Shale gas horizontal section gas-liquid two-phase flow pattern and pressure drop prediction method and device

Abstract

The invention discloses a shale gas horizontal section gas-liquid two-phase flow pattern and pressure drop prediction method and device, and relates to the technical field of shale gas drainage gas recovery processes, and the method comprises the following steps: obtaining shale gas well basic data; calculating the gas-liquid two-phase flow pressure of the starting point of the horizontal section according to the obtained basic data of the shale gas well; dividing calculation nodes of a horizontal section and determining flow; calculating the internal pressure drop of each node; and calculating the flow pattern in each node. According to the horizontal section pressure drop calculation method, the well track and the gas production profile of the horizontal section of the shale gas well are comprehensively considered, the gas-liquid two-phase flow condition of a shaft can be truly reflected, and the method can be applied to horizontal section pressure prediction; according to the method, the actual situation that the horizontal section flows up and down in the small-angle casing pipe is considered, the horizontal section flow pattern graph is drawn, calculation is simple, convenient and rapid, and the horizontal section gas-liquid two-phase flow pattern can be accurately predicted.

Description

Technical Field

[0001] The present invention relates to the technical field of shale gas drainage and gas production technology, and in particular to a method and device for predicting gas-liquid two-phase flow pattern and pressure drop in a shale gas horizontal section. Background Art

[0002] Shale gas is produced by ultra-long horizontal sections and large-scale hydraulic fracturing, which requires a large amount of fracturing fluid (15,000 to 48,000 m3 in the entire well). 3 ), while shale gas daily production exhibits a typical hyperbolic decline curve. This rapidly declining gas production results in an extremely low fracturing fluid flowback rate, resulting in consistent gas and water production. With deeper shale gas production, the average reservoir pressure gradually decreases, the wellbore's fluid-carrying capacity deteriorates, bottomhole flowing pressure increases, and the production differential pressure decreases. Consequently, shale gas well production deteriorates, resulting in low production, low pressure, and poor production stability. Field wellbore fluid level testing data indicates that approximately 75% of shale gas wells have a dynamic fluid level below the tubing shoe. Therefore, accurately predicting the flow pattern and pressure drop between fracturing fluid and shale gas in horizontal sections is of great practical significance for shale gas production and guiding the design of drainage and gas recovery processes.

[0003] Compared to conventional horizontal wells in gas reservoirs, shale gas horizontal sections are approximately 1,500 to 3,000 meters long. Influenced by the vertical distribution of the shale reservoir, they exhibit a typical updip / downdip macroscopic structure, with a large elevation difference between target points A and B and varying degrees of undulation. Furthermore, shale gas development is performed in a segmented, multi-cluster manner, with each segment contributing significantly to the daily gas and liquid production of a single well. The corresponding wellbore trajectory varies, potentially in slightly concave, slightly convex, or updip locations. This makes it difficult to accurately predict the two-phase flow pattern and pressure drop of the fracturing fluid and shale gas in the horizontal section.

[0004] Currently, long horizontal sections with smaller angles are primarily composed of surface oil and gas pipelines. Comparing wellbore trajectories reveals that the elevation difference of surface pipelines is much smaller than that of horizontal sections in shale gas wells (up to 700 meters). Regarding the fluid medium, surface pipelines primarily flow in a near-pure liquid or pure gas state, while horizontal shale gas sections flow at a high gas-liquid ratio, with gas-liquid replenishment along the way. Therefore, using commonly used engineering analysis methods, it is difficult to predict the two-phase flow state in horizontal sections of shale gas wells.

[0005] Based on indoor simulation experiments, the present invention provides a method and design device for predicting the gas-liquid two-phase flow pattern and pressure drop in the horizontal section of shale gas coupled with the gas production profile, providing a theoretical basis for the production dynamic analysis of shale gas wells and the design of drainage gas production processes. Summary of the Invention

[0006] The present invention aims to provide a method and apparatus for predicting the gas-liquid two-phase flow pattern and pressure drop in a horizontal section of shale gas. This method aims to address the production technology issue of the difficulty in accurately understanding the flow pattern and pressure drop of fracturing fluid and shale gas in horizontal sections. To achieve this objective, the present invention provides the following technical solutions:

[0007] In a first aspect, the present invention provides a method for predicting gas-liquid two-phase flow patterns and pressure drop in a horizontal section of shale gas, the method comprising:

[0008] Obtain basic data of shale gas wells;

[0009] Calculate the gas-liquid two-phase flow pressure at the starting point of the horizontal section based on the acquired shale gas well basic data;

[0010] Horizontal section calculation node division and flow determination;

[0011] Calculate the pressure drop in each node;

[0012] Calculate the flow pattern within each node.

[0013] Furthermore, the basic data includes: wellbore trajectory data, downhole tubing data and production data.

[0014] Furthermore, the calculation formula for the gas-liquid two-phase flow pressure at the starting point of the horizontal section is:

[0015]

[0016] Where p is pressure, Pa; z is depth, m; ρ m is the mixed density, kg / m 3 ; g is the acceleration due to gravity, m / s 2 ; θ is the well inclination angle, °; f is the friction coefficient, dimensionless; v m is the superficial velocity of the gas-liquid mixture, m / s; D is the pipe diameter, m.

[0017] Furthermore, the mixture density ρ m The expression is:

[0018] ρ m =ρ l H L +ρ g (1-H L );

[0019] in,

[0020] Where H L is the liquid holdup, dimensionless; ρ l is the liquid density, kg / m 3 ρ g is the gas density, kg / m 3 ; N l is the dimensionless liquid phase flow rate, dimensionless; N g is the dimensionless gas phase velocity, dimensionless.

[0021] Furthermore, the horizontal segment computing node division and flow determination are specifically as follows:

[0022] The horizontal section is divided into n segments based on the total length of the horizontal section and the length of each segment of the gas production profile. The vertical depth at each node is calculated using the interpolation method. The wellbore trajectory between two adjacent nodes is linearized, and the well inclination angle of the segment is calculated based on the vertical depth of the two adjacent points.

[0023] The gas production proportion of each horizontal section is simplified: the entire gas volume is produced at the middle position of each section; the flow rate of each node is the sum of the total flow rate of the sum of the gas production proportions of each section from target point B to the node.

[0024] Furthermore, the calculation formula for the pressure drop in each node is:

[0025]

[0026] Where P* is the pressure drop, dimensionless; Fr L is the liquid phase Froude number; Fr G is the gas phase Froude number; A and B are experimental coefficients and constants.

[0027] Furthermore, the calculation of the flow pattern within each node is specifically as follows:

[0028] Based on experimental test data, draw the flow pattern diagrams of horizontal flow, upward flow and downward flow in the horizontal section;

[0029] Based on the pressure drop at each node, combined with the bottom hole temperature and gas and liquid flow rates, the gas and liquid apparent flow velocities in each node are calculated, the flow pattern in each node is obtained, and the horizontal section flow pattern diagram is drawn.

[0030] In a second aspect, the present invention provides a device for predicting gas-liquid two-phase flow patterns and pressure drops in a horizontal section of shale gas, the device comprising:

[0031] A basic data acquisition unit, used to acquire basic data of shale gas wells;

[0032] A flow pressure calculation unit is used to calculate the gas-liquid two-phase flow pressure at the starting point of the horizontal section based on the acquired shale gas well basic data;

[0033] Node division and flow determination unit, used for horizontal segment calculation node division and flow determination;

[0034] A pressure drop calculation unit, used to calculate the pressure drop in each node;

[0035] The flow pattern calculation unit is used to calculate the flow pattern in each node.

[0036] In a third aspect, the present invention provides an electronic device, comprising:

[0037] one or more processors;

[0038] a storage device for storing one or more programs;

[0039] When the one or more programs are executed by the one or more processors, the one or more processors implement the above-mentioned method for predicting gas-liquid two-phase flow pattern and pressure drop in the horizontal section of shale gas.

[0040] In a fourth aspect, the present invention provides a storage medium comprising computer-executable instructions, which, when executed by a computer processor, are used to execute the above-mentioned method for predicting gas-liquid two-phase flow pattern and pressure drop in a horizontal section of shale gas.

[0041] Technical effects and advantages of the present invention:

[0042] (1) The horizontal section pressure drop calculation method adopted comprehensively considers the horizontal section wellbore trajectory and gas production profile of shale gas wells, can truly reflect the gas-liquid two-phase flow in the wellbore, and can be used for horizontal section pressure prediction;

[0043] (2) Considering the actual situation of upward and downward flow in the small-angle casing in the horizontal section, a horizontal section flow pattern diagram was drawn. The calculation is simple, convenient and fast, and can accurately predict the gas-liquid two-phase flow pattern in the horizontal section.

[0044] Other features and advantages of the present invention will be described in the following description, and in part will become apparent from the description, or will be understood by practicing the present invention. The purpose and other advantages of the present invention can be realized and obtained by the structures pointed out in the description and the drawings. BRIEF DESCRIPTION OF THE DRAWINGS

[0045] In order to more clearly illustrate the embodiments of the present invention or the technical solutions in the prior art, the following is a brief introduction to the drawings required for use in the embodiments or the description of the prior art. Obviously, the drawings described below are some embodiments of the present invention. For ordinary technicians in this field, other drawings can be obtained based on these drawings without paying any creative work.

[0046] Figure 1 This is a flow chart of a method for predicting gas-liquid two-phase flow pattern and pressure drop in a horizontal section of shale gas according to the present invention;

[0047] Figure 2 A schematic diagram of a wellbore trajectory for an implementation of the present invention;

[0048] Figure 3 Schematic diagram of gas production and cumulative gas production profiles of each horizontal section of a well implementing the present invention;

[0049] Figure 4 This is a schematic diagram of the calculation nodes and gas flow ratios in the horizontal section of an implementation well of the present invention;

[0050] Figure 5 This is a pressure drop distribution diagram of the horizontal section of the well implementing the present invention;

[0051] Figure 6 It is the horizontal pipe flow pattern diagram of the present invention;

[0052] Figure 7 It is the upward flow pattern diagram of the present invention;

[0053] Figure 8 This is a downward flow diagram of the present invention;

[0054] Figure 9 This is a flow pattern distribution diagram of the horizontal section of an example well of the present invention;

[0055] Figure 10 This is a schematic diagram of a device for predicting gas-liquid two-phase flow pattern and pressure drop in a horizontal section of shale gas according to the present invention;

[0056] Figure 11 A schematic diagram of an electronic device provided by the present invention. DETAILED DESCRIPTION

[0057] The following will clearly and completely describe the technical solutions in the embodiments of the present invention in conjunction with the accompanying drawings. Obviously, the described embodiments are only part of the embodiments of the present invention, not all of the embodiments. Based on the embodiments of the present invention, all other embodiments obtained by ordinary technicians in this field without making creative efforts are within the scope of protection of the present invention.

[0058] The present invention provides a method and device for predicting gas-liquid two-phase flow pattern and pressure drop in a horizontal section of shale gas coupled with a gas production profile. Figure 1 The flow chart of the method for predicting gas-liquid two-phase flow pattern and pressure drop in the horizontal section of shale gas of the present invention is as follows: Figure 1 As shown, the method includes the following steps:

[0059] Step S1: Acquire basic data of shale gas wells, including wellbore trajectory data, downhole tubing data, and production data;

[0060] Step S2: Calculating the gas-liquid two-phase flow pressure at the starting point of the horizontal section based on the basic data of the shale gas well obtained in step S1;

[0061] Step S3: Horizontal segment calculation node division and flow determination;

[0062] Step S4: Calculate the pressure drop in each node;

[0063] Step S5: Calculate the flow pattern in each node.

[0064] The technology of the present invention is further described below with reference to embodiments.

[0065] Example:

[0066] Step S1: Acquire basic data of shale gas wells, including wellbore trajectory data, downhole tubing data, and production data.

[0067] 1. Obtain the wellbore trajectory data of a shale gas well and its horizontal section, and collect the gas production and cumulative gas production profiles of each horizontal section.

[0068] Figure 2 Schematic diagram of the wellbore trajectory of the present invention, in which target point A is the starting point of the horizontal section and target point B is the end point of the horizontal section. Figure 2 As shown, the unmarked solid line (corresponding to the Y-axis on the left and the X-axis on the horizontal axis) represents the complete wellbore trajectory from the surface to the gas layer. Fluid flows into the wellbore along the entire horizontal section and flows along this trajectory to the wellhead (surface). The solid dotted line (corresponding to the Y-axis on the right and the X-axis on the horizontal axis) represents a refinement (or magnification) of the entire horizontal section to facilitate visualization of its shape, such as updip or slight concavity.

[0069] Figure 3 Schematic diagram of gas production and cumulative gas production profile of each horizontal section of the well in the present invention, as shown in FIG. Figure 3 As shown in the figure, the horizontal axis of the bar chart represents the specific location of each segment. For example, segment 1 is 0-55m from target A, and the corresponding value is the proportion of the gas production of this segment to the gas production of the well (or the total gas production of all segments). The dotted line chart represents the cumulative gas production percentage: the sum of the gas production of all segments from target B to a certain location, divided by the gas production of the well. For example, the 1622m segment includes 1741-1799m, 1684-1741m, and 1622-1684m, and its cumulative gas production percentage is 0.2 + 6.1 + 2.8 = 9.1.

[0070] 2. Obtain the following downhole tubing data for the shale gas well: casing inner diameter D = 0.125 m, tubing depth L = 4316 m, inner diameter d = 0.05064 m;

[0071] 3. Obtain shale gas well production data: gas production Q g =3.70×104m 3 / d, water production Q l =26m 3 / d、Wellhead oil pressure p wh =2.66MPa, bottom hole temperature t=141.67℃, shale gas relative density 0.5736, liquid density ρ l =1020kg / m 3 wait;

[0072] Step S2: Calculate the gas-liquid two-phase flow pressure at the target point in the horizontal section A.

[0073] Based on the wellbore trajectory data and production data, the gas-liquid two-phase flow pressure at target point A is calculated from the wellhead. The wellbore pressure drop model expression is:

[0074]

[0075] In formula (1), p is pressure, Pa; z is depth, m; ρ m is the mixed density, kg / m 3 ; g is the acceleration due to gravity, m / s 2 ; θ is the well inclination angle, °; f is the friction coefficient, dimensionless, and the friction coefficient f is obtained using the calculation method in the Mukherjee-Brill model; v m is the superficial velocity of the gas-liquid mixture, m / s; D is the pipe diameter, m.

[0076] Mixture density ρ m It is a function of liquid holdup, and its expression is:

[0077] ρ m =ρ l H L +ρ g (1-H L ) (2);

[0078] In formula (2), H L is the liquid holdup, dimensionless, ranging from 0 to H L ≤1;ρ l is the liquid density, kg / m 3 ρ g is the gas density, kg / m 3 .

[0079] The liquid holdup is related to the inclination angle, pipe diameter, superficial liquid velocity, and superficial gas velocity. It is calculated using a new model established using experimental test data:

[0080]

[0081] In formula (3), N l is the dimensionless liquid phase flow rate, dimensionless; N g is the dimensionless gas phase velocity, dimensionless.

[0082] The bottom hole flow pressure of the example well was calculated, that is, the gas-liquid two-phase flow pressure at the target point A in the horizontal section was 11.68 MPa.

[0083] Step S3: Horizontal segment calculation node division and flow determination.

[0084] 1. Based on the total length of the horizontal section and the length of each segment of the gas production profile, select an appropriate step size to divide the horizontal section into n segments. Then, use interpolation to calculate the vertical depth at each node. Linearize the wellbore trajectory between two adjacent nodes and calculate the wellbore inclination angle for that segment based on the vertical depths of the two adjacent points.

[0085] 2. Calculate the traffic at each node:

[0086] First, the gas production ratio of each horizontal section is simplified: the entire gas volume is produced at the middle position of each section.

[0087] Secondly, the flow rate of each node is the sum of the gas production proportions of each section from target point B to the node and all the flow rates.

[0088] The calculation formula for the gas volume at the jth node is:

[0089]

[0090] In formula (4), q gj is the gas volume at the jth node, m 3 / d;q gw is the daily gas production of the shale gas well, m 3 / d;η gi is the gas production ratio of the i-th section, decimal.

[0091] The liquid volume at the jth node is calculated based on the gas-liquid ratio of the entire well:

[0092]

[0093] In formula (5), q Li is the liquid volume at the jth node, m 3 / d;q Lw is the daily liquid production of the shale gas well, m 3 / d.

[0094] The gas and liquid volumes within the distance from the jth node to the j-1th node are taken as the average value of the two adjacent nodes:

[0095] q gj,j-1 =(q gj +q gj-1 ) / 2 (6);

[0096] q Lj,j-1 =(q Lj +q Lj-1 ) / 2 (7);

[0097] In formulas (6) and (7), q gj，j-1 is the average gas volume within the distance from the jth node to the j-1th node, m 3 / d;q Lj，j-1 is the average liquid volume within the distance from the jth node to the j-1th node, m 3 / d.

[0098] Figure 4 This is a schematic diagram of the calculation nodes and gas flow ratios in the horizontal section of the well according to the present invention. Figure 4 As shown, the example well is divided into nodes at 50m, where the position of each node corresponds to Figure 2 Well trajectory diagram of the middle horizontal section, the gas volume ratio in each node corresponds to Figure 3 The proportion of cumulative gas production.

[0099] Step S4: Calculate the pressure drop in each node.

[0100] Using the force balance method, the momentum equation in the inclined tube is established:

[0101]

[0102] In formula (8), dp / dz is the pressure gradient, Pa / m; A p is the cross-sectional area of ​​the pipe, m 2 ; τ WL , τ WG is the shear force between the liquid phase and the gas phase and the tube wall, N / m; S WL 、S WG is the gas phase and liquid phase wetted perimeter, m; A G 、A L is the cross-sectional flow area of ​​the pipe occupied by the gas phase and liquid phase, m 2 ρ L , ρ G are gas phase and liquid phase densities, kg / m 3 ;θ is the tube inclination angle, °.

[0103] Where, τ WL and τ WG It can be expressed as:

[0104]

[0105]

[0106] In formulas (9) and (10), f G 、f L Divided into the Fanning friction coefficient of gas phase and liquid phase, ν G , ν L is the average flow rate of gas and liquid phase, m / s.

[0107] Substitute (9) and (10) into (8), ignoring the gas phase gravity ρ G A G gsinθ and A p =πD 2 / 4, perform dimensionless processing:

[0108]

[0109] Among them, the last term in formula (11) It is only related to factors such as pipe diameter, pipe inclination and liquid flow rate. Low-pressure pipe flow experiments can determine the pipe structure and liquid flow rate, so this item can be regarded as a constant C.

[0110] Introduce the ratio of liquid and gas phase Froude numbers:

[0111]

[0112] In formula (12), Fr L is the liquid phase Froude number; Fr G is the gas phase Froude number.

[0113] Based on the principle of geometric similarity, the dimensionless lengths of the gas and liquid wetted perimeters are defined as:

[0114]

[0115] In formula (13), is the dimensionless number of gas phase wet cycles; is the dimensionless number of liquid phase wetted cycles.

[0116] Define the dimensionless pressure drop P*:

[0117]

[0118] Substituting (12), (13) and (14) into (11), the final relationship between pressure gradient and Froude number is:

[0119]

[0120] That is, dimensionless pressure drop P * The ratio of the gas and liquid Froude numbers is a power law relationship:

[0121]

[0122] Based on indoor simulation experiments, coefficients A and B are taken as 6.3275 and -1.639 respectively.

[0123] According to step S2, the node division is calculated, and target point A is used as the starting point of the terminal pressure. The pressure of each node is calculated in sequence according to the simulated flow direction until target point B.

[0124] Figure 5 The horizontal section pressure drop distribution diagram of the example well of the present invention is as follows: Figure 5 As shown, the pressure drop distribution of the fluid in the wellbore during the flow from target point B to target point A is displayed.

[0125] Step S5: Calculate the flow pattern in each node.

[0126] Based on the experimental test data, the flow pattern diagrams of horizontal flow, upward flow and downward flow in the horizontal section are drawn. Figure 6 is the horizontal pipe flow diagram of the present invention, Figure 7 This is the upward flow diagram of the present invention, Figure 8 is the downward flow diagram of the present invention, such as Figure 6-8 As shown in the figure, each point is the gas phase apparent flow rate and liquid phase apparent flow rate during the experimental test, and the curve is the flow pattern boundary drawn according to the flow pattern observed at each experimental point.

[0127] Based on the pressure drop at each node in step S4, combined with the bottom hole temperature, gas-liquid flow rate, etc., the gas and liquid apparent flow velocities in each node are calculated, the flow pattern in each node is obtained, and a horizontal section flow pattern diagram is drawn.

[0128] Figure 9 This is the flow pattern distribution diagram of the horizontal section of the example well of the present invention, as shown in FIG. Figure 9 As shown, the flow pattern of the fluid in the wellbore flows from target point B to target point A.

[0129] The present invention also provides a device for predicting gas-liquid two-phase flow pattern and pressure drop in a horizontal section of shale gas. Figure 10 This is a schematic diagram of a shale gas horizontal section gas-liquid two-phase flow pattern and pressure drop prediction device of the present invention, as shown in FIG. Figure 10 As shown, the device includes: a basic data acquisition unit 201, used to acquire basic data of shale gas wells; a flow pressure calculation unit 202, used to calculate the gas-liquid two-phase flow pressure of the target point A in the horizontal section based on the acquired basic data of the shale gas wells; a node division and flow determination unit 203, used for node division and flow determination in the horizontal section calculation; a pressure drop calculation unit 204, used to calculate the pressure drop in each node; and a flow pattern calculation unit 205, used to calculate the flow pattern in each node.

[0130] Based on the same inventive concept, the present invention also provides an electronic device, Figure 11 A schematic diagram of an electronic device provided by the present invention, such as Figure 11 As shown, the electronic device includes at least one processor 301, at least one communication interface 302, at least one memory 303 and at least one communication bus 304; wherein the processor 301, the communication interface 302 and the memory 303 communicate with each other via the communication bus 304;

[0131] Memory 303, storing computer programs;

[0132] The processor 301 is configured to implement the method for predicting the gas-liquid two-phase flow pattern and pressure drop in the horizontal section of shale gas when executing the program stored in the memory 303 .

[0133] Optionally, the communication interface may be an interface of a communication module, such as an interface of a GSM module; the processor may be a CPU, or an ASIC (Application Specific Integrated Circuit), or one or more integrated circuits configured to implement the embodiments of the present invention. The memory may include a high-speed RAM memory, and may also include a non-volatile memory, such as at least one disk storage. The memory stores a program, and the processor calls the program stored in the memory to execute some or all of the above-mentioned method embodiments.

[0134] Based on the same inventive concept, the present invention further provides a computer-readable storage medium storing a computer program, wherein when the computer program is executed, some or all of the above-mentioned method embodiments are implemented. Optionally, the storage medium may be a non-transitory computer-readable storage medium, for example, a ROM, a random access memory (RAM), a CD-ROM, a magnetic tape, a floppy disk, an optical data storage device, or the like.

[0135] Finally, it should be noted that the above is only a preferred embodiment of the present invention and is not intended to limit the present invention. Although the present invention has been described in detail with reference to the aforementioned embodiments, those skilled in the art can still modify the technical solutions described in the aforementioned embodiments or make equivalent substitutions for some of the technical features therein. Any modifications, equivalent substitutions, improvements, etc. made within the spirit and principles of the present invention should be included in the scope of protection of the present invention.

Claims

1. A method for predicting gas-liquid two-phase flow pattern and pressure drop in a horizontal section of shale gas, characterized in that: The method comprises: Obtain basic data of shale gas wells; Calculate the gas-liquid two-phase flow pressure at the starting point of the horizontal section based on the acquired shale gas well basic data; Horizontal section calculation node division and flow determination; Calculate the pressure drop in each node; Calculate the flow pattern within each node.

2. The method for predicting gas-liquid two-phase flow pattern and pressure drop in a horizontal section of shale gas according to claim 1, characterized in that: The basic data includes: wellbore trajectory data, downhole tubing data and production data.

3. A method for predicting gas-liquid two-phase flow pattern and pressure drop in a horizontal section of shale gas according to claim 1 or 2, characterized in that: The calculation formula for the gas-liquid two-phase flow pressure at the starting point of the horizontal section is: Where p is pressure, Pa; z is depth, m; ρ m is the mixed density, kg / m 3 ; g is the acceleration due to gravity, m / s 2 ; θ is the well inclination angle, °; f is the friction coefficient, dimensionless; v m is the superficial velocity of the gas-liquid mixture, m / s; D is the pipe diameter, m.

4. The method for predicting gas-liquid two-phase flow pattern and pressure drop in a horizontal section of shale gas according to claim 3, characterized in that: The mixture density ρ m The expression is: r m =ρ l H L +r g (1-H L ); in, Where H L is the liquid holdup, dimensionless; ρ l is the liquid density, kg / m 3 ρ g is the gas density, kg / m 3 ; N l is the dimensionless liquid phase flow rate, dimensionless; N g is the dimensionless gas phase velocity, dimensionless.

5. The method for predicting gas-liquid two-phase flow pattern and pressure drop in a horizontal section of shale gas according to claim 1, characterized in that: The horizontal segment computing node division and flow determination are specifically as follows: The horizontal section is divided into n segments based on the total length of the horizontal section and the length of each segment of the gas production profile. The vertical depth at each node is calculated using the interpolation method. The wellbore trajectory between two adjacent nodes is linearized, and the well inclination angle of the segment is calculated based on the vertical depth of the two adjacent points. The gas production proportion of each horizontal section is simplified: the entire gas volume is produced at the middle position of each section; the flow rate of each node is the sum of the total flow rate of the sum of the gas production proportions of each section from target point B to the node.

6. The method for predicting gas-liquid two-phase flow pattern and pressure drop in a horizontal section of shale gas according to claim 1, characterized in that: The calculation formula for the pressure drop in each node is: Where P* is the pressure drop, dimensionless; Fr L is the liquid phase Froude number; Fr G is the gas phase Froude number; A and B are experimental coefficients and constants.

7. The method for predicting gas-liquid two-phase flow pattern and pressure drop in a horizontal section of shale gas according to claim 1, characterized in that: The calculation of the flow pattern in each node is specifically as follows: Based on experimental test data, draw the flow pattern diagrams of horizontal flow, upward flow and downward flow in the horizontal section; Based on the pressure drop at each node, combined with the bottom hole temperature and gas and liquid flow rates, the gas and liquid apparent flow velocities in each node are calculated, the flow pattern in each node is obtained, and the horizontal section flow pattern diagram is drawn.

8. A device for predicting gas-liquid two-phase flow pattern and pressure drop in horizontal sections of shale gas, characterized in that: The device comprises: A basic data acquisition unit, used to acquire basic data of shale gas wells; A flow pressure calculation unit is used to calculate the gas-liquid two-phase flow pressure at the starting point of the horizontal section based on the acquired shale gas well basic data; Node division and flow determination unit, used for horizontal segment calculation node division and flow determination; A pressure drop calculation unit, used to calculate the pressure drop in each node; The flow pattern calculation unit is used to calculate the flow pattern in each node.

9. An electronic device, characterized in that: include: one or more processors; a storage device for storing one or more programs; When the one or more programs are executed by the one or more processors, the one or more processors implement the shale gas horizontal section gas-liquid two-phase flow pattern and pressure drop prediction method as described in any one of claims 1-7.

10. A storage medium containing computer-executable instructions, characterized in that: When executed by a computer processor, the computer executable instructions are used to execute the method for predicting gas-liquid two-phase flow pattern and pressure drop in a horizontal section of shale gas as described in any one of claims 1 to 7.

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