A method for predicting the pressure distribution in a gas-liquid two-phase flow wellbore of a shale gas horizontal well.

Abstract

This invention provides a method for predicting the pressure distribution of a shale gas horizontal well in a gas-liquid two-phase flow wellbore, belonging to the field of oil and gas field development. The method includes: dividing the target shale gas horizontal well into target well sections; performing a detailed simulation of the target well sections to obtain detailed simulation results; determining the functional relationship between the gas-liquid two-phase slip velocity and the average transport rate of the water phase in the target well based on the detailed simulation results of the target well sections; determining the functional relationship between the resistance coefficient and the outlet liquid holdup of the target well based on the detailed simulation results of each target well section; establishing a wellbore control coupling model for the target well based on conservation theorems, the functional relationship between the gas-liquid two-phase slip velocity and the average transport rate of the water phase, and the functional relationship between the resistance coefficient and the outlet liquid holdup; iteratively solving the wellbore control coupling model for the target well; and obtaining the pressure distribution of the shale gas horizontal well based on the iteration results to achieve accurate and efficient pressure distribution prediction.

Description

Technical Field

[0001] This invention relates to the field of oil and gas field development technology, specifically to a method for predicting the pressure distribution of gas-liquid two-phase flow wellbore in shale gas horizontal wells, a computer device, and a computer-readable storage medium. Background Technology

[0002] Due to large-scale hydraulic fracturing, shale gas wells typically produce gas and water simultaneously during production. After water is produced, the flow medium in the horizontal wellbore changes from a single phase to a two-phase flow (gas and water). Compared to single-phase flow, the pressure drop of the two-phase medium in the horizontal wellbore is significant, directly impacting the production quality of the well. Accurately calculating the pressure distribution of the two-phase flow in the horizontal wellbore is crucial for improving the accuracy of shale gas production prediction and is also fundamental for addressing water accumulation in gas wells through methods such as foam drainage and mechanical pumping.

[0003] A review revealed few methods for calculating the pressure distribution in the gas-water two-phase flow tube of shale gas horizontal wells, primarily focusing on empirical formulas, homogeneous flow methods, and direct two-phase flow simulations. Empirical formula methods are highly subjective and prone to significant calculation errors. Homogeneous flow methods simplify the gas and water phases into a uniform miscible fluid, neglecting the flow details of the two phases and failing to accurately describe phenomena such as interphase velocity slippage and flow regime changes. Direct two-phase flow simulations can finely characterize the gas-liquid two-phase flow process in the wellbore, but the computational complexity and high mesh count make it difficult to apply to entire wellbores at the kilometer level, thus hindering the development of an integrated reservoir-wellbore simulation method.

[0004] In summary, existing technologies cannot accurately and efficiently predict the pressure distribution in the wellbore of shale gas horizontal wells with gas-liquid two-phase flow. Summary of the Invention

[0005] To address the aforementioned technical deficiencies, this invention provides a method for predicting the pressure distribution in a shale gas horizontal well using gas-liquid two-phase flow. This method involves dividing the target well into segments to obtain target well sections that meet accuracy requirements. A detailed simulation of each target well section is then performed. Based on the simulation results, the gas-liquid two-phase slip velocity and the gas-liquid two-phase resistance coefficient of the target well are determined. Finally, a wellbore control coupling model is established based on these parameters to solve for the pressure distribution within the wellbore, resulting in efficient and accurate calculations.

[0006] The first aspect of this invention provides a method for predicting the pressure distribution in a shale gas horizontal well with gas-liquid two-phase flow, comprising: The target shale gas horizontal well is divided into multiple well sections. The target well section is selected from the multiple well sections, and a detailed simulation is performed on the target well section to obtain the detailed simulation results of the target well section. Based on the detailed simulation results of the target well section, the functional relationship between the gas-liquid two-phase slip velocity and the average water phase transport rate of the target well is determined, and the functional relationship between the resistance coefficient and the outlet liquid holdup of the target well is determined based on the detailed simulation results of each target well section. Based on the functional relationship between the gas-liquid two-phase slip velocity and the average transport rate of the aqueous phase in the target well, as well as the functional relationship between the resistance coefficient and the outlet liquid holdup in the target well, a wellbore control coupling model for the target well is established. The wellbore control coupling model of the target well is solved iteratively to obtain the iterative results, and the pressure distribution of the shale gas horizontal well is obtained based on the iterative results.

[0007] In this embodiment of the invention, the step of performing a detailed simulation of the target well section to obtain the detailed simulation results of the target well section includes: Multiple sets of fluid parameters for the gas-liquid two-phase fluid in the target well section are set, and smoothed fluid particle dynamics is used to perform a fine simulation of the target well section based on the multiple sets of fluid parameters for the gas-liquid two-phase fluid in the target well section, so as to obtain multiple sets of fine simulation results for the target well section.

[0008] In this embodiment of the invention, each set of detailed simulation results for the target well section includes: average liquid phase transport rate, average gas phase transport rate, inlet pressure of the target well section, outlet pressure of the target well section, and outlet liquid holdup of the target well section.

[0009] In this embodiment of the invention, determining the functional relationship between the gas-liquid two-phase slip velocity and the average water phase transport rate of the target well based on the detailed simulation results of the target well section includes: Based on the average liquid phase transport rate and average gas phase transport rate in each set of detailed simulation results, the gas-liquid two-phase slip velocity corresponding to each set of detailed simulation results is calculated. Based on the gas-liquid two-phase slip velocity corresponding to each set of detailed simulation results and the average liquid phase transport velocity in each set of detailed simulation results, the functional relationship between the gas-liquid two-phase slip velocity and the average water phase transport rate of the target well is obtained by fitting.

[0010] In this embodiment of the invention, determining the functional relationship between the resistance coefficient and the outlet liquid holdup of the target well based on the detailed simulation results of the target well section includes: Based on the inlet pressure and outlet pressure of the target well section in each set of detailed simulation results, the pressure difference corresponding to each set of detailed simulation results is calculated. Based on the outlet liquid holdup of the target well section in each set of detailed simulation results, the average density and average velocity corresponding to each set of detailed simulation results are calculated. Based on the average density and average velocity corresponding to each set of detailed simulation results, as well as the pressure difference corresponding to each set of detailed simulation results, the drag coefficient corresponding to each set of detailed simulation results is calculated. Based on the resistance coefficients corresponding to each set of detailed simulation results and the outlet liquid holdup of the target well section in each set of detailed simulation results, the functional relationship between the resistance coefficient and the outlet liquid holdup of the target well is fitted.

[0011] In this embodiment of the invention, the step of establishing a wellbore control coupling model for the target well based on the functional relationship between the gas-liquid two-phase slip velocity and the average transport rate of the aqueous phase, and the functional relationship between the resistance coefficient and the outlet liquid holdup of the target well, includes: Based on the law of conservation of mass and the functional relationship between the gas-liquid two-phase slip velocity and the average transport rate of the water phase in the target well, the liquid holdup equation of the target well is established. Based on the law of conservation of momentum, the functional relationship between the gas-liquid two-phase slip velocity and the average transport rate of the aqueous phase in the target well, and the functional relationship between the drag coefficient and the outlet liquid holdup of the target well, the miscible flow equation of the target well is established. The liquid holdup equation of the target well is coupled with the miscible flow equation of the target well section to obtain the wellbore control coupling model of the target well.

[0012] In this embodiment of the invention, the liquid holdup equation of the target well is: ; Where A is the cross-sectional area of ​​the well shaft. Let x be the liquid holdup of the target well at position x. The water phase velocity is determined by the functional relationship between the gas-liquid two-phase slip velocity and the average water phase transport rate of the target well.

[0013] In this embodiment of the invention, the miscible flow equation of the target well is: ; ; Where A is the cross-sectional area of ​​the well shaft. It is the mixed phase density. It is the mixed phase velocity. Let P be the momentum of the mixed phase, P be the pressure at position x, and g be the acceleration due to gravity. It is the inclination angle of the well shaft. The wall resistance is determined by the functional relationship between the resistance coefficient of the target well and the outlet liquid holdup.

[0014] In this embodiment of the invention, the iterative solution of the wellbore control coupling model of the target well yields iterative results, and the pressure distribution of the shale gas horizontal well is obtained based on the iterative results, including: Set the pressure and liquid holdup values ​​at a specific location in the target well at the initial time; Based on the first liquid holdup value at a certain location of the target well at the initial time, solve the liquid holdup equation of the target well and calculate the liquid holdup value at the next time at a certain location of the target well at the initial time. Based on the liquid holdup value at a certain location in the target well at the initial time and the pressure value at the initial time, the miscible flow equation of the target well is solved, and the gas phase velocity value at a certain location in the target well at the initial time and the next time is calculated. The miscible flow equation of the target well is solved by the gas phase velocity value at a certain location of the target well at the next time after the initial time, and the pressure value at a certain location of the target well at the next time after the initial time is calculated. Based on the pressure value at a certain location of the target well at the initial moment and the pressure value at the next moment at the same location of the target well, it is determined whether the target well is in a steady state. When the target well is in a steady state, the iterative result is obtained, and the pressure distribution of the shale gas horizontal well is obtained based on the iterative result. In this embodiment of the invention, if the target well is in a steady state, the iteration result is: the pressure value at a certain position of the target well at the next time after the initial time is the final pressure value at that position of the target well, and the pressure distribution of the shale gas horizontal well is obtained based on the final pressure value at that position of the target well. If the target well is not in a steady state, the next time step after the initial time step is used as the initial time step for iterative calculation until the target well is in a steady state.

[0015] In this embodiment of the invention, the method further includes: Calculate the difference between the pressure value at a certain location in the target well at the initial time and the pressure value at the same location in the target well at the next time after the initial time; If the difference is within a preset range, the target well is determined to be in a steady state.

[0016] A second aspect of the present invention provides a computer device, comprising: Memory, which stores computer programs; A processor is used to execute the computer program to implement the method for predicting the pressure distribution of gas-liquid two-phase flow wellbore in shale gas horizontal wells as described above.

[0017] A third aspect of the present invention provides a computer-readable storage medium having a computer program stored thereon, the computer program being executed by a processor to implement the method for predicting the pressure distribution of a gas-liquid two-phase flow wellbore in a shale gas horizontal well as described above. This invention divides the target well into segments to obtain target well sections that meet accuracy requirements. It then performs a detailed simulation of the target well sections and determines the gas-liquid two-phase slip velocity and gas-liquid two-phase resistance coefficient based on the simulation results. Finally, it determines the wellbore control coupling model of the target well based on the gas-liquid two-phase slip velocity and gas-liquid two-phase resistance coefficient to solve the pressure distribution in the wellbore, making the calculation efficient and accurate.

[0018] Other features and advantages of the technical solution of the present invention will be described in detail in the following detailed embodiments section. Attached Figure Description

[0019] The accompanying drawings, which are included to provide a further understanding of the invention and form part of this invention, illustrate exemplary embodiments of the invention and are used to explain the invention, but do not constitute an undue limitation of the invention. In the drawings: Figure 1 This is a flowchart of a method for predicting the pressure distribution in a shale gas horizontal well with gas-liquid two-phase flow, provided in an embodiment of the present invention. Detailed Implementation

[0020] To make the technical solutions and advantages of the embodiments of the present invention clearer, the exemplary embodiments of the present invention will be further described in detail below with reference to the accompanying drawings. Obviously, the described embodiments are only a part of the embodiments of the present invention, and not an exhaustive list of all embodiments. It should be noted that, unless otherwise specified, the embodiments and features in the embodiments of the present invention can be combined with each other.

[0021] In the description of this invention, it should be understood that the terms "center," "longitudinal," "lateral," "length," "width," "thickness," "upper," "lower," "front," "rear," "left," "right," "vertical," "horizontal," "top," "bottom," "inner," and "outer," etc., indicate the orientation or positional relationship based on the orientation or positional relationship shown in the accompanying drawings. They are only for the convenience of describing this invention and simplifying the description, and do not indicate or imply that the device or element referred to must have a specific orientation, or be constructed and operated in a specific orientation. Therefore, they should not be construed as limitations on this invention.

[0022] Furthermore, the terms "first" and "second" are used for descriptive purposes only and should not be construed as indicating or implying relative importance or implicitly specifying the number of technical features indicated. Thus, a feature defined as "first" or "second" may explicitly or implicitly include one or more of that feature. In the description of this invention, "a plurality of" means at least two, such as two, three, etc., unless otherwise explicitly specified.

[0023] In this invention, unless otherwise explicitly specified and limited, terms such as "installation," "connection," "linking," and "fixing" should be interpreted broadly. For example, they can refer to a fixed connection, a detachable connection, or an integral part; they can refer to a mechanical connection, an electrical connection, or a connection that allows communication between them; they can refer to a direct connection or an indirect connection through an intermediate medium; they can refer to the internal communication of two components or the interaction between two components. Those skilled in the art can understand the specific meaning of the above terms in this invention according to the specific circumstances.

[0024] In developing this invention, the inventors discovered that due to large-scale hydraulic fracturing, shale gas wells typically produce gas and water simultaneously during production. After water is produced, the flow medium in the horizontal wellbore changes from a single phase to a two-phase flow (gas and water). Compared to single-phase flow, the pressure drop of the two-phase gas-water medium in the horizontal wellbore is significant, directly impacting the production quality of the horizontal well. Accurately calculating the pressure distribution of the two-phase gas-water flow in the horizontal wellbore is crucial for improving the accuracy of shale gas production prediction and is also fundamental for addressing water accumulation in gas wells through methods such as bubble drainage and mechanical pumping.

[0025] A review of existing methods reveals limited resources for calculating the pressure distribution in the gas-liquid two-phase flow wellbore of shale gas horizontal wells. These methods primarily rely on empirical formulas, homogeneous flow methods, and direct two-phase flow simulations. Empirical formulas are highly subjective and prone to significant calculation errors. Homogeneous flow methods simplify the gas and water phases into a uniform mixed-phase fluid, neglecting the flow details of the two phases and failing to accurately describe phenomena such as interphase velocity slippage and flow regime changes. Direct two-phase flow simulations can precisely characterize the gas-liquid two-phase flow process in the wellbore, but the complex calculations and high mesh counts make it difficult to apply to entire wellbores at the kilometer level, hindering the development of an integrated reservoir-wellbore simulation method. In conclusion, current technologies cannot accurately and efficiently predict the pressure distribution in the gas-liquid two-phase flow wellbore of shale gas horizontal wells.

[0026] To address the aforementioned problems, this invention provides a method for predicting the pressure distribution of a shale gas horizontal well in a gas-liquid two-phase flow wellbore. The method includes: dividing the target shale gas horizontal well into target well sections; performing a detailed simulation of each target well section to obtain detailed simulation results; determining the functional relationship between the gas-liquid two-phase slip velocity and the average transport rate of the aqueous phase in the target well based on the detailed simulation results of each target well section; determining the functional relationship between the resistance coefficient and the outlet liquid holdup of the target well based on the detailed simulation results of each target well section; establishing a wellbore control coupling model for the target well based on conservation laws, the functional relationship between the gas-liquid two-phase slip velocity and the average transport rate of the aqueous phase, and the functional relationship between the resistance coefficient and the outlet liquid holdup of the target well; iteratively solving the wellbore control coupling model for the target well; and obtaining the pressure distribution of the shale gas horizontal well based on the iteration results. The method divides the target well into segments to obtain target well sections that meet the accuracy requirements, performs fine simulation on the target well sections, determines the gas-liquid two-phase slip velocity and gas-liquid two-phase resistance coefficient of the target well based on the fine simulation results of the target well sections, and determines the wellbore control coupling model of the target well based on the gas-liquid two-phase slip velocity and gas-liquid two-phase resistance coefficient of the target well to solve the pressure distribution of the wellbore, making the calculation efficient and accurate.

[0027] Figure 1 This is a flowchart of a method for predicting the pressure distribution in a shale gas horizontal well using a two-phase flow, provided in an embodiment of the present invention. For example... Figure 1 As shown in this embodiment, a method for predicting the pressure distribution in a shale gas horizontal well with gas-liquid two-phase flow includes: S1. Divide the target shale gas horizontal well into multiple well sections, select the target well section from the multiple well sections, perform a fine simulation on the target well section, and obtain the fine simulation results of the target well section; S2. Based on the detailed simulation results of the target well section, determine the functional relationship between the gas-liquid two-phase slip velocity and the average water phase transport rate of the target well, and based on the detailed simulation results of each target well section, determine the functional relationship between the resistance coefficient and the outlet liquid holdup of the target well. S3. Based on the functional relationship between the gas-liquid two-phase slip velocity and the average transport rate of the aqueous phase in the target well, and the functional relationship between the resistance coefficient and the outlet liquid holdup of the target well, establish a wellbore control coupling model for the target well. S4. Iteratively solve the wellbore control coupling model of the target well to obtain the iterative results, and obtain the pressure distribution of the shale gas horizontal well based on the iterative results.

[0028] In step S1, the detailed simulation of the target well section to obtain the detailed simulation results of the target well section includes: S11. Divide the target shale gas horizontal well into segments according to a preset accuracy, and select the target well segments that meet the preset conditions; Specifically, the preset accuracy unit is meters. The preset conditions are: well section length L, in meters, and diameter d, in meters.

[0029] S12. Set multiple sets of fluid parameters for the gas-liquid two-phase fluid in the target well section, and use smoothed fluid particle dynamics to perform a fine simulation of the target well section based on the multiple sets of fluid parameters for the gas-liquid two-phase fluid in the target well section, and obtain multiple sets of fine simulation results for the target well section.

[0030] Furthermore, the detailed simulation results for each target well section include: average liquid phase transport rate, average gas phase transport rate, inlet pressure of the target well section, outlet pressure of the target well section, and outlet liquid holdup of the target well section.

[0031] Specifically, each set of fluid parameters includes: liquid phase density. Unit: kg / m 3 , Gas phase density, unit kg / m³ 3 Liquid phase viscosity Unit: Pa·s, gas phase viscosity Unit: Pa·s, surface tension coefficient Unit: N / m, liquid holdup .

[0032] Among the fluid parameters in each group, the liquid holdup is as follows: 0.25 0.5 0.7 .

[0033] Furthermore, the average liquid-phase transport rate is Gas-phase average transport rate Pressure at the entrance of the target well section Pressure at the outlet of the target well section and the outlet fluid holdup of the target well section .

[0034] In step S2, determining the functional relationship between the gas-liquid two-phase slip velocity and the average water phase transport rate of the target well based on the detailed simulation results of the target well section includes: S21. Based on the average liquid phase transport rate and average gas phase transport rate in each set of detailed simulation results, calculate the gas-liquid two-phase slip velocity corresponding to each set of detailed simulation results. Specifically, Where a, b, and c are the fitting parameters.

[0035] S22. Based on the gas-liquid two-phase slip velocity corresponding to each set of fine simulation results and the average liquid phase transport velocity in each set of fine simulation results, the functional relationship between the gas-liquid two-phase slip velocity and the average water phase transport rate of the target well is fitted.

[0036] In step S2, determining the functional relationship between the resistance coefficient and the outlet liquid holdup of the target well based on the detailed simulation results of the target well section includes: S23. Based on the inlet pressure and outlet pressure of the target well section in each set of detailed simulation results, calculate the pressure difference corresponding to each set of detailed simulation results; Specifically, ΔP = P in -P out ; S24. Based on the outlet liquid holdup of the target well section in each set of fine simulation results, calculate the average density and average velocity corresponding to each set of fine simulation results; ; ; in, For average density, This represents the average density.

[0037] S25. Based on the average density and average velocity corresponding to each set of fine simulation results and the pressure difference corresponding to each set of fine simulation results, calculate the drag coefficient corresponding to each set of fine simulation results. ;in, This is the drag coefficient.

[0038] S26. Based on the resistance coefficients corresponding to each set of fine simulation results and the outlet liquid holdup of the target well section in each set of fine simulation results, the functional relationship between the resistance coefficient and the outlet liquid holdup of the target well is fitted.

[0039] d, e, and m are the fitting coefficients.

[0040] In step S3, the wellbore control coupling model of the target well is established based on the conservation theorem, the functional relationship between the gas-liquid two-phase slip velocity and the average transport rate of the aqueous phase in the target well, and the functional relationship between the resistance coefficient and the outlet liquid holdup of the target well. This includes: S31. Based on the law of conservation of mass and the functional relationship between the gas-liquid two-phase slip velocity and the average transport rate of the water phase in the target well, establish the liquid holdup equation for the target well. S32. Based on the law of conservation of momentum, the functional relationship between the gas-liquid two-phase slip velocity and the average transport rate of the water phase in the target well, and the functional relationship between the drag coefficient and the outlet liquid holdup of the target well, establish the miscible flow equation of the target well. S33. Couple the liquid holdup equation of the target well with the miscible flow equation of the target well section to obtain the wellbore control coupling model of the target well.

[0041] Furthermore, in this embodiment, the liquid holdup equation of the target well is: ; Where A is the cross-sectional area of ​​the well shaft, in meters. 2 ; The fluid holdup of the target well at location x, in % (%). The velocity of the water phase, in m / s, is determined by the functional relationship between the gas-liquid two-phase slip velocity and the average water phase transport rate of the target well.

[0042] In this embodiment, the miscible flow equation of the target well is: ; ; in, This is the mixed-phase density, in kg / m³. 3 ; It is the mixing phase velocity, in m / s; The momentum of the mixed phase; P is the pressure at position x; g is the acceleration due to gravity; It is the inclination angle of the well shaft; The wall resistance is determined by the functional relationship between the resistance coefficient of the target well and the outlet liquid holdup.

[0043] in, ; ; .

[0044] The percentage of gas at position x, in %. , These are the densities of the gas and liquid phases, respectively, in kg / m³. 3 , , The values ​​are the velocities of the gas phase and the water phase, respectively, in m / s.

[0045] In step S4, the iterative solution of the wellbore control coupling model of the target well, and the obtaining of the pressure distribution of the shale gas horizontal well based on the iteration results, includes: S41. Set the pressure and liquid holdup values ​​at a specific location in the target well at the initial time; S42. Based on the first liquid holdup value at a certain location of the target well at the initial time and the liquid holdup equation of the target well, calculate the liquid holdup value at a certain location of the target well at the next time after the initial time; S43. Based on the liquid holdup value at a certain location in the target well at the time following the initial time, the pressure value at a certain location in the target well at the initial time, and the miscible flow equation of the target well, calculate the gas phase velocity value at a certain location in the target well at the time following the initial time. S44. Based on the gas phase velocity value at a certain location in the target well at the next time step after the initial time step and the miscible flow equation of the target well, calculate the pressure value at a certain location in the target well at the next time step after the initial time step. S45. Determine whether the target well is in a steady state based on the pressure value at a certain location of the target well at the initial moment and the pressure value at the next moment at the same location of the target well. S46. If the target well is in a steady state, the pressure value at a certain location of the target well at the next time step after the initial time step is determined to be the final pressure value at that location of the target well. Based on the final pressure value at that location of the target well, the pressure distribution of the shale gas horizontal well can be obtained. S47. If the target well is not in a steady state, the next time step after the initial time step is used as the initial time step for iterative calculation until the target well is in a steady state.

[0046] In S45, the method further includes: Calculate the difference between the pressure value at a certain location in the target well at the initial time and the pressure value at the same location in the target well at the next time after the initial time; If the difference is within a preset range, the target well is determined to be in a steady state.

[0047] Specifically, by using the upwind scheme to solve the liquid holdup equation, the formula for calculating the liquid holdup value at a certain location in the target well at the next time step after the initial time step is as follows: ; Where n is the nth time and i is the i-th position of the target well.

[0048] Based on the liquid holdup at a certain location in the target well at the initial time and the pressure at that location at the initial time, and the miscibility equation of the target well, the formula for calculating the gas phase velocity at a certain location in the target well at the initial time and the next time is as follows:

[0049] The method for calculating the difference between the pressure value at a certain location in the target well at the initial moment and the pressure value at the same location in the target well at the next moment is as follows:

[0050] The formula for correcting the velocity distribution in a gas-liquid two-phase flow is as follows: .

[0051] The present invention also provides a computer device, including: a memory, a processor, and a computer program, the computer program being stored in the memory and configured to be executed by the processor to implement the above-described method for predicting the pressure distribution of gas-liquid two-phase flow wellbore in shale gas horizontal wells.

[0052] The present invention also provides a machine-readable storage medium storing computer program instructions, which, when executed by a processor, implement the above-described method for predicting the pressure distribution of gas-liquid two-phase flow wellbore in shale gas horizontal wells.

[0053] Those skilled in the art will understand that embodiments of the present invention can be provided as methods, systems, or computer program products. Therefore, the present invention can take the form of a completely hardware embodiment, a completely software embodiment, or an embodiment combining software and hardware aspects. Furthermore, the present invention can take the form of a computer program product implemented on one or more computer-usable storage media (including but not limited to disk storage, CD-ROM, optical storage, etc.) containing computer-usable program code. The solutions in the embodiments of the present invention can be implemented using various computer languages, such as the object-oriented programming language Java and the interpreted scripting language JavaScript.

[0054] This invention is described with reference to flowchart illustrations and / or block diagrams of methods, apparatus (systems), and computer program products according to embodiments of the invention. It will be understood that each block of the flowchart illustrations and / or block diagrams, and combinations of blocks in the flowchart illustrations and / or block diagrams, can be implemented by computer program instructions. These computer program instructions can be provided to a processor of a general-purpose computer, special-purpose computer, embedded processor, or other programmable data processing apparatus to produce a machine, such that the instructions, which execute via the processor of the computer or other programmable data processing apparatus, generate instructions for implementing the flowchart illustrations and / or block diagrams. Figure 1 One or more processes and / or boxes Figure 1 A device that provides the functions specified in one or more boxes.

[0055] These computer program instructions may also be stored in a computer-readable storage medium that can direct a computer or other programmable data processing device to function in a particular manner, such that the instructions stored in the computer-readable storage medium produce an article of manufacture including instruction means, which are implemented in a process Figure 1 One or more processes and / or boxes Figure 1 The function specified in one or more boxes.

[0056] These computer program instructions may also be loaded onto a computer or other programmable data processing equipment to cause a series of operational steps to be performed on the computer or other programmable equipment to produce a computer-implemented process, thereby providing instructions that execute on the computer or other programmable equipment for implementing the process. Figure 1 One or more processes and / or boxes Figure 1 The steps of the function specified in one or more boxes.

[0057] Although preferred embodiments of the invention have been described, those skilled in the art, upon learning the basic inventive concept, can make other changes and modifications to these embodiments. Therefore, the appended claims are intended to be interpreted as including both the preferred embodiments and all changes and modifications falling within the scope of the invention.

[0058] Obviously, those skilled in the art can make various modifications and variations to this invention without departing from its spirit and scope. Therefore, if these modifications and variations fall within the scope of the claims of this invention and their equivalents, this invention also intends to include these modifications and variations.

Claims

1. A method for predicting the pressure distribution in a shale gas horizontal well with gas-liquid two-phase flow, characterized in that, include: The target shale gas horizontal well is divided into multiple well sections. The target well section is selected from the multiple well sections, and a detailed simulation is performed on the target well section to obtain the detailed simulation results of the target well section. Based on the detailed simulation results of the target well section, the functional relationship between the gas-liquid two-phase slip velocity and the average water phase transport rate of the target well is determined, and the functional relationship between the resistance coefficient and the outlet liquid holdup of the target well is determined based on the detailed simulation results of each target well section. Based on the functional relationship between the gas-liquid two-phase slip velocity and the average transport rate of the aqueous phase in the target well, as well as the functional relationship between the resistance coefficient and the outlet liquid holdup in the target well, a wellbore control coupling model for the target well is established. The wellbore control coupling model of the target well is solved iteratively to obtain the iterative results, and the pressure distribution of the shale gas horizontal well is obtained based on the iterative results.

2. The method for predicting the pressure distribution in a shale gas horizontal well with gas-liquid two-phase flow according to claim 1, characterized in that, The detailed simulation of the target well section, to obtain the detailed simulation results of the target well section, includes: Multiple sets of fluid parameters for the gas-liquid two-phase fluid in the target well section are set, and smoothed fluid particle dynamics is used to perform a fine simulation of the target well section based on the multiple sets of fluid parameters for the gas-liquid two-phase fluid in the target well section, so as to obtain multiple sets of fine simulation results for the target well section.

3. The method for predicting the pressure distribution in a shale gas horizontal well with gas-liquid two-phase flow according to claim 2, characterized in that, Each set of detailed simulation results for the target well section includes: average liquid transport rate, average gas transport rate, inlet pressure of the target well section, outlet pressure of the target well section, and outlet liquid holdup of the target well section.

4. The method for predicting the pressure distribution in a shale gas horizontal well with gas-liquid two-phase flow according to claim 3, characterized in that, The determination of the functional relationship between the gas-liquid two-phase slip velocity and the average water phase transport rate of the target well based on the detailed simulation results of the target well section includes: Based on the average liquid phase transport rate and average gas phase transport rate in each set of detailed simulation results, the gas-liquid two-phase slip velocity corresponding to each set of detailed simulation results is calculated. Based on the gas-liquid two-phase slip velocity corresponding to each set of detailed simulation results and the average liquid phase transport velocity in each set of detailed simulation results, the functional relationship between the gas-liquid two-phase slip velocity and the average water phase transport rate of the target well is obtained by fitting.

5. The method for predicting the pressure distribution in a shale gas horizontal well with gas-liquid two-phase flow according to claim 3, characterized in that, The determination of the functional relationship between the resistance coefficient and the outlet liquid holdup of the target well based on the detailed simulation results of the target well section includes: Based on the inlet pressure and outlet pressure of the target well section in each set of detailed simulation results, the pressure difference corresponding to each set of detailed simulation results is calculated. Based on the outlet liquid holdup of the target well section in each set of detailed simulation results, the average density and average velocity corresponding to each set of detailed simulation results are calculated. Based on the average density and average velocity corresponding to each set of detailed simulation results, as well as the pressure difference corresponding to each set of detailed simulation results, the drag coefficient corresponding to each set of detailed simulation results is calculated. Based on the resistance coefficients corresponding to each set of detailed simulation results and the outlet liquid holdup of the target well section in each set of detailed simulation results, the functional relationship between the resistance coefficient and the outlet liquid holdup of the target well is fitted.

6. The method for predicting the pressure distribution in a shale gas horizontal well with gas-liquid two-phase flow according to claim 1, characterized in that, The wellbore control coupling model for the target well is established based on the functional relationship between the gas-liquid two-phase slip velocity and the average water phase transport rate, as well as the functional relationship between the resistance coefficient and the outlet liquid holdup of the target well. This model includes: Based on the law of conservation of mass and the functional relationship between the gas-liquid two-phase slip velocity and the average transport rate of the water phase in the target well, the liquid holdup equation of the target well is established. Based on the law of conservation of momentum, the functional relationship between the gas-liquid two-phase slip velocity and the average transport rate of the aqueous phase in the target well, and the functional relationship between the drag coefficient and the outlet liquid holdup of the target well, the miscible flow equation of the target well is established. The liquid holdup equation of the target well is coupled with the miscible flow equation of the target well section to obtain the wellbore control coupling model of the target well.

7. The method for predicting the pressure distribution in a shale gas horizontal well with gas-liquid two-phase flow according to claim 6, characterized in that, The liquid holdup equation for the target well is: ； Where A is the cross-sectional area of ​​the well shaft. Let x be the liquid holdup of the target well at position x. The water phase velocity is determined by the functional relationship between the gas-liquid two-phase slip velocity and the average water phase transport rate of the target well.

8. The method for predicting the pressure distribution in a shale gas horizontal well with gas-liquid two-phase flow according to claim 6, characterized in that, The miscible flow equation for the target well is: ； ； Where A is the cross-sectional area of ​​the well shaft. It is the mixed phase density. It is the mixed phase velocity. The momentum of the mixed phase is given by the pressure at position x, and g is the acceleration due to gravity. It is the inclination angle of the well shaft. The wall resistance is determined by the functional relationship between the resistance coefficient of the target well and the outlet liquid holdup.

9. The method for predicting the pressure distribution in a shale gas horizontal well with gas-liquid two-phase flow according to claim 6, characterized in that, The iterative solution of the wellbore control coupling model of the target well yields iterative results. Based on these results, the pressure distribution of the shale gas horizontal well is obtained, including: Set the pressure and liquid holdup values ​​at a specific location in the target well at the initial time; Based on the first liquid holdup value at a certain location of the target well at the initial time, solve the liquid holdup equation of the target well and calculate the liquid holdup value at the next time at a certain location of the target well at the initial time. Based on the liquid holdup value at a certain location in the target well at the initial time and the pressure value at the initial time, the miscible flow equation of the target well is solved, and the gas phase velocity value at a certain location in the target well at the initial time and the next time is calculated. The miscible flow equation of the target well is solved by the gas phase velocity value at a certain location of the target well at the next time after the initial time, and the pressure value at a certain location of the target well at the next time after the initial time is calculated. Based on the pressure value at a certain location of the target well at the initial moment and the pressure value at the next moment at the same location of the target well, it is determined whether the target well is in a steady state. When the target well is in a steady state, the iterative result is obtained, and the pressure distribution of the shale gas horizontal well is obtained based on the iterative result.

10. The method for predicting the pressure distribution in a shale gas horizontal well with gas-liquid two-phase flow according to claim 9, characterized in that, The process of obtaining iterative results when the target well is in a steady state, and then determining the pressure distribution of the shale gas horizontal well based on these iterative results, includes: If the target well is in a steady state, the iteration result is: the pressure value at a certain location of the target well at the initial time is the final pressure value at that location of the target well. Based on the final pressure value at that location of the target well, the pressure distribution of the shale gas horizontal well can be obtained. If the target well is not in a steady state, the next time step after the initial time step is used as the initial time step for iterative calculation until the target well is in a steady state.

11. The method for predicting the pressure distribution in a shale gas horizontal well with gas-liquid two-phase flow according to claim 10, characterized in that, The method further includes: Calculate the difference between the pressure value at a certain location in the target well at the initial time and the pressure value at the same location in the target well at the next time after the initial time; If the difference is within a preset range, the target well is determined to be in a steady state.

12. A computer device, characterized in that, include: Memory, which stores computer programs; A processor for executing the computer program to implement the method for predicting the pressure distribution of gas-liquid two-phase flow wellbore in shale gas horizontal wells according to any one of claims 1 to 11.

13. A computer-readable storage medium having a computer program stored thereon, characterized in that, The computer program is executed by a processor to implement the method for predicting the pressure distribution of gas-liquid two-phase flow wellbore in shale gas horizontal wells as described in any one of claims 1 to 11.

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