and transient liquid holding data of the horizontal section of the target gas well based on the gas well data, the gas phase flow data and the liquid phase flow data.

[0184] The liquid accumulation information determination module 904 is used to determine the liquid accumulation information of the horizontal section of the target gas well based on the non-slippage liquid holding data and the transient liquid holding data.

[0185] The description and functions of the above modules can be understood by referring to the content of the method for determining gas well horizontal section liquid loading information, and will not be described again.

[0186] The present specification also provides a computer storage medium storing computer program instructions, which are executed to implement the steps of the method for determining gas well horizontal section liquid loading information.

[0187] The present specification also provides a computer program product containing a computer program, which is executed by a processor to implement the steps of the method for determining gas well horizontal section liquid loading information.

[0188] The present specification also provides an electronic device, as shown in the accompanying drawings. Figure 10 The electronic device can include a processor 1001 and a memory 1002, wherein the processor 1001 and the memory 1002 can be connected by a bus or other means, Figure 10 for example, by a bus connection.

[0189] The processor 1001 can be a central processing unit (CPU). The processor 1001 can also be other general-purpose processors, digital signal processors (DSP), application specific integrated circuits (ASIC), field programmable gate arrays (FPGA) or other programmable logic devices, discrete gate or transistor logic devices, discrete hardware components, or combinations thereof.

[0190] The memory 1002 is a non-transitory computer readable storage medium, which can be used to store non-transitory software programs, non-transitory computer executable programs and modules, such as the program instructions / modules corresponding to the method for determining gas well horizontal section liquid loading information in the embodiments of the present application. The processor 1001 executes various functions of the processor and data processing by running the non-transitory software programs, instructions and modules stored in the memory 1002, that is, implements the method for determining gas well horizontal section liquid loading information in the above method embodiments.

[0191] The memory 1002 can include a program storage area and a data storage area, where the program storage area can store an operating system, at least one application required by the at least one function, and the like; and the data storage area can store data created by the processor 1001 and the like. In addition, the memory 1002 can include a high-speed random access memory, and can further include a non-transitory memory, such as at least one disk memory device, a flash memory device, or other non-transitory solid-state memory device. In some embodiments, the memory 1002 can optionally include a memory disposed remotely from the processor 1001, which can be connected to the processor 1001 through a network. Examples of the above network include, but are not limited to, the Internet, an intranet, a local area network, a mobile communication network, and a combination thereof.

[0192] The one or more modules are stored in the memory 1002, and when executed by the processor 1001, perform the steps of the method for determining the gas well horizontal section liquid loading information as described above. Figure 1 The method for determining the gas well horizontal section liquid loading information in the illustrated embodiment.

[0193] The above electronic device specific details can be understood in correspondence with the corresponding related descriptions and effects in the above method embodiment, which will not be repeated here.

[0194] In some embodiments, the electronic device can be a terminal such as a PC (Personal Computer), a tablet computer, a smart phone, a wearable device, a smart robot, and the like; or can be a server. The server can be a stand-alone physical server, or can be a server cluster or a distributed system composed of multiple physical servers, or can be a cloud server providing cloud computing services. The present application does not limit this.

[0195] The present specification also provides a computer storage medium storing computer program instructions, which when executed realize the steps of the method for determining the gas well horizontal section liquid loading information described above.

[0196] The present specification also provides a computer program product containing a computer program, which when executed by a processor realizes the steps of the method for determining the gas well horizontal section liquid loading information described above.

[0197] Those skilled in the art can understand that all or part of the processes in the above-mentioned embodiment methods can be completed by instructing the relevant hardware through a computer program. The program can be stored in a computer-readable storage medium, and when the program is executed, the processes of the above-mentioned embodiment methods can be included. The storage medium can be a magnetic disc, an optical disc, a read-only memory (ROM), a random access memory (RAM), a flash memory, a hard disk drive (HDD) or a solid-state drive (SSD), etc. The storage medium can also include a combination of the above-mentioned types of memories.

[0198] Each embodiment in the specification is described in a progressive manner, and the same or similar parts between each embodiment can be referred to each other. Each embodiment focuses on the difference from other embodiments.

[0199] The system, device, module or unit described in the above embodiments can be specifically implemented by a computer chip or entity, or by a product with certain functions.

[0200] For the convenience of description, the above device is described as various units respectively described by functions. Of course, the functions of each unit can be implemented in the same or more software and / or hardware in the implementation of the present application.

[0201] From the above description of the embodiments, those skilled in the art can clearly understand that the present application can be implemented by means of software and the necessary general hardware platform. Based on this understanding, the technical solutions of the present application can be embodied in the form of a software product, which can be stored in a storage medium, such as a ROM / RAM, a magnetic disc, an optical disc, etc., and includes a number of instructions to make a computer device (which can be a personal computer, a server, or a network device, etc.) execute the methods of some parts of the embodiments of the present application.

[0202] The present application can be used in many general or special computer system environments or configurations. For example: personal computers, server computers, handheld devices or portable devices, tablet devices, multi-processor systems, microprocessor-based systems, set-top boxes, programmable consumer electronics, network PCs, small computers, large computers, distributed computing environments including any of the above systems or devices, etc.

[0203] The application can be described in the general context of computer- executable instructions, such as program modules, being executed by a computer. Generally, program modules include routines, programs, objects, components, data structures, etc. that perform particular tasks or implement particular abstract data types. The application can also be practiced in distributed computing environments where tasks are performed by remote processing devices that are linked through a communications network. In this case, program modules can be located in both local and remote computer storage media including memory storage devices.

[0204] While this application has been depicted, described, and is to be understood in connection with specific example embodiments, it will be appreciated that it is in no way limited to these embodiments but rather can admit to any number of modifications and variations. It is therefore desired that the present application be deemed limited only by the scope of the appended claims, which follow and the equivalents thereof.

Claims

1. A method for determining liquid accumulation information in the horizontal section of a gas well, characterized in that, include: Obtain gas well data for the target gas well; Based on the gas well data, determine the gas phase flow data and liquid phase flow data of the horizontal section of the target gas well; Based on the gas well data, the gas phase flow data, and the liquid phase flow data, determine the non-slippage liquid holding data and transient liquid holding data of the horizontal section of the target gas well; Based on the non-slippage fluid holding data and the transient fluid holding data, the fluid accumulation information of the horizontal section of the target gas well is determined; Based on the gas well data, the gas phase flow data, and the liquid phase flow data, determine the non-slippage liquid holding data for the horizontal section of the target gas well, including: Based on the tubing data in the gas well data, determine the horizontal liquid holdup when the horizontal section of the target gas well water does not tilt. Based on the gas phase flow data, the liquid phase flow data, and the tubing data, the flow process of the target gas well is experimentally analyzed, and flow data is collected during the experiment. Based on the flow data, the non-slip liquid holdup data of the target gas well and the inclination angle data of the horizontal section of the target gas well corresponding to the non-slip liquid holdup data are determined. Based on the horizontal liquid holdup rate, the non-slip liquid holdup rate data, and the inclination angle data of the horizontal section, the relationship between the non-slip liquid holdup rate of the horizontal section of the target gas well and the inclination angle and horizontal liquid holdup rate is determined, which is used as the non-slip liquid holdup data. Based on the non-slippage fluid holding data and the transient fluid holding data, the fluid accumulation information of the horizontal section of the target gas well is determined, including: If the non-slippage fluid holding data at the current position of the horizontal section of the target gas well is less than the transient fluid holding data, it is determined that there is fluid accumulation at the current position of the horizontal section of the target gas well. Based on the non-slippage fluid holding data, the transient fluid holding data, and the tubing data in the gas well data, the cross-sectional area of ​​the fluid accumulation at the current location is determined.

2. The method according to claim 1, characterized in that, Based on the gas well data, determine the gas phase flow data and liquid phase flow data of the horizontal section of the target gas well, including: Based on the wellbore trajectory data, tubing data, and gas well production data in the gas well data, the relationship between the flow pressure of the target gas well and the depth of the target gas well is determined. Based on the aforementioned relationship and the depth of the horizontal section of the target gas well, the flow pressure data of the horizontal section of the target gas well are determined; Based on the flow pressure and the gas well data, the gas phase flow velocity data and the liquid phase flow velocity data are determined.

3. The method according to claim 1, characterized in that, The horizontal liquid holdup is determined by the following formula: ； ； in, Indicates the horizontal liquid holdup. This indicates the angle corresponding to the liquid film in the horizontal section of the target gas well. This indicates the liquid film height in the horizontal section of the target gas well. This indicates the inner diameter of the pipe in the horizontal section of the target gas well.

4. The method according to claim 1, characterized in that, The non-slippage liquid retention rate is determined by the following formula: ； Where a, b, and c represent the coefficients of the fitted polynomial. Indicates the horizontal liquid holdup. θ represents the non-slippage liquid holdup, and θ represents the well inclination angle.

5. The method according to claim 1, characterized in that, The cross-sectional area of ​​the accumulated liquid is determined by the following formula: ； in, Indicates the cross-sectional area of ​​the liquid accumulation. This represents the transient liquid holdup at the current position at time t. This indicates the non-slip liquid holdup at the current position. This indicates the inner diameter of the pipe in the horizontal section of the target gas well.

6. A device for determining liquid accumulation information in the horizontal section of a gas well, characterized in that, include: The data acquisition module is used to acquire gas well data of the target gas well; The flow data determination module is used to determine the gas phase flow data and liquid phase flow data of the horizontal section of the target gas well based on the gas well data. The liquid holding data determination module is used to determine the non-slippage liquid holding data and transient liquid holding data of the horizontal section of the target gas well based on the gas well data, the gas phase flow data and the liquid phase flow data; The liquid accumulation information determination module is used to determine the liquid accumulation information of the horizontal section of the target gas well based on the non-slippage liquid holding data and the transient liquid holding data; The non-slippage liquid retention data was determined in the following way: Based on the tubing data in the gas well data, determine the horizontal liquid holdup when the horizontal section of the target gas well water does not tilt. Based on the gas phase flow data, the liquid phase flow data, and the tubing data, the flow process of the target gas well is experimentally analyzed, and flow data is collected during the experiment. Based on the flow data, the non-slip liquid holdup data of the target gas well and the inclination angle data of the horizontal section of the target gas well corresponding to the non-slip liquid holdup data are determined. Based on the horizontal liquid holdup rate, the non-slip liquid holdup rate data, and the inclination angle data of the horizontal section, the relationship between the non-slip liquid holdup rate of the horizontal section of the target gas well and the inclination angle and horizontal liquid holdup rate is determined, which is used as the non-slip liquid holdup data. The fluid accumulation information determination module is specifically used for: If the non-slippage fluid holding data at the current position of the horizontal section of the target gas well is less than the transient fluid holding data, it is determined that there is fluid accumulation at the current position of the horizontal section of the target gas well. Based on the non-slippage fluid holding data, the transient fluid holding data, and the tubing data in the gas well data, the cross-sectional area of ​​the fluid accumulation at the current location is determined.

7. An electronic device, characterized in that, include: A memory and a processor, the processor and the memory being communicatively connected to each other, the memory storing computer instructions, the processor executing the computer instructions to implement the steps of the method according to any one of claims 1 to 5.

8. A computer storage medium, characterized in that, The computer storage medium stores computer program instructions, which, when executed, implement the steps of the method according to any one of claims 1 to 5.

Images