Condensate gas failure development simulation method, device and equipment considering non-equilibrium phase state

Abstract

The invention provides a condensate gas depletion development simulation method, device and equipment considering a non-equilibrium phase state, and belongs to the field of oil-gas field development, and the method comprises the steps: carrying out fluid non-equilibrium phase state calculation for a condensate gas system based on the system pressure of the current time step, and determining the oil-gas two-phase composition and an oil-gas two-phase compression factor of the current time step; on the basis of the gas phase compression factor of the current time step and the system pressure change within the time delta t, the fluid mole number generated within the time delta t is determined, and then the total fluid composition and the total fluid mole number of the next time step are determined; the t is updated to be t + delta t, the steps are repeated until t is smaller than or equal to tend, and the total fluid composition and the total fluid mole number of each time step are obtained; and flash evaporation calculation is carried out on produced fluids at different time steps, and the gas production rate, the oil production rate and the well flow composition under the corresponding conditions are obtained. Through the method provided by the invention, the condensate gas exhaustion development process occurring in an actual reservoir can be simulated.

Description

Technical Field

[0001] The present invention relates to the technical field of oil and gas field development, and in particular to a condensate gas depletion development simulation method considering non-equilibrium phase states, a condensate gas depletion development simulation device considering non-equilibrium phase states, an electronic device and a computer-readable storage medium. Background Art

[0002] Depletion development is one of the common development modes of condensate gas reservoirs. The simulation of depletion development can be divided into two categories: indoor physical simulation experimental method and numerical simulation method.

[0003] Among them, the constant-volume depletion experiment is the most commonly used experimental method for simulating condensate gas depletion development. The current national standard, "GB / T 26981-2020 Methods for Analysis of Physical Properties of Oil and Gas Reservoir Fluids," provides relevant descriptions and requirements for constant-volume depletion experiments. Constant-volume depletion experiments are designed to simulate the depletion recovery process of condensate gas reservoirs, understand production dynamics, and study changes in reservoir fluid volume and well flow composition during depletion recovery, as well as recovery factors at different depletion pressures. In practice, depletion recovery is a continuous process of pressure reduction and production. Due to laboratory limitations, this process can only be simulated approximately. Specifically, the sample volume at dew point pressure is determined as the constant pore volume of the oil or gas reservoir fluid. The pressure intervals for the constant-volume depletion experiment are determined based on the dew point pressure. The pressure range between the dew point pressure and zero pressure is generally divided into four to eight depletion pressure levels. Each level is depressurized and expanded, followed by discharge to the constant volume at constant pressure. During this experimental process, the fluid pressure and composition continuously change, while the volume occupied by the fluid remains constant, hence the term "constant-volume depletion."

[0004] However, the constant-volume depletion process in PVT experiments differs from actual production. In the former, the phase change of the fluid occurs within a high-pressure vessel. Because the gas and liquid phases have sufficient contact area, it is generally believed that the fluid can reach phase equilibrium in a short period of time. However, the depletion process in actual production occurs in the reservoir. In the porous media of actual reservoirs, due to its complex pore structure, the contact area between the phases in the fluid is very limited. As a result, when the temperature or pressure changes, the phases of the fluid cannot quickly reach phase equilibrium. In other words, the actual phase change process is non-equilibrium.

[0005] Core depletion experiments can be used to address the impact of nonequilibrium phase changes. To obtain a larger depletion volume and effectively simulate the depletion development process, core depletion experiments are typically conducted using large, full-diameter cores. However, full-diameter core depletion experiments are difficult and time-consuming. Furthermore, the effect of the dead volume of the sealed high-pressure container after the core is loaded on the effective pore volume of the rock remains unresolved. Summary of the Invention

[0006] In response to the technical problem that the existing technology lacks a non-equilibrium simulation method for condensate gas depletion development, the present invention provides a condensate gas depletion development simulation method that takes into account the non-equilibrium phase state. This method can simulate the condensate gas depletion development process occurring in an actual reservoir on the basis of considering the influence of the porous media in the actual reservoir on the non-equilibrium phase state changes during the depletion development process, thereby providing a reference basis for recovery rate prediction, development plan formulation, etc.

[0007] To achieve the above-mentioned object, the first aspect of the present invention provides a condensate gas depletion development simulation method considering non-equilibrium phase state, the method comprising the following steps: based on the system pressure at the current time step, performing fluid non-equilibrium phase state calculation for the condensate gas system, determining the oil and gas two-phase composition and the oil and gas two-phase compressibility factor at the current time step; based on the gas phase compressibility factor at the current time step and the system pressure change within Δt time, determining the number of moles of produced fluid within Δt time; based on the number of moles of produced fluid within Δt time, determining the total fluid composition and total fluid moles in the next time step; updating t to t+Δt, and repeating the above steps until t≤t end , obtain the total fluid composition and total fluid molar number at each time step; where t is the current time step, t end is the termination time, Δt is the time interval; flash calculation is performed on the produced fluids at different time steps to obtain the gas production, oil production and well flow composition under the corresponding conditions.

[0008] In an exemplary embodiment of the present invention, the performing of fluid non-equilibrium phase calculation for the condensate gas system based on the system pressure at the current time step to determine the oil and gas two-phase composition at the current time step and the compressibility factor of the oil and gas two-phase mixture at the current time step may include: determining the gas phase mole fraction based on the initial equilibrium ratio value in the current time step; determining the oil and gas two-phase composition based on the initial equilibrium ratio value and the gas phase mole fraction; determining the oil and gas two-phase compressibility factor based on the oil phase composition; determining the capillary pressure and the oil and gas two-phase pressure based on the oil and gas two-phase composition and the system pressure at the current time step; Based on the oil and gas two-phase composition, oil and gas two-phase pressure and oil and gas two-phase compressibility factor, the fugacity of each oil and gas phase component is determined; based on the fugacity of each oil and gas phase component, the normalized mass transfer velocity is calculated, and the fugacity error is determined; it is determined whether the fugacity error is less than or equal to the error threshold; if it is determined that the fugacity error is greater than the error threshold, the initial value of the equilibrium ratio is updated, and the above steps are repeated to determine the oil and gas two-phase composition and the oil and gas two-phase compressibility factor of the current time step again until the fugacity error is less than or equal to the error threshold, and the oil and gas two-phase composition and the oil and gas two-phase compressibility factor of the current time step are output.

[0009] In an exemplary embodiment of the present invention, the calculation formula for the gas phase mole fraction may be:

[0010]

[0011] The calculation formula of oil phase composition is:

[0012]

[0013] The calculation formula for the gas phase composition is:

[0014]

[0015] Where V is the gas phase mole fraction, Z i is the total fluid composition of the condensate gas system, K i is the initial value of the balance ratio, N c is the total number of components in the oil and gas system, i is the component number, X i is the oil phase composition, Y i It is composed of gas phase.

[0016] In an exemplary embodiment of the present invention, the maximum positive root of the system of equations for solving the compressibility factor may be determined as the gas phase compressibility factor, and the minimum positive root of the system of equations for solving the compressibility factor may be determined as the oil phase compressibility factor;

[0017] The compression factor solution equations are:

[0018]

[0019]

[0020]

[0021]

[0022] a i (T) = a ci α i (T),

[0023]

[0024]

[0025]

[0026]

[0027]

[0028] Where Z is the compression factor, a m is the average gravity of the condensate system, b m is the repulsive force constant of the condensate gas system, T is the temperature, p is the system pressure, R is the ideal gas constant, X i is the oil phase composition, Yi is the gas phase composition, ω i is the eccentricity factor of component i, T ci is the critical temperature of component i, p ci is the critical pressure of component i, is the binary interaction coefficient, for the hydrocarbon-hydrocarbon system: A m and B m are the first intermediate calculation parameters of the condensate gas system, a i 、a ci , α i 、b i and m i are the second intermediate calculation parameters for component i.

[0029] In an exemplary embodiment of the present invention, the calculation formula for the gas phase pressure is:

[0030] p=p g ;

[0031] The calculation formula of oil phase pressure is:

[0032] p o =p g -p c ;

[0033] The calculation formula of the capillary pressure is:

[0034]

[0035]

[0036] Where p is the system pressure, p g is the gas phase pressure, p o is the oil phase pressure, p c is the capillary pressure, γ is the interfacial tension, Z V is the gas phase compressibility factor, Z L is the oil phase compressibility factor, X i is the oil phase composition, Y i is the gas phase composition, [P i ] is the isotonic specific volume of component i, r is the pore radius, and θ is the angle between the gas-liquid interface and the pore surface.

[0037] In an exemplary embodiment of the present invention, the calculation formula for the fugacity of each component of the oil and gas phases may be:

[0038]

[0039]

[0040] The calculation formula of the normalized mass transfer rate is:

[0041]

[0042] The calculation formula of the fugacity error is:

[0043]

[0044] Among them, f Li is the fugacity of each component in the oil phase, f Vi is the fugacity of each component in the gas phase, X i is the oil phase composition, Y i is the gas phase composition, Z V is the gas phase compressibility factor, Z L is the oil phase compressibility factor, a m is the average gravity of the condensate system, b m is the repulsion constant of the condensate gas system, A m and B m is the first intermediate calculation parameter for the condensate gas system, a i and b i are the second intermediate calculation parameters for component i, is the normalized mass transfer velocity, p o + is the oil phase pressure at the next time step, p g + is the gas phase pressure at the next time step, λ is the inverse of the equilibrium time, and ε is the fugacity error.

[0045] In an exemplary embodiment of the present invention, the calculation formula for the number of moles of produced fluid within the time Δt may be:

[0046]

[0047] n V =V·F,

[0048]

[0049] The calculation formula for the total fluid composition in the next time step is:

[0050]

[0051] The calculation formula for the total number of fluid moles in the next time step is:

[0052] F + =F-Δn V ;

[0053] Among them, Δn V is the number of moles of gas produced during the time Δt, nV is the number of moles of gas phase in the current time step, is the number of gas phase moles in the next time step, Z V is the gas phase compressibility factor of the current time step, is the gas phase compression factor of the next time step, p is the system pressure of the current time step, p + is the system pressure in the next time step, F is the total number of fluid moles in the current time step, and F + is the total fluid mole number in the next time step, V is the gas phase mole fraction, and Z i is the total fluid composition at the current time step, is the total fluid composition in the next time step, Y i It is composed of gas phase.

[0054] A second aspect of the present invention provides a condensate gas depletion development simulation device taking into account non-equilibrium phase states, the device comprising: a non-equilibrium phase state calculation module, a production fluid calculation module, a total fluid composition update module, an iteration module, and a flash calculation module; the non-equilibrium phase state calculation module is used to perform fluid non-equilibrium phase state calculation for the condensate gas system based on the system pressure at the current time step, and determine the oil and gas two-phase composition and the oil and gas two-phase compressibility factor at the current time step; the production fluid calculation module is used to determine the number of moles of production fluid within Δt time based on the gas phase compressibility factor at the current time step and the system pressure change within Δt time; the total fluid composition update module is used to determine the total fluid composition and the total fluid moles in the next time step based on the number of moles of production fluid within Δt time; the iteration module is used to update t to t+Δt, and repeat the above steps until t≤t end , obtain the total fluid composition and total fluid molar number at each time step; where t is the current time step, t end is the termination time, Δt is the time interval; the flash calculation module is used to perform flash calculations on the produced fluids at different time steps to obtain the gas production, oil production and well flow composition under corresponding conditions.

[0055] The third aspect of the present invention provides an electronic device, which includes a processor and a memory, wherein the memory stores at least one computer program, and the at least one computer program is loaded and executed by one or more of the above-mentioned processors to enable the processor to execute the above-mentioned condensate gas depletion development simulation method considering non-equilibrium phase state.

[0056] A fourth aspect of the present invention provides a computer-readable storage medium storing at least one program code, which is loaded and executed by a processor to enable the computer to execute the above-mentioned condensate gas depletion development simulation method considering non-equilibrium phase state.

[0057] The technical solution provided by the present invention has at least the following technical effects:

[0058] The condensate gas depletion development simulation method of the present invention simulates the condensate gas depletion development process occurring in an actual reservoir on the basis of considering the influence of the porous medium in the actual reservoir on the non-equilibrium phase change during the depletion development process, and can provide a reference basis for recovery rate prediction, development plan formulation, etc.

[0059] Other features and advantages of the present invention will be described in detail in the following detailed description. BRIEF DESCRIPTION OF THE DRAWINGS

[0060] The accompanying drawings are used to provide a further understanding of the embodiments of the present invention and constitute a part of the specification. Together with the following detailed description, they are used to explain the embodiments of the present invention, but do not constitute a limitation of the embodiments of the present invention. In the accompanying drawings:

[0061] Figure 1 A flow chart of a condensate gas depletion development simulation method considering non-equilibrium phase states provided in an embodiment of the present invention;

[0062] Figure 2 A comparison chart of gas production during the non-equilibrium depletion process, equilibrium process, and full-diameter core depletion experiment provided by an embodiment of the present invention;

[0063] Figure 3 A comparison chart of oil production during the non-equilibrium depletion process, equilibrium process, and full-diameter core depletion experiment provided by an embodiment of the present invention;

[0064] Figure 4 A schematic diagram of the structure of a condensate gas depletion development simulation device considering non-equilibrium phase states provided in an embodiment of the present invention;

[0065] Figure 5 A schematic structural diagram of an electronic device provided by an embodiment of the present invention.

[0066] Description of Reference Numerals

[0067] 101 - non-equilibrium phase calculation module, 102 - output fluid calculation module, 103 - total fluid composition update module, 104 - iteration module, 105 - flash calculation module, 201 - processor, 202 - memory. DETAILED DESCRIPTION

[0068] The following describes the specific implementation of the embodiment of the present invention in detail with reference to the accompanying drawings. It should be understood that the specific implementation described herein is only used to illustrate and explain the embodiment of the present invention and is not used to limit the embodiment of the present invention.

[0069] It should be noted that, in the absence of conflict, the embodiments of the present invention and the features in the embodiments may be combined with each other.

[0070] In the present invention, unless otherwise indicated, directional terms such as "upper, lower, top, and bottom" are generally used to describe the relative positions of components relative to the directions shown in the drawings, or relative to the vertical, perpendicular, or gravitational directions. "First," "second," etc. are merely for convenience of description and distinction and should not be construed as indicating or implying relative importance.

[0071] It should also be noted that, in the description of the present invention, unless otherwise expressly specified or limited, the terms "installation" and "connection" should be understood in a broad sense. For example, they may refer to fixed connection, detachable connection, or integrated connection; direct connection, indirect connection, wired connection, or wireless connection. Those skilled in the art will understand the specific meanings of the above terms in the present invention depending on the specific circumstances.

[0072] Existing techniques often use full-diameter core depletion experiments to simulate the condensate gas depletion development process under the influence of nonequilibrium phase changes. While this experimental method can simulate the depletion development process, it is difficult and time-consuming to implement. It also fails to account for the effect of the dead volume of the sealed high-pressure container after the core is loaded on the effective pore volume of the rock, resulting in inaccurate results.

[0073] Considering the problem that existing technologies cannot effectively simulate the condensate gas depletion development process that occurs in actual reservoirs based on the influence of non-equilibrium phase changes, the present invention proposes a condensate gas depletion development simulation method that takes non-equilibrium phases into account. This method calculates the oil and gas phase composition and two-phase fugacity in the oil-gas system under different pressure conditions based on the original gas phase composition using formulas such as the SRK state equation and the fugacity equation. When two phases exist, the material transfer rate between the two phases is considered to calculate the difference between the two-phase fugacity at different times. On this basis, the composition and various parameters of the oil and gas two-phases at different times are recalculated. Based on the establishment of a non-equilibrium phase calculation method that describes the change of fluid phase over time, the condensate gas constant volume depletion development process is simulated. Compared with the simulation methods of condensate gas depletion development processes in the prior art, this method can improve the simulation accuracy of the condensate gas constant volume depletion development process. In specific implementation, the above method can be executed by an electronic device, which can be a server, terminal, or other device with processing capabilities.

[0074] The technical solution of the present invention will be described in detail below with reference to the accompanying drawings and in combination with embodiments. The following specific embodiments can be combined with each other, and the same or similar concepts or processes may not be described in detail in some embodiments.

[0075] First, the present invention considers using a fluid non-equilibrium phase calculation model to determine the non-equilibrium phase changes during depletion development. The basic assumptions of the calculation model are as follows:

[0076] (1) The oil-gas two-phase system is a closed system. The whole process is isothermal. The temperature is T, and the unit is K.

[0077] (2) The phase equilibrium process between oil and gas phases is not completed instantaneously, but changes dynamically over time;

[0078] (3) When the system is single-phase, there is no need to consider non-equilibrium phase processes;

[0079] (4) Ignore the effects of surface wettability of porous media, capillary forces, and adsorption on the phase changes of the oil and gas system.

[0080] Assume that the oil and gas system has N c Components, total molar number is F (unit is mol), total composition is Z i (i=1,2,…,N c ), at equilibrium, the liquid phase mole fraction is L (dimensionless), and the liquid phase composition is X i (i=1,2,…,N c ), the gas phase mole fraction is V (dimensionless), and the gas phase composition is Y i (i=1,2,…,N c ).

[0081] According to the law of conservation of matter, we can get:

[0082] L+V=1 (1)

[0083] X i L+Y i V=Z i (i=1,2,…,N c ) (2)

[0084] Among them, the composition of each phase satisfies the following normalization conditions:

[0085]

[0086] The equilibrium ratio (dimensionless) of component i at equilibrium is:

[0087]

[0088] Combining equations (1), (2), (3) and (4), we get the liquid phase composition:

[0089]

[0090] Substituting equation (5) into equation (4), the gas phase composition is obtained as follows:

[0091]

[0092] Combining equations (3), (5) and (6), we can get:

[0093]

[0094] Where V is the gas phase mole fraction, dimensionless; Z i is the total fluid composition of the condensate gas system, dimensionless; K i is the initial value of the equilibrium ratio, dimensionless; N c is the total number of components in the oil and gas system, dimensionless; i is the component number, dimensionless; X i It is composed of oil phase and dimensionless; Y i It is composed of gas phase and has no dimension.

[0095] According to the given K i The gas phase mole fraction V can be calculated by the Newton-Raphson iterative method using formula (7), and based on this, the oil phase mole fraction L and the oil-gas two-phase composition X can be calculated respectively by formula (1), formula (5), and formula (6). i and Y i .

[0096] After calculating the oil and gas two-phase composition, it is necessary to calculate the fugacity of each component based on the oil and gas two-phase composition, and then calculate the normalized mass transfer velocity and fugacity error.

[0097] The present invention proposes to use the Soave-Redlish-Kwong (SRK) state equation to calculate the fugacity (in MPa) of each component in the oil and gas phases:

[0098]

[0099]

[0100] Among them, f Li is the fugacity of each component in the oil phase, f Vi is the fugacity of each component in the gas phase, p o and p g Represents the pressure of the oil phase and gas phase respectively, in MPa. Under the action of capillary force in porous media, the two are not equal. The calculation method is shown in formulas (10) to (11). For condensate gas system: system pressure p = p g .

[0101]

[0102]

[0103] Where, γ is the interfacial tension, N / m; [P i ] is the isotonic specific volume of component i, dimensionless; p c is the capillary pressure, MPa; r is the pore radius, m; θ is the angle between the gas-liquid interface and the pore surface, degrees; R is the ideal gas constant; T is the temperature, K; Z L is the oil phase compression factor, dimensionless; Z V is the gas phase compressibility factor, dimensionless.

[0104] Z L and Z V It can be calculated by the following formula:

[0105]

[0106] There are three roots in formula (12), among which the largest positive root is the gas phase compressibility factor Z V , the smallest positive root is the oil phase compressibility factor Z L .

[0107] In addition, the definitions of other parameters in formula (12) are:

[0108]

[0109]

[0110]

[0111] a i (T) = a ci α i (T) (16)

[0112]

[0113]

[0114]

[0115]

[0116]

[0117] Where Z is the compression factor; a m is the average gravity of the condensate system; dimensionless; b m is the repulsive force constant of the condensate system, dimensionless; T is the temperature; p is the system pressure; R is the ideal gas constant; X i It is composed of oil phase; Y i is the gas phase composition; ω i is the eccentricity factor of component i; T ciis the critical temperature of component i, dimensionless; p ci is the critical pressure of component i, dimensionless; is the binary interaction coefficient, dimensionless; for hydrocarbon-hydrocarbon system: A m and B m are the first intermediate calculation parameters of the condensate gas system; a i 、a ci , α i 、b i and m i are the second intermediate calculation parameters for component i.

[0118] For the initial time t0 (in seconds), the initial value of the equilibrium ratio can be calculated using the Wilson formula:

[0119]

[0120] For the initial time t0, the default is higher than the saturation pressure of the condensate gas. At this time, the fluid is in a gas phase single-phase state. The K calculated by formula (22) is i As the initial value, the equilibrium ratio K under this condition can be calculated using conventional flash evaporation i Except for the initial time t0, for other times t, the initial value of the equilibrium ratio uses the value of the pressure condition in the previous step.

[0121] At phase equilibrium, the fugacity of the oil and gas phases is assumed to be equal. However, due to the complex pore structure in actual porous media, the contact area between the oil and gas phases is extremely limited, resulting in the inability to complete the material transfer between the two phases instantaneously.

[0122] The material transfer rate between the two phases is related to the difference in chemical potential between the oil and gas phases:

[0123] ω i,L-V =C(μ Li -μ Vi ) (i=1,2,…,N c ) (twenty three)

[0124] In the formula, the value of C is related to the physical properties of the rock itself (such as porosity and permeability) and fluid saturation.

[0125] Here, a normalized material transfer velocity between two phases is defined:

[0126]

[0127] The difference in fugacity coefficients between the two phases can be expressed as:

[0128]

[0129] As the material transfers between the two phases, the two phases of the fluid gradually reach a phase equilibrium state over time. In this process, the material transfer rate between the two phases is generally considered to decrease exponentially. Therefore, the normalized material transfer rate is defined as:

[0130]

[0131] Where p o + Indicates the oil phase pressure value of the next time step, p g + It represents the gas phase pressure value at the next time step. The value of λ can be obtained by fitting based on experiments or mine data.

[0132] According to formula (26), the fugacity error is obtained as:

[0133]

[0134] Whether the parameters of the oil and gas phase components and other parameters calculated by the above formula are reasonable is determined by judging whether the fugacity error ε is less than or equal to the error threshold ε0. If so, subsequent calculations on the total fluid composition and produced fluid can be performed. If not, the initial value of the equilibrium ratio needs to be updated, and the parameters of the oil and gas phase components and other parameters need to be recalculated until the fugacity error is less than or equal to the error threshold.

[0135] When the fugacity error ε is greater than the error threshold ε0, the initial value of the balance ratio can be updated using formula (28), that is:

[0136]

[0137] Second, after determining the components of the oil and gas phases and parameters such as the compression factor, the condensate gas depletion development process occurring in the actual reservoir can be simulated on this basis.

[0138] During the depletion process, gas phase fluid is produced, causing the total fluid composition to change continuously. The total fluid composition at each time step can be calculated using the following formula:

[0139]

[0140] Where Z i represents the total fluid composition at the current time step; represents the total fluid composition of the next time step; F represents the total number of moles of fluid in the current time step; Δn V Indicates the number of moles of gas produced within Δt (in mol); Y i Represents the gas phase composition.

[0141] At the same time, since part of the fluid is produced, the total fluid molar number decreases, which can be calculated using the following formula:

[0142] F + =F-Δn V (30)

[0143] Where, F + represents the total number of fluid moles in the next time step; F represents the total number of fluid moles in the current time step; Δn V Indicates the number of moles of gas produced within the time Δt.

[0144] The change in molar number can be further calculated based on the change in pressure before and after the fluid is produced at each time step:

[0145]

[0146] in, Indicates the gas phase compressibility factor for the next time step (dimensionless); Indicates the number of gas phase moles in the next time step (in mol); Z V Indicates the gas phase compressibility factor at the current time step (dimensionless; n V Indicates the number of gas phase moles at the current time step (in mol); p indicates the system pressure at the current time step (in MPa); p + Indicates the system pressure at the next time step (in MPa).

[0147] Current gas phase molar number n V (unit is mol) is:

[0148] n V =V·F (32)

[0149] Thus, the number of moles of gas produced within the time Δt can be calculated (in mol):

[0150]

[0151] Here, it should be noted that according to equations (1) to (7) and (12) to (21), the gas phase compressibility factor of the next time step is The number of moles of gas produced in Δt time Δn V Constitute a certain functional relationship, namely: At the same time, according to equations (32) and (33), the number of gas phase moles in the next time step is The number of moles of gas produced in Δt time Δn V It also forms a certain functional relationship, namely: Therefore, the above two groups about Δn V Substituting the functional relationship into equation (31), the change in the number of moles Δn can be solved according to the change in pressure before and after the production of fluid at each time step. V .

[0152] Third, after determining the number of moles of gas phase produced, the produced fluid can be flashed and calculated to obtain the gas production, oil production, and well flow composition under the corresponding conditions.

[0153] Since the calculation process of gas production, oil production and well flow composition belongs to the conventional calculation method in the field of oil and gas field development, it will not be described in detail in the embodiment of the present invention.

[0154] In summary, the specific process of the condensate gas depletion development simulation method considering non-equilibrium phase state involved in the embodiment of the present invention is as follows ( Figure 1 shown):

[0155] Step 1: Input the original composition and physical property parameters of each component, and set the temperature T and original pressure p0 of the condensate gas system;

[0156] Step 2: Enter the start time, end time, and current time step t, and enter the pressure at the corresponding time;

[0157] Step 3: For the current time step t, calculate the gas phase mole fraction V according to formula (7), and calculate the oil and gas two-phase composition X according to formulas (5) and (6): i and Y i and normalized;

[0158] Step 4: For the current time step t, calculate the compressibility factor Z of the oil-gas two-phase mixture according to equations (12) and (13) to (21): L and Z V ;

[0159] Step 5: For the current time step t, calculate the capillary pressure p according to equations (10) and (11): c And the oil and gas two-phase pressure p o and p g ;

[0160] Step 6: For the current time step t, calculate the fugacity f of each component of the oil and gas phases according to equations (8) and (9): Li and f Vi ;

[0161] Step 7: For the current time step t, calculate the normalized mass transfer velocity according to Equation (26):

[0162] Step 8: For the current time step t, calculate the fugacity error according to formula (27), and determine whether the fugacity error ε is less than or equal to the error threshold ε0;

[0163] Step 9: If the fugacity error ε is less than or equal to the error threshold ε0, proceed to step 10; if the fugacity error ε is greater than the error threshold ε0, update the initial value of the balance ratio K according to formula (28) i Return to step 3 and repeat steps 3 to 9 to recalculate parameters such as components of the oil and gas phases;

[0164] Step 10: According to equations (31) to (33) and pressure drop p~p + Calculate the number of moles of produced gas and perform flash evaporation calculation on the produced fluid in the current time step t to obtain the gas production, oil production and well flow composition under the corresponding conditions;

[0165] Step 11: Calculate and update the total fluid composition Z of the oil-gas mixture in the current time step t according to equations (29) and (30): i and the total number of fluid moles F;

[0166] Step 12: Determine whether the current time step t is less than or equal to the end time t end If yes, terminate the calculation. If no, update t to t+Δt and return to step 2. Repeat steps 2 to 12 to calculate the total fluid composition and total fluid moles of the oil-gas mixture in the next time step until the current time step t is less than or equal to the termination time t. end .

[0167] In order to better understand the above exemplary embodiments of the present invention, they are further described below with reference to specific examples.

[0168] Taking a fluid sample obtained from a condensate gas reservoir as an example, the original gas phase composition and critical parameters of the fluid sample obtained after conventional PVT physical simulation experiments and phase state fitting are shown in Table 1 below.

[0169] Table 1 Original gas phase composition and parameters

[0170]

[0171] In addition, the average pore radius is given as r = 100 nm, and the angle between the gas-liquid interface and the pore surface is θ = 0.

[0172] Based on the results of the indoor PVT experiment, the conventional SRK equation of state was used to fit the pseudo-component parameters and fitting calculation results of the second sampling sample from Well B201. The experimentally measured dew point pressure at 110.4°C was 26.3 MPa.

[0173] According to the condensate gas depletion development simulation method given in the embodiment of the present invention, the depletion development process of the fluid sample is simulated, and the simulation results of the non-equilibrium depletion process and the equilibrium process under porous media conditions are compared with the full-diameter core depletion test results. The results are as follows: Figures 2 and 3 shown.

[0174] Comparison of the results shows that the impact of nonequilibrium phase calculations on gas production results is negligible; after accounting for the nonequilibrium phase, oil production below the dew point increases, which better matches the experimental results; compared to the equilibrium phase, when considering λ = 0.00001, the cumulative oil production increases by 11%.

[0175] In addition, the implementation environment of this embodiment includes at least one terminal and a server, and the method is executed on the terminal or the server respectively. The terminal and the server can be connected in communication to realize the interactive transmission of information.

[0176] Among them, the terminal can be any electronic product that can interact with the user through one or more methods such as keyboard, touchpad, touch screen, voice interaction, etc., such as PC (Personal Computer), PPC (Pocket Personal Computer), tablet computer, etc.

[0177] A server can be a single server or a server cluster consisting of multiple servers. It can also be a cloud server that provides basic cloud computing services such as cloud services, cloud databases, cloud computing, cloud functions, cloud storage, network services, cloud communications, middleware services, domain name services, security services, CDN (Content Delivery Network), as well as big data and artificial intelligence platforms.

[0178] like Figure 4 As shown, an embodiment of the present invention also provides a condensate gas depletion development simulation device considering non-equilibrium phase state, which includes: a non-equilibrium phase state calculation module 101, a production fluid calculation module 102, a total fluid composition update module 103, an iteration module 104 and a flash calculation module 104.

[0179] The non-equilibrium phase state calculation module 101 is used to perform fluid non-equilibrium phase state calculation for the condensate gas system based on the system pressure at the current time step, and determine the oil and gas two-phase composition and the oil and gas two-phase compressibility factor at the current time step.

[0180] The produced fluid calculation module 102 is used to determine the number of moles of produced fluid within the time Δt based on the gas phase compressibility factor of the current time step and the system pressure change within the time Δt.

[0181] The total fluid composition updating module 103 is used to determine the total fluid composition and total fluid moles in the next time step based on the moles of produced fluid in the time Δt.

[0182] Iteration module 104 is used to update t to t+Δt and repeat the above steps until t≤tend , obtain the total fluid composition and total fluid mole number at each time step. Where t is the current time step, t end is the end time, and Δt is the time interval.

[0183] The flash calculation module 105 is used to perform flash calculations on the produced fluids at different time steps to obtain the gas production, oil production and well flow composition under corresponding conditions.

[0184] It should be noted that the above-mentioned device only uses the division of the above-mentioned functional modules as an example to illustrate its functions. In actual applications, the above-mentioned functions can be assigned to different functional modules as needed, that is, the internal structure of the device can be divided into different functional modules to complete all or part of the functions described above. In addition, the device provided in the above embodiment and the method provided in the above embodiment are based on the same concept. The specific implementation process is detailed in the method embodiment and will not be repeated here.

[0185] like Figure 5 As shown, an embodiment of the present invention further provides an electronic device, which includes a processor 201 and a memory 202, wherein at least one computer program is stored in the memory, and the at least one computer program is loaded and executed by one or more of the above-mentioned processors to enable the processor to implement the condensate gas depletion development simulation method considering the non-equilibrium phase state in the above-mentioned embodiment.

[0186] Of course, the electronic device may also have components such as a wired or wireless network interface, a keyboard, and an input / output interface for input and output. The electronic device may also include other components for realizing various functions of the device, which will not be described in detail here.

[0187] An embodiment of the present invention also provides a computer-readable storage medium, which stores at least one program code. The program code is loaded and executed by a processor to enable the computer to implement the condensate gas depletion development simulation method considering the non-equilibrium phase state in the above embodiment.

[0188] Optionally, the computer-readable storage medium may be a read-only memory (ROM), a random access memory (RAM), a compact disc (CD-ROM), a magnetic tape, a floppy disk, and an optical disc data storage device. Those skilled in the art will appreciate that all or part of the steps in the above-mentioned embodiment method can be accomplished by instructing the relevant hardware through a program, and the program is stored in a storage medium, including several instructions for causing a single-chip microcomputer, a chip, or a processor to execute all or part of the steps of the method described in each embodiment of the present application. The aforementioned storage medium includes various media that can store program codes, such as a USB flash drive, a mobile hard disk, a read-only memory (ROM), a random access memory (RAM), a magnetic disk, or an optical disc.

[0189] The preferred embodiments of the present invention are described in detail above in conjunction with the accompanying drawings. However, the present invention is not limited to the specific details in the above embodiments. Within the technical concept of the present invention, various simple modifications can be made to the technical solution of the present invention, and these simple modifications all fall within the scope of protection of the present invention.

[0190] It should also be noted that the various specific technical features described in the above specific embodiments can be combined in any appropriate manner without contradiction. In order to avoid unnecessary repetition, the present invention will not further describe various possible combinations.

[0191] In addition, the various embodiments of the present invention may be arbitrarily combined, and as long as they do not violate the concept of the present invention, they should also be regarded as the contents disclosed by the present invention.

Claims

1. A condensate gas depletion development simulation method considering non-equilibrium phase state, characterized in that: The method comprises: Based on the system pressure at the current time step, perform fluid non-equilibrium phase calculation for the condensate gas system to determine the oil and gas two-phase composition and the oil and gas two-phase compressibility factor at the current time step; Determine the number of moles of produced fluid within Δt based on the gas phase compressibility factor of the current time step and the system pressure change within Δt. Based on the molar number of produced fluid in the time Δt, the total fluid composition and total fluid molar number in the next time step are determined; Update t to t+Δt and repeat the above steps until t≤t end , obtain the total fluid composition and total fluid molar number at each time step; where t is the current time step, t end is the end time, Δt is the time interval; Flash calculations are performed on the produced fluids at different time steps to obtain the gas production, oil production and well flow composition under corresponding conditions.

2. The condensate gas depletion development simulation method considering non-equilibrium phase state according to claim 1, characterized in that: The fluid non-equilibrium phase state calculation is performed for the condensate gas system based on the system pressure at the current time step to determine the oil and gas two-phase composition and the oil and gas two-phase compressibility factor at the current time step, including: In the current time step, the gas phase mole fraction is determined based on the initial value of the equilibrium ratio; Determine the oil and gas two-phase composition based on the initial equilibrium ratio and the gas phase mole fraction; Determine the oil and gas two-phase compressibility factor based on the oil phase composition; Determine the capillary pressure and the oil-gas two-phase pressure based on the oil-gas two-phase composition and the system pressure at the current time step; Determine the fugacity of each component of the oil and gas phases based on the oil and gas two-phase composition, oil and gas two-phase pressure, and oil and gas two-phase compressibility factor; According to the fugacity of each component of the oil and gas phases, the normalized mass transfer velocity is determined, and then the fugacity error is determined; Determine whether the fugacity error is less than or equal to the error threshold; When it is determined that the fugacity error is greater than the error threshold, the initial value of the equilibrium ratio is updated and the above steps are repeated to determine the oil and gas two-phase composition and the oil and gas two-phase compressibility factor at the current time step again until the fugacity error is less than or equal to the error threshold. The oil and gas two-phase composition and the oil and gas two-phase compressibility factor at the current time step are then output.

3. The condensate gas depletion development simulation method considering non-equilibrium phase state according to claim 2, characterized in that: The calculation formula for the gas phase mole fraction is: The calculation formula of oil phase composition is: The calculation formula for the gas phase composition is: Where V is the gas phase mole fraction, Z i is the total fluid composition of the condensate gas system, K i is the initial value of the balance ratio, N c is the total number of components in the oil and gas system, i is the component number, X i is the oil phase composition, Y i It is composed of gas phase.

4. The condensate gas depletion development simulation method considering non-equilibrium phase state according to claim 2, characterized in that: Determining the maximum positive root of the equations for solving the compressibility factor as the gas phase compressibility factor, and determining the minimum positive root of the equations for solving the compressibility factor as the oil phase compressibility factor; The compression factor solution equations are: a i (T)=a ci α i (T), Where Z is the compression factor, a m is the average gravity of the condensate system, b m is the repulsive force constant of the condensate gas system, T is the temperature, p is the system pressure, R is the ideal gas constant, X i is the oil phase composition, Y i is the gas phase composition, ω i is the eccentricity factor of component i, T ci is the critical temperature of component i, p ci is the critical pressure of component i, is the binary interaction coefficient, for the hydrocarbon-hydrocarbon system: A m and B m are the first intermediate calculation parameters of the condensate gas system, a i 、a ci , α i 、b i and m i are the second intermediate calculation parameters for component i.

5. The condensate gas depletion development simulation method considering non-equilibrium phase state according to claim 2, characterized in that: The calculation formula for gas phase pressure is: p=p g ; The calculation formula of oil phase pressure is: p o =p g -p c ; The calculation formula of the capillary pressure is: Where p is the system pressure, p g is the gas phase pressure, p o is the oil phase pressure, p c is the capillary pressure, γ is the interfacial tension, Z V is the gas phase compressibility factor, Z L is the oil phase compressibility factor, X i is the oil phase composition, Y i is the gas phase composition, [P i ] is the isotonic specific volume of component i, r is the pore radius, and θ is the angle between the gas-liquid interface and the pore surface.

6. The condensate gas depletion development simulation method considering non-equilibrium phase state according to claim 2, characterized in that: The calculation formula for the fugacity of each component of the oil and gas phases is: The calculation formula of the normalized mass transfer rate is: The calculation formula of the fugacity error is: Among them, f Li is the fugacity of each component in the oil phase, f Vi is the fugacity of each component in the gas phase, X i is the oil phase composition, Y i is the gas phase composition, Z V is the gas phase compressibility factor, Z L is the oil phase compressibility factor, a m is the average gravity of the condensate system, b m is the repulsion constant of the condensate gas system, A m and B m is the first intermediate calculation parameter for the condensate gas system, a i and b i are the second intermediate calculation parameters for component i, is the normalized mass transfer velocity, p o + is the oil phase pressure in the next time step, p g + is the gas phase pressure at the next time step, λ is the inverse of the equilibrium time, and ε is the fugacity error.

7. The condensate gas depletion development simulation method considering non-equilibrium phase state according to claim 1, characterized in that: The calculation formula for the number of moles of produced fluid within the time Δt is: n V =V·F, The calculation formula for the total fluid composition in the next time step is: The calculation formula for the total number of fluid moles in the next time step is: F + =F-Δn V ; Among them, Δn V is the number of moles of gas produced during the time Δt, n V is the number of moles of gas phase in the current time step, is the number of gas phase moles in the next time step, Z V is the gas phase compressibility factor of the current time step, is the gas phase compression factor of the next time step, p is the system pressure of the current time step, p + is the system pressure in the next time step, F is the total number of fluid moles in the current time step, and F + is the total fluid mole number in the next time step, V is the gas phase mole fraction, and Z i is the total fluid composition at the current time step, is the total fluid composition in the next time step, Y i It is composed of gas phase.

8. A condensate gas depletion development simulation device considering non-equilibrium phase state, characterized in that: The device comprises: a non-equilibrium phase calculation module, an output fluid calculation module, a total fluid composition update module, an iteration module and a flash calculation module; The non-equilibrium phase state calculation module is used to perform fluid non-equilibrium phase state calculation for the condensate gas system based on the system pressure at the current time step, and determine the oil and gas two-phase composition and the oil and gas two-phase compressibility factor at the current time step; The produced fluid calculation module is used to determine the number of moles of produced fluid within Δt time based on the gas phase compressibility factor of the current time step and the system pressure change within Δt time; The total fluid composition update module is used to determine the total fluid composition and total fluid moles in the next time step based on the number of moles of produced fluid in the time Δt; Iteration module is used to update t to t+Δt and repeat the above steps until t≤t end , obtain the total fluid composition and total fluid molar number at each time step; where t is the current time step, t end is the end time, Δt is the time interval; The flash calculation module is used to perform flash calculations on the produced fluids at different time steps to obtain the gas production, oil production and well flow composition under corresponding conditions.

9. An electronic device, characterized in that: The electronic device includes a processor and a memory, wherein the memory stores at least one computer program, and the at least one computer program is loaded and executed by one or more of the above processors to enable the processor to execute the condensate gas depletion development simulation method considering non-equilibrium phase state described in any one of claims 1 to 7.

10. A computer-readable storage medium, characterized in that The computer-readable storage medium stores at least one program code, and the program code is loaded and executed by a processor to enable a computer to execute the condensate gas depletion development simulation method considering non-equilibrium phase states according to any one of claims 1 to 7.

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