Method, device and equipment for determining hydrops information of horizontal section of gas well

Abstract

The invention discloses a method, a device and equipment for determining hydrops information of a horizontal section of a gas well. The method comprises the following steps: acquiring gas well data of a target gas well; determining gas phase flow data and liquid phase flow data of a horizontal section of the target gas well according to the gas well data; according to the gas well data, the gas-phase flow data and the liquid-phase flow data, non-slip liquid holding data and transient liquid holding data of the horizontal section of the target gas well are determined; and determining liquid accumulation information of the horizontal section of the target gas well based on the non-slip liquid holding data and the transient liquid holding data. According to the method, the gas phase flow data and the liquid phase flow data of the horizontal section can be calculated based on the gas well data, and a basis is provided for determining the liquid accumulation information of the horizontal section; and the hydrops information of the horizontal section of the target gas well can be determined through the non-slip fluid holding data and the transient fluid holding data, so that the actual production condition of the target gas well can be reflected more truly, and the hydrops information of the horizontal section of the gas well can be determined more accurately and effectively.

Description

Technical Field

[0001] The present application relates to the technical field of gas well drainage and gas production, and in particular to a method, device and equipment for determining liquid accumulation information in a horizontal section of a gas well. Background Art

[0002] Horizontal wells are one of the well types for shale gas production. Compared with conventional gas reservoir horizontal wells, shale gas horizontal wells have ultra-long horizontal sections of 1500 to 3000 meters. Affected by the vertical distribution of shale reservoirs, horizontal wells present an up-dip / down-dip structure. When horizontal well production enters the middle and late stages, the bottom hole flow pressure drops significantly, the production pressure difference decreases, and the gas-liquid carrying capacity gradually decreases. The horizontal well will be in a low-production stage for a long time. The on-site wellbore liquid level measurement data shows that most of the well liquid levels are below the tubing shoe, indicating that due to the complex structure of the horizontal section, low gas production, low pressure and other factors, some gas wells have serious liquid accumulation in the horizontal section. Therefore, it is necessary to accurately determine the location and amount of liquid accumulation in the horizontal section of shale gas wells to facilitate its drainage.

[0003] At present, the research on fluid accumulation in horizontal wells mostly focuses on vertical sections and inclined sections, while there is little research on the influence of complex structures of horizontal sections (upward, downward and undulating) on ​​the gas-liquid two-phase flow law, especially for determining whether fluid accumulation occurs in the horizontal wellbore, as well as the location of the fluid accumulation and its cross-sectional area.

[0004] It can be seen that the existing technology cannot accurately and effectively determine the liquid accumulation information in the horizontal section of the gas well. Summary of the invention

[0005] The purpose of the embodiments of the present application is to provide a method, device and equipment for determining liquid accumulation information in the horizontal section of a gas well, so as to solve the problem that the liquid accumulation information in the horizontal section of a gas well cannot be accurately and effectively determined.

[0006] In order to solve the above technical problems, the first aspect of this specification provides a method for determining liquid accumulation information in a horizontal section of a gas well, comprising:

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

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

[0009] Determining no-slip liquid holding data and transient liquid holding data of a 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] Based on the no-slip liquid holding data and the transient liquid holding data, liquid loading information of the horizontal section of the target gas well is determined.

[0011] In some embodiments, 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 includes:

[0012] Determine the relationship between the flow pressure of the target gas well and the depth of the target gas well based on the well trajectory data, the tubing data and the gas well production data in the gas well data;

[0013] Determining 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;

[0014] 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.

[0015] In some embodiments, determining the non-slip liquid holding 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 includes:

[0016] Based on the tubing data in the gas well data, determining the horizontal liquid holdup when the horizontal section of the target gas well water does not tilt;

[0017] Based on the gas phase flow data, the liquid phase flow data, and the tubing string data, an experimental analysis is performed on the flow process of the target gas well, and flow data during the experimental process is collected;

[0018] Determine, based on the flow data, no-slip liquid holdup 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 data;

[0019] Based on the horizontal liquid holdup, the no-slip liquid holdup data and the inclination angle data of the horizontal section, the relationship between the no-slip liquid holdup, the inclination angle and the horizontal liquid holdup of the horizontal section of the target gas well is determined as the no-slip liquid holdup data.

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

[0021]

[0022]

[0023] Among them, H L(0) represents the horizontal liquid holdup, α represents the angle of the liquid film in the horizontal section of the target gas well, and h L represents the liquid film height of the horizontal section of the target gas well, and D represents the inner diameter of the pipeline of the horizontal section of the target gas well.

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

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

[0026] Among them, a, b, c represent the coefficients of the fitted polynomial, H L(0) represents the horizontal liquid holdup, H L(s) Indicates no slip holdup.

[0027] In some embodiments, determining the transient liquid holding 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 includes:

[0028] Based on the tubing data in the gas well data, a gas-liquid flow model of the target gas well is established;

[0029] 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 holding data of the target gas well.

[0030] In some embodiments, determining the liquid accumulation information of the horizontal section of the target gas well based on the non-slip liquid holding data and the transient liquid holding data includes:

[0031] If the non-slip liquid holding data at any position of the horizontal section of the target gas well is greater than or equal to the transient liquid holding data, then there is no liquid accumulation in the target gas well;

[0032] If the non-slip liquid holding data at any position of the horizontal section of the target gas well is less than the transient liquid holding data, liquid accumulation exists in the target gas well.

[0033] In some embodiments, determining the liquid accumulation information of the horizontal section of the target gas well based on the non-slip liquid holding data and the transient liquid holding data includes:

[0034] When it is determined that the no-slip liquid holding data at the current position of the horizontal section of the target gas well is less than the transient liquid holding data, it is determined that liquid accumulation exists at the current position of the horizontal section of the target gas well;

[0035] The liquid accumulation cross-sectional area at the current position is determined based on the no-slip liquid holding data, the transient liquid holding data, and the tubing string data in the gas well data.

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

[0037]

[0038] Among them, A a represents the cross-sectional area of ​​the effusion, H L(t) represents the transient liquid holdup at the current position at time t, H L(s) represents the non-slip liquid holdup at the current position, and D represents the inner diameter of the pipeline in the horizontal section of the target gas well.

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

[0040] A data acquisition module, used for acquiring gas well data of a target gas well;

[0041] A flow data determination module, used to determine 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;

[0042] a liquid holding data determination module, configured to determine the no-slip liquid holding data and the transient liquid holding 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] 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-slip liquid holding data and the transient liquid holding data.

[0044] The third aspect of this specification provides an electronic device, comprising: a memory and a processor, the processor and the memory are communicatively connected to each other, the memory stores computer instructions, and the processor implements the steps of any one of the methods described in the first aspect by executing the computer instructions.

[0045] A fourth aspect of the present specification provides a computer storage medium, wherein the computer storage medium stores computer program instructions, and when the computer program instructions are executed, the steps of any one of the methods described in the first aspect are implemented.

[0046] The method for determining liquid accumulation information in the horizontal section of a gas well provided in the embodiments of this specification obtains gas well data of a target gas well, determines gas phase flow data and liquid phase flow data of the horizontal section of the target gas well based on the gas well data, and then determines the no-slip 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, and determines the liquid accumulation information of the horizontal section of the target gas well based on the no-slip liquid holding data and the transient liquid holding data. In the present application, after obtaining the gas well data of the target gas well, the gas phase flow data and 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 accumulation information of the horizontal section of the target gas well. After obtaining the gas phase flow data and liquid phase flow data of the horizontal section of the target gas well, the no-slip liquid holding data and transient liquid holding data of the horizontal section of the target gas well can be determined, and then the liquid accumulation information of the horizontal section of the target gas well can be determined through the no-slip liquid holding data and transient liquid holding 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 accumulation information of the horizontal section of the gas well, providing support for the drainage gas production process design of the target gas well. BRIEF DESCRIPTION OF THE DRAWINGS

[0047] In order to more clearly illustrate the implementation methods of the present application or the technical solutions in the prior art, the drawings required for use in the implementation methods or the description of the prior art will be briefly introduced below. Obviously, the drawings described below are only some implementation methods recorded in this application. For ordinary technicians in this field, other drawings can be obtained based on these drawings without paying creative labor.

[0048] Figure 1 It is a schematic diagram of a method for determining liquid accumulation information in a horizontal section of a gas well provided in an embodiment of the present application;

[0049] Figure 2 Shown is a schematic diagram of a wellbore trajectory of a target gas well provided in an embodiment of the present application;

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

[0051] Figure 4 Shown is a schematic diagram of a shale gas wellbore pressure profile provided by an embodiment of the present application;

[0052] Figure 5 Shown is a schematic diagram of a no-slip holdup profile curve provided in an embodiment of the present application;

[0053] Figure 6 Shown is a schematic diagram of a transient liquid holdup profile curve provided in an embodiment of the present application;

[0054] Figure 7 Shown is a schematic diagram of the location of the fluid accumulation provided in an embodiment of the present application;

[0055] Figure 8 Shown is a schematic diagram of a no-slip liquid holdup profile curve and a transient liquid holdup profile curve provided in an embodiment of the present application;

[0056] Fig. 9 It is a schematic diagram of a device for determining liquid accumulation information in a horizontal section of a gas well provided in an embodiment of the present application;

[0057] Fig.10 Shown is a schematic diagram of an electronic device provided in an embodiment of the present application. DETAILED DESCRIPTION

[0058] In order to enable those skilled in the art to better understand the technical solutions in this application, the technical solutions in the embodiments of this application will be clearly and completely described below in conjunction with the drawings in the embodiments of this application. Obviously, the described embodiments are only part of the embodiments of this application, not all of the embodiments. Based on the embodiments in this application, all other embodiments obtained by ordinary technicians in this field without creative work should fall within the scope of protection of this application.

[0059] As mentioned above, current research on liquid accumulation in horizontal wells mostly focuses on vertical and inclined sections, while there is little research on the impact of complex structures of horizontal sections (upward, downward, and undulating) on ​​the gas-liquid two-phase flow laws. In particular, there is a lack of methods to determine whether liquid accumulation occurs in the horizontal wellbore, the location of the liquid accumulation, and its cross-sectional area, making it impossible to accurately and effectively determine the liquid accumulation information in the horizontal section of the gas well.

[0060] In order to solve the above problems, an embodiment of the present application provides a method for determining liquid accumulation information in a horizontal section of a gas well, which specifically includes: acquiring gas well data of a target gas well; determining gas phase flow data and liquid phase flow data of a horizontal section of the target gas well based on the gas well data; determining no-slip 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; and determining liquid accumulation information in the horizontal section of the target gas well based on the no-slip liquid holding data and the transient liquid holding data.

[0061] In this application, after obtaining the gas well data of the target gas well, the gas phase flow data and liquid phase flow data of the horizontal section of the target gas well can be calculated based on the gas well data, providing a basis for determining the liquid accumulation information of the horizontal section of the target gas well. After determining the gas phase flow data and liquid phase flow data of the horizontal section of the target gas well, the non-slip liquid holding data and transient liquid holding data of the horizontal section of the target gas well can be determined, and then the liquid accumulation information of the horizontal section of the target gas well can be determined through the non-slip liquid holding data and transient liquid holding 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 accumulation information of the horizontal section of the gas well, providing support for the design of the drainage gas production process of the target gas well.

[0062] The following is a detailed introduction to the method for determining liquid accumulation information in the horizontal section of a gas well provided in an embodiment of the present application in conjunction with the accompanying drawings.

[0063] Figure 1 FIG. 1 is a schematic diagram of a method for determining liquid accumulation information in a horizontal section of a gas well provided in an embodiment of the present application. Figure 1 As shown, the method may include:

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

[0065] It can be understood that the gas well data of the target gas well may include the borehole trajectory data, tubing data and gas well production data of the target gas well. Among them, the borehole trajectory data may be the path taken by the target gas well from the surface wellhead position to the underground target area. The tubing data may be data related to the downhole tubing of the target gas well, for example, it may include the inner diameter of the casing, the depth of the tubing, the inner diameter of the tubing, etc. The gas well production data may be data collected by the target gas well during the oil and gas production process, for example, it may include the gas production, water production, wellhead oil pressure, bottom hole temperature, liquid density, gas density, etc. of the target gas well. In some embodiments, the tubing data and gas well production data of the target gas well may also include other related data, which is not limited by 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 may be the superficial gas flow rate of the horizontal section of the target gas well, and the liquid phase flow data may be the superficial liquid flow rate of the horizontal section of the target gas well.

[0068] It is understood that the target gas well may include vertical sections and horizontal sections, such as Figure 2The figure shows a schematic diagram of the borehole trajectory of the target gas well provided in the embodiment of the present application. Point C may be the surface wellhead position of the target gas well, target point A and target point B may be two target points of the target gas well, the borehole trajectory between point C and target point A may be the borehole trajectory of the vertical section of the target gas well, and the borehole trajectory between target point A and target point B may be the borehole trajectory of the horizontal section of the target gas well.

[0069] In some embodiments, considering that the horizontal section of the target gas well, including gas well production data, tubing data, etc., is difficult to collect, and the collected data is not accurate and reliable, the embodiments of the present application calculate the flow pressure of target point A through the collected gas well data of the vertical section of the target gas well, and use the flow pressure of target point A as the flow pressure of the horizontal section of the target gas well, and calculate the gas phase flow data and 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, 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 includes:

[0071] Determine the relationship between the flow pressure of the target gas well and the depth of the target gas well based on the well trajectory data, the tubing data and the gas well production data in the gas well data;

[0072] Determining 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] 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.

[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 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 and depth of the target gas well, and then the wellbore trajectory data, tubing data and gas well production data of the target gas well can be combined with the wellbore pressure drop model to obtain the relationship between the flow pressure and depth of the target gas well. The calculation process of the flow pressure of the horizontal section of the target gas well will be further introduced in combination with the wellbore pressure drop model, which will not be repeated here.

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

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

[0078] Determining the natural gas volume fraction of the target gas well based on the temperature in the gas well data and the flow pressure data;

[0079] The gas phase flow velocity data is determined based on the natural gas volume fraction and the liquid production in the gas well data.

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

[0081] In some embodiments, the bottom hole temperature, tubing inner diameter, etc. at different positions in the horizontal section of the target gas well may be different, and thus the superficial gas velocity and the superficial liquid velocity at different positions of the horizontal section obtained based on the calculation may be different. The horizontal section of the target gas well may be divided into multiple sections, the superficial gas velocity and the superficial liquid velocity of each section may be calculated, and the superficial liquid velocity and the superficial gas velocity of the multiple sections may be used 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 sections based on a preset segment length, and the superficial gas flow rate and the superficial liquid flow rate of each section can be calculated. In some embodiments, the horizontal section of the target gas well can be divided into multiple sections based on the position of the production data acquisition device set in the horizontal section of the target gas well, and the superficial gas flow rate and the superficial liquid flow rate of each section 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, etc., and the present application does not limit this.

[0083] S103: Determine the no-slip liquid holding data and the transient liquid holding 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.

[0084] It can be understood that due to the difference in density between oil and gas, during the upward flow of the gas-liquid mixture in the horizontal section of the target gas well, when the gas rising speed is greater than the liquid (crude oil) flow rate, the gas will surpass the liquid. This phenomenon can be called slippage. The embodiment of the present application studies the measured data when liquid accumulation occurs in the gas well and finds that whether liquid accumulation occurs in the gas well, the location of the liquid accumulation, the cross-sectional area of ​​the liquid accumulation 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 present application calculates the no-slip liquid holding data and the transient liquid holding data of the target gas well to determine the liquid accumulation information of the target gas well. Among them, the no-slip liquid holding data can specifically include the no-slip liquid holding rate, the no-slip liquid holding rate can be the liquid holding rate of the liquid in the horizontal section of the target gas well without slippage, the transient liquid holding data can include the transient liquid holding rate of the horizontal section of the target gas well at multiple times, and the transient liquid holding rate can be the liquid holding rate of the horizontal section 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 respectively include the apparent gas velocity and the apparent liquid velocity of each segment. Further, based on the gas well data, the gas phase flow data and the liquid phase flow data, the non-slip liquid holding data and the transient liquid holding data of the horizontal section of the target gas well are determined, including the non-slip liquid holding rates of multiple segments and the transient liquid holding rates of multiple segments at multiple moments. That is, the non-slip liquid holding rate can represent the liquid holding rate of a certain 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 certain segment of the horizontal section of the target gas well at a certain moment.

[0086] In some embodiments, determining the non-slip liquid holding 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 includes:

[0087] Based on the tubing data in the gas well data, determining the horizontal liquid holdup when the horizontal section of the target gas well water does not tilt;

[0088] Based on the gas phase flow data, the liquid phase flow data, and the tubing string data, an experimental analysis is performed on the flow process of the target gas well, and flow data during the experimental process is collected;

[0089] Determine, based on the flow data, no-slip liquid holdup 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 data;

[0090] Based on the horizontal liquid holdup, the no-slip liquid holdup data and the inclination angle data of the horizontal section, the relationship between the no-slip liquid holdup, the inclination angle and the horizontal liquid holdup of the horizontal section of the target gas well is determined as the no-slip liquid holdup 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 wellbore trajectory angle of the horizontal section of the target gas well will change, the inclination angle of the pipeline of the horizontal section of the target gas well will also change. 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, the relationship between the non-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. It can be understood that in the embodiment of the present application, when determining the non-slip liquid holdup of the horizontal section of the target gas well, the change of the inclination angle of the horizontal section of the target gas well is taken into account, so that a more accurate and reliable non-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 inner diameter of the pipeline in the horizontal section of the target gas well. Further, the relationship between the non-slip liquid holdup of the horizontal section of the target gas well and the inclination angle, the liquid film height and the inner diameter of the pipeline can be determined. Among them, the study on the correlation between the horizontal liquid holdup of the target gas well and the liquid film height and the inner diameter of the pipeline in the horizontal section of the target gas well will be described in detail below and will not be repeated here.

[0093] In some embodiments, determining the transient liquid holding 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 includes:

[0094] Based on the tubing 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 holding data of the target gas well.

[0096] In some embodiments, a hexahedral structured grid can be generated based on computational fluid dynamics (CFD) software to divide the global grid and set a boundary layer grid at the pipe wall. A multiphase flow model (e.g., a volume of fluid (VOF) model) and a turbulence model (e.g., an 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 in the horizontal wellbore of the target gas well, and the transient liquid holdup collected during the simulation process is derived.

[0097] S104: Determine liquid accumulation information of the horizontal section of the target gas well based on the no-slip liquid holding data and the transient liquid holding data.

[0098] It can be understood that the liquid accumulation information of the horizontal section of the target gas well may include: whether liquid accumulation occurs in the horizontal section of the target gas well, the location of the liquid accumulation, and the liquid accumulation cross-sectional area. The liquid accumulation cross-sectional area may be understood as the cross-sectional area of ​​the pipeline occupied by the liquid accumulation.

[0099] It can be understood that in the embodiment of the present application, the liquid accumulation information of the horizontal section of the target gas well is determined by the non-slip liquid holding data and transient liquid holding 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 accumulation information of the horizontal section of the gas well, thereby providing support for the drainage gas production 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 accumulation information of the horizontal section of the target gas well may include: whether liquid accumulation occurs in each segment; the position of the segment where liquid accumulation occurs (i.e., the liquid accumulation position), and the liquid accumulation cross-sectional area of ​​the segment where liquid accumulation occurs.

[0101] In some embodiments, determining the liquid accumulation information of the horizontal section of the target gas well based on the non-slip liquid holding data and the transient liquid holding data includes:

[0102] If the non-slip liquid holding data at any position of the horizontal section of the target gas well is greater than or equal to the transient liquid holding data, then there is no liquid accumulation in the target gas well;

[0103] If the non-slip liquid holding data at any position of the horizontal section of the target gas well is less than the transient liquid holding data, liquid accumulation exists in the target gas well.

[0104] In some embodiments, determining the liquid accumulation information of the horizontal section of the target gas well based on the non-slip liquid holding data and the transient liquid holding data includes:

[0105] When it is determined that the no-slip liquid holding data at the current position of the horizontal section of the target gas well is less than the transient liquid holding data, it is determined that liquid accumulation exists at the current position of the horizontal section of the target gas well;

[0106] The liquid accumulation cross-sectional area at the current position is determined based on the no-slip liquid holding data, the transient liquid holding data, and the tubing string data in the gas well data.

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

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

[0109]

[0110] Where p represents the flow pressure of the target gas well in Pa; z represents the depth in m; ρ m It can represent the mixed density of gas-liquid mixture in the target gas well, in kg / m 3 ;θ can represent the well inclination angle, the unit is °; v m It can represent the mixed superficial velocity of the gas-liquid mixture in the target gas well, in m / s; D represents the diameter of the target gas well, in m; g represents the gravitational acceleration, in m / s 2 ; f can represent the friction coefficient, which is dimensionless.

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

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

[0113] Among them, v sg The unit of apparent gas velocity in the vertical section of the target gas well is m / s; v sl It can express the apparent liquid velocity of the vertical section of the target gas well in m / s.

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

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

[0116] Among them, ρ l It can indicate the liquid density of the vertical section of the target gas well in kg / m 3 ρ g It can indicate the gas density of the vertical section of the target gas well in kg / m 3 ;H L It can indicate the liquid holdup in the vertical section of the target gas well.

[0117] In some embodiments, the friction coefficient 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 coefficient f can be expressed by the following formula:

[0118]

[0119]

[0120] Where, e can represent the absolute roughness, dimensionless; D can represent the diameter of the target gas well, in meters; N Re It can represent the no-slip Reynolds number, dimensionless; ρ ns It can express the density of the mixture without slippage in kg / m 3 ;μ ns It can be used to express the viscosity of a mixture without slip, in Pa·s; v m It can represent the mixed superficial velocity of the gas-liquid mixture in the target gas well, in m / s.

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

[0122]

[0123]

[0124]

[0125] Among them, Q g It can represent the gas production of the target gas well in the time period T, in units of 10 4 m 3 / d; B g It can represent the natural gas volume fraction of the target gas well; D can represent; Q l It can represent the liquid production of the target gas well in the T time period, in m 3 / d;t sc 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 of the horizontal section of the target gas well; p sc It can represent atmospheric pressure in MPa; Z can represent the natural gas deviation coefficient.

[0126] The calculation method of the horizontal liquid holdup and the no-slip liquid holdup of the target gas well will be further introduced below with reference to the accompanying drawings.

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

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

[0129] Ignoring the changes in the velocity of the gas and liquid phases along the process and using the force balance method, the momentum equation of the gas and liquid phases can be established, and the following formula is obtained:

[0130]

[0131] Among them, dp / dx can represent the pressure gradient, Pa / m; τ wg It can express the shear force between the gas phase and the tube wall, N / m 2 ; τ wl It can express the shear force between the liquid phase and the tube wall, N / m 2 ; τ i Can express the shear force at the gas-liquid interface, N / m 2 ; S g Can represent the gas phase wetted period, m; S l Can represent the liquid phase wetted perimeter, m; S i It can represent the length of the gas-liquid interface in the pipeline cross section, m; θ can represent the inclination of the pipeline (upward inclination is positive, downward inclination is negative), rad.

[0132] Ignoring the surface tension and the hydrostatic pressure gradient of the liquid phase, the pressure gradient terms in the momentum equations of the two phases are equal. Eliminating the pressure gradient terms based on formula (9) yields the following formula:

[0133]

[0134] When the inclination angle of the horizontal section of the pipeline is 0, that is, the horizontal section of the pipeline is a horizontal pipe, the angle term of formula (10) is 0, and the momentum equation of the horizontal pipe can be obtained as follows:

[0135]

[0136] Among them, some parameters in the above formula can be expressed by the following formula:

[0137]

[0138] Among them, f wg It can represent the gas phase Fanning friction coefficient and can be calculated by the single-term Blasius formula, that is, The Reynolds number Re g =ρ g Dv g / μ g ;f wlIt can represent the liquid phase Fanning friction coefficient and can be calculated by the single-term Blasius formula, that is, Among them, the Reynolds number Re l =ρ l Dv l / μ l ;f i It can represent the Fanning friction coefficient of the gas-liquid interface.

[0139] Combined with Andritsos's study on the condition of pipe diameter less than 127 mm and considering the transition of flow state in horizontal pipe, it is proposed to use the transition superficial gas velocity from laminar flow to wavy flow as the criterion for the Fanning friction coefficient of gas-liquid interface, and then the relationship between the Fanning friction coefficient of gas-liquid interface and the Fanning friction coefficient of gas phase is obtained as follows:

[0140]

[0141] Among them, h L It can represent the liquid film height of the horizontal section of the target gas well, v sgt It can represent the superficial gas velocity when the flow changes from laminar flow to wavy flow.

[0142] Expanding the geometric parameters in the above formula (11), we can find that the geometric parameter S g , S l , S i , A g , A l They are all related to the ratio of the liquid film height to the inner diameter of the pipe. The momentum equation of the horizontal pipe can be expressed as a function of the ratio of the liquid film height to the inner diameter of the pipe, that is, formula (11) can be expressed as:

[0143]

[0144] In some embodiments, combined with the above formula (14), and based on Figure 3 The geometric relationship shown in b can be used to obtain the formula for horizontal liquid holdup, which can be determined by the following formula:

[0145]

[0146] Among them, H L(0) represents the horizontal liquid holdup, α represents the angle of the liquid film in the horizontal section of the target gas well, and h L represents the liquid film height of the horizontal section of the target gas well, and D represents the inner diameter of the pipeline of the horizontal section of the target gas well.

[0147] In some embodiments, a pipeline with a length of less than 10m can be used as the horizontal section of the target gas well. Based on the gas phase flow data and the liquid phase flow data, the flow process of the target gas well is experimentally analyzed, the flow data in the experimental process is collected, and based on the flow data, the non-slip liquid holding 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. Furthermore, based on the horizontal liquid holding rate, the non-slip liquid holding rate data and the inclination angle data of the horizontal section, the horizontal pipe can be used as the reference to fit the correction angle coefficient to obtain the inclined pipe liquid holding rate applicable to the horizontal section of the target gas well. Since the length of the test pipe section of the pipeline is less than 10m, it can be considered that the liquid has no slippage, and the liquid holding rate determined based on the experiment can be used as the non-slip liquid holding rate of the horizontal section of the target gas well.

[0148] In some embodiments, the slip-free liquid holdup of the horizontal section of the target gas well obtained by fitting can be expressed by the following formula:

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

[0150] Among them, a, b, and c represent the coefficients of the fitted polynomial, that is, the coefficients of the tilt angle, and H L(0) represents the horizontal liquid holdup, H L(s) Indicates no slip holdup.

[0151] It can be understood that the above formula (16) is an example of an expression of the no-slip liquid holdup provided in the present application. In other embodiments, the expression of the no-slip liquid holdup may also include a higher-order sinθ term, which is not limited in the present application.

[0152] It can be understood that the non-slippage liquid holding rate provided in the embodiment of the present application takes into account the change in the angle of the wellbore trajectory of the actual horizontal section of the shale gas well, wherein the parameters involved can be obtained by a calculation formula, and the calculation is simple, convenient and fast with high accuracy.

[0153] In some embodiments, the liquid flow rate in the wellbore includes the liquid volume flowing to the wellhead and the liquid volume remaining in the wellbore (dead circulation in the wellbore, not lifted to the wellhead). To determine whether a certain position is filled with liquid, the actual liquid volume at the position and the liquid volume brought to the wellhead can be calculated, wherein the liquid volume divided by the cross-sectional area is the liquid holdup. The actual liquid volume can be characterized by the transient liquid holdup, and the liquid volume brought to the wellhead can be represented by the no-slip liquid holdup.

[0154] In some embodiments, when it is determined that the no-slip liquid holding data of the current position of the horizontal section of the target gas well is less than the transient liquid holding data, it is determined that liquid accumulation exists at the current position of the horizontal section of the target gas well, and the liquid accumulation cross-sectional area is determined by the following formula:

[0155]

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

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

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

[0159] S1. Obtain shale gas well data. Specifically, it may include: shale gas well bore trajectory, downhole string data and gas well production data. Among them, the shale gas well bore trajectory data can be as follows: Figure 2 As shown; Downhole pipe string 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 of the horizontal section, including gas phase flow parameter data and liquid phase flow parameter data. Specifically, it may include calculating the gas-liquid two-phase flow pressure of the horizontal section and calculating the superficial gas velocity and the superficial liquid velocity.

[0161] Specifically, the wellbore pressure drop model of formula (1) to formula (5) in the previous text can be used to describe the relationship between the flow pressure and depth of the gas well, and based on the acquired gas well data, the relationship between the gas-liquid two-phase flow pressure and depth of the shale gas well is constructed, and the following is obtained: Figure 4 A schematic diagram of the shale gas wellbore pressure profile is shown.

[0162] Depend on Figure 4It can be seen that the gas-liquid two-phase flow pressure of shale gas wells gradually decreases with the increasing depth of the gas well, and combined with Figure 2 It can be seen that when the depth of the shale gas well no longer changes, that is, when it is in the horizontal section of the shale gas well, the gas-liquid two-phase flow pressure is basically stable and unchanged. 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 superficial gas flow rate and the superficial liquid flow rate of the horizontal section of the shale gas well can be calculated based on the gas production, water production, bottom hole temperature, liquid density, tubing inner diameter, casing inner diameter and other parameters obtained in step S1 and the calculated gas-liquid two-phase flow pressure of the horizontal section.

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

[0165]

[0166]

[0167] Taking the standard temperature of 20°C as an example, and converting the Celsius temperature into thermodynamic temperature, the natural gas volume fraction B in the above formula (8) is g It can be further expressed as:

[0168]

[0169] Specifically, the superficial gas velocity v of the shale gas well can be calculated based on the above formulas (18) to (20) and combined with the measured data of the horizontal section of the shale gas well: sg and the superficial liquid velocity v sl .

[0170] S3. Calculating the non-slip liquid holding rate of the horizontal section of the shale gas well, which may specifically include:

[0171] (1) Calculate the horizontal liquid holdup of shale gas wells. Figure 3 And the formula (15) derived from the formula is used to calculate the horizontal liquid holdup H of the shale gas well. L(0) .

[0172] (2) After calculating the horizontal liquid holdup of the shale gas well, the horizontal segment of the shale gas well can be simulated by using a pipeline with a length of less than 10 m. Based on the superficial gas velocity v calculated in step S2,sg and the superficial liquid velocity v sl The flow process of shale gas wells was tested based on the liquid holdup rate of horizontal pipes. The flow data during the experiment were collected, and the corresponding no-slip liquid holdup data and its corresponding inclination angle data were calculated. The no-slip liquid holdup H was established by fitting. L(s) The relationship between the tilt angle and the tilt angle is as follows:

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

[0174] Among them, the values ​​-32.56, 7.04 and 10.08 can correspond to the coefficients a, b and c in the above formula (16) respectively. It can be understood that the values ​​in the above formula (21) are only an example in this embodiment, and different values ​​can be taken in other embodiments, or polynomials with more terms and higher powers related to sinθ can be used, and this application does not limit this.

[0175] Based on the above formula (21), combined with the actual inclination angle, liquid film height, pipe inner diameter and other data of the horizontal section of the shale gas well, the non-slip liquid holding rate data of the horizontal section of the shale gas well and the wellbore trajectory data of the shale gas well can be obtained. Figure 5 Schematic diagram of the no-slip liquid holdup profile curve and the wellbore trajectory curve shown. Figure 5 The abscissa in represents the horizontal distance between the horizontal section of the shale gas well and the wellhead, and the ordinate represents the slip-free liquid holding rate of the shale gas well.

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

[0177] S5. Predict the liquid accumulation position and liquid accumulation cross-sectional area of ​​the shale gas well. Specifically, the transient liquid holdup H obtained by simulation can be L(t) With no slip hold-up rate H L(s) By comparing the two, the location of the effusion in the horizontal section is determined, and the cross-sectional area A occupied by the effusion at that location is obtained by calculating the difference between the two formulas (17) above. a .

[0178] In some embodiments, the no-slip liquid holdup profile, the transient liquid holdup profile, and the wellbore trajectory can be plotted in the same graph to obtain Figure 7 The liquid holdup profile curve is shown in Figure 2. Figure 7 As shown in the figure, the horizontal axis represents the horizontal distance between the horizontal section of the shale gas well and the wellhead, and the vertical axis represents the liquid holding rate of the shale gas well. Figure 7 As shown in the figure, based on the positional relationship between the no-slip holdup profile curve and the transient holdup profile curve, if the transient holdup profile curve is judged to be above the no-slip holdup profile curve, it can be determined that there is liquid accumulation at the corresponding position. Figure 7 It can be determined that shale gas wells have liquid accumulation in the horizontal distance range of 1620-1700m and 2040-2110m. The liquid accumulation area can be Figure 7 Shown in the dotted box area.

[0179] After determining the location where liquid accumulation exists in the horizontal section of the shale gas well, the cross-sectional area occupied by the liquid accumulation at that location can be obtained by calculating the difference between the two based on the formula (17) mentioned above. Figure 8 Taking the cross-sectional area occupied by the liquid at the dotted line as an example, the transient liquid holdup H at the dotted line can be calculated L(t) With no slip hold-up rate H L(s) The difference, then multiply by πD 2 / 4, we can get the cross-sectional area occupied by the accumulated fluid at that position.

[0180] The embodiment of the present application also provides a device for determining liquid accumulation information in a horizontal section of a gas well. Fig. 9 The figure shows a schematic diagram of a device for determining liquid accumulation information in a horizontal section of a gas well provided in an embodiment of the present application. Fig. 9 As shown, the device 900 for determining liquid accumulation information in the horizontal section of a gas well may include:

[0181] 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 the liquid phase flow data of the horizontal section of the target gas well according to the gas well data.

[0183] The liquid holding data determination module 903 is used to determine the no-slip liquid holding data and transient liquid holding 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.

[0184] The liquid loading information determination module 904 is configured to determine the liquid loading information of the horizontal section of the target gas well based on the non-slip 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 the liquid accumulation information in the horizontal section of the gas well, and will not be repeated here.

[0186] The present specification also provides a computer storage medium, wherein the computer storage medium stores computer program instructions, and when the computer program instructions are executed, the steps of the method for determining the liquid accumulation information in the horizontal section of the gas well are implemented.

[0187] The present specification also provides a computer program product, comprising a computer program, which, when executed by a processor, implements the steps of the method for determining liquid accumulation information in a horizontal section of a gas well.

[0188] The embodiment of the present invention further provides an electronic device, such as Fig.10 As shown, the electronic device may include a processor 1001 and a memory 1002, wherein the processor 1001 and the memory 1002 may be connected via a bus or other means. Fig.10 The example of connecting through bus is taken in the following.

[0189] The processor 1001 may be a central processing unit (CPU). The processor 1001 may 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 a combination of the above chips.

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

[0191] The memory 1002 may include a program storage area and a data storage area, wherein the program storage area may store an operating system, an application required by at least one function; the data storage area may store data created by the processor 1001, etc. In addition, the memory 1002 may include a high-speed random access memory, and may also include a non-volatile memory, such as at least one disk storage device, a flash memory device, or other non-volatile solid-state storage device. In some embodiments, the memory 1002 may optionally include a memory remotely arranged relative to the processor 1001, and these remote memories may be connected to the processor 1001 via a network. Examples of the above-mentioned network include, but are not limited to, the Internet, an intranet, a local area network, a mobile communication network, and combinations thereof.

[0192] The one or more modules are stored in the memory 1002, and when executed by the processor 1001, the following is performed: Figure 1 The method for determining liquid accumulation information in the horizontal section of a gas well in the illustrated embodiment.

[0193] The specific details of the above electronic device can be understood by referring to the corresponding descriptions and effects in the above method embodiments, and will not be repeated here.

[0194] In some embodiments, the electronic device may be a terminal such as a PC (Personal Computer), a tablet computer, a smart phone, a wearable device, an intelligent robot, etc.; or a server. The server may be an independent physical server, a server cluster or a distributed system composed of multiple physical servers, or a cloud server providing cloud computing services. This application does not limit this.

[0195] The present specification also provides a computer storage medium, wherein the computer storage medium stores computer program instructions, and when the computer program instructions are executed, the steps of the method for determining the liquid accumulation information in the horizontal section of the gas well are implemented.

[0196] The present specification also provides a computer program product, comprising a computer program, which, when executed by a processor, implements the steps of the method for determining liquid accumulation information in a horizontal section of a gas well.

[0197] Those skilled in the art can understand that all or part of the processes in the above-mentioned embodiments can be implemented by instructing the relevant hardware through a computer program, and the program can be stored in a computer-readable storage medium, and when the program is executed, it can include the processes of the embodiments of the above-mentioned methods. Among them, the storage medium can be a disk, an optical disk, 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 memory.

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

[0199] The systems, devices, modules or units described in the above embodiments may be implemented by computer chips or entities, or by products with certain functions.

[0200] For the convenience of description, the above device is described in various units according to their functions. Of course, when implementing the present application, the functions of each unit can be implemented in the same or multiple software and / or hardware.

[0201] It can be known from the description of the above implementation methods that those skilled in the art can clearly understand that the present application can be implemented by means of software plus a necessary general hardware platform. Based on such an understanding, the technical solution of the present application can be essentially or partly contributed to the prior art in the form of a software product, which can be stored in a storage medium such as ROM / RAM, a magnetic disk, an optical disk, etc., and includes several instructions for enabling a computer device (which can be a personal computer, a server, or a network device, etc.) to execute certain parts of the methods of each implementation method of the present application.

[0202] The present application can be used in many general or special computer system environments or configurations, such as personal computers, server computers, handheld or portable devices, tablet devices, multiprocessor systems, microprocessor-based systems, set-top boxes, programmable consumer electronic devices, network PCs, minicomputers, mainframe computers, distributed computing environments including any of the above systems or devices, etc.

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

[0204] Although the present application has been described through embodiments, those skilled in the art will appreciate that there are many modifications and variations to the present application without departing from the spirit of the present application, and it is intended that the appended claims include these modifications and variations without departing from the spirit of the present application.

Claims

1. A method for determining liquid accumulation information in a horizontal section of a gas well, characterized in that: include: Acquire gas well data of a target gas well; Determining gas phase flow data and liquid phase flow data of a horizontal section of the target gas well according to the gas well data; Determining no-slip liquid holding data and transient liquid holding data of a horizontal section of the target gas well according to the gas well data, the gas phase flow data and the liquid phase flow data; Based on the no-slip liquid holding data and the transient liquid holding data, liquid loading information of the horizontal section of the target gas well is determined.

2. The method according to claim 1, characterized in that Determining gas phase flow data and liquid phase flow data of a horizontal section of the target gas well according to the gas well data includes: Determine the relationship between the flow pressure of the target gas well and the depth of the target gas well based on the well trajectory data, the tubing data and the gas well production data in the gas well data; Determining 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; 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.

3. The method according to claim 1, characterized in that Determining the non-slip liquid holding 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, including: Based on the tubing data in the gas well data, determining 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 string data, an experimental analysis is performed on the flow process of the target gas well, and flow data during the experimental process is collected; Determine, based on the flow data, no-slip liquid holdup 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 data; Based on the horizontal liquid holdup, the no-slip liquid holdup data and the inclination angle data of the horizontal section, the relationship between the no-slip liquid holdup, the inclination angle and the horizontal liquid holdup of the horizontal section of the target gas well is determined as the no-slip liquid holdup data.

4. The method according to claim 3, characterized in that The horizontal liquid holdup is determined by the following formula: Among them, H L(0) represents the horizontal liquid holdup, α represents the angle of the liquid film in the horizontal section of the target gas well, and h L represents the liquid film height of the horizontal section of the target gas well, and D represents the inner diameter of the pipeline of the horizontal section of the target gas well.

5. The method according to claim 3, characterized in that: The no-slip holdup is determined by the following formula: H L(s) =H L(0) [1+a(sinθ) 3 +b(sinθ) 2 +csinθ]; Among them, a, b, c represent the coefficients of the fitted polynomial, H L(0) represents the horizontal liquid holdup, H L(s) Indicates no slip holdup.

6. The method according to claim 1, characterized in that Determining liquid accumulation information of a horizontal section of the target gas well based on the non-slippage liquid holding data and the transient liquid holding data includes: When it is determined that the no-slip liquid holding data at the current position of the horizontal section of the target gas well is less than the transient liquid holding data, it is determined that liquid accumulation exists at the current position of the horizontal section of the target gas well; The liquid accumulation cross-sectional area at the current position is determined based on the no-slip liquid holding data, the transient liquid holding data, and the tubing string data in the gas well data.

7. The method according to claim 6, characterized in that The effusion cross-sectional area is determined by the following formula: Among them, A a represents the cross-sectional area of ​​the effusion, H L(t) represents the transient liquid holdup at the current position at time t, H L(s) represents the non-slip liquid holdup at the current position, and D represents the inner diameter of the pipeline in the horizontal section of the target gas well.

8. A device for determining liquid accumulation information in a horizontal section of a gas well, characterized in that: include: A data acquisition module, used for acquiring gas well data of a target gas well; A flow data determination module, used to determine 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; a liquid holding data determination module, configured to determine the no-slip liquid holding data and the transient liquid holding 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; 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-slip liquid holding data and the transient liquid holding data.

9. An electronic device, characterized in that: include: A memory and a processor, wherein the processor and the memory are communicatively connected to each other, the memory stores computer instructions, and the processor implements the steps of the method according to any one of claims 1 to 7 by executing the computer instructions.

10. A computer storage medium, characterized in that: The computer storage medium stores computer program instructions, and when the computer program instructions are executed, the steps of the method according to any one of claims 1 to 7 are implemented.

Images