Method and system for calculating average formation pressure of a shale condensate gas reservoir

Abstract

The application discloses a method and system for calculating average formation pressure of a shale condensate gas reservoir, which comprises the following steps: obtaining geological characteristic parameters of a target shale condensate gas reservoir, and determining an oil-gas seepage control equation representing oil-gas seepage characteristics in the target oil-gas reservoir and an adsorption equation representing adsorption characteristics of adsorbed gas in the target oil-gas reservoir according to the geological characteristic parameters; optimizing the gas-phase seepage control equation by using the adsorption equation to obtain an actual best oil-gas seepage control equation; and determining a common differential equation about the average formation pressure according to the best oil-gas seepage control equation to obtain the average formation pressure in different production periods. The application realizes accurate calculation of the average formation pressure in different production periods.

Description

Technical Field

[0001] This invention belongs to the field of shale gas exploration and development technology, and in particular relates to a method and system for calculating the average formation pressure of shale condensate oil and gas reservoirs. Background Technology

[0002] With the rapid growth in resource demand, global energy development has entered a critical stage of transition from fossil fuels to new energy sources. As the cleanest energy source among fossil fuels, natural gas is a crucial transitional element in this shift. Conventional natural gas resources are easy to extract but have small reserves. Shale gas, as a clean and efficient unconventional fossil energy source, has received widespread attention in recent years, with global shale gas production showing a year-on-year increasing trend. In the future, shale gas will occupy an important position in the global energy market.

[0003] With the deepening of exploration, development, and theoretical research, more and more shale condensate gas reservoirs are being discovered and gaining attention. In-depth research on the fluid flow patterns and phase changes in condensate gas reservoirs, as well as the application of technologies such as horizontal drilling and volumetric fracturing, has made shale condensate oil and gas extraction an economic reality, thereby increasing the importance of shale condensate gas reservoirs in oil and gas field development.

[0004] Condensate gas reservoirs are a common type of oil and gas reservoir. Compared to traditional gas reservoirs, condensate gas has better expandability, which can alleviate the reduction in reservoir pressure, thus resulting in higher production. However, the development of shale condensate gas reservoirs is relatively complex due to their more intricate flow mechanisms and the dense reservoir structure, which makes gas flow very difficult. To effectively develop shale condensate gas reservoirs, large-scale hydraulic fracturing is usually required to create highly conductive hydraulic fractures, thereby connecting natural and hydraulically induced fractures in the reservoir.

[0005] Numerous studies have shown that the mass balance method is a crucial approach for calculating mean formation pressure, estimating original geological reserves, and establishing production capacity equations. Calculating mean formation pressure using mass balance is fundamental to PVT property calculations. However, traditional volume conservation methods often neglect complex flow mechanisms such as adsorption / desorption and the influence of natural fracture networks. Furthermore, shale condensate gas reservoirs experience two-phase or even multi-phase flow during extraction, and current technologies have limited or overly complex studies on the mean formation pressure-time relationship in shale condensate gas reservoirs. Therefore, there is an urgent need to research precise mass balance methods for multiphase flow in shale condensate gas. Summary of the Invention

[0006] To address the aforementioned problems, this invention provides a method for calculating the mean formation pressure of a shale condensate oil and gas reservoir, comprising: obtaining geological characteristic parameters of the target shale condensate oil and gas reservoir; determining, based on the geological characteristic parameters, an oil and gas seepage control equation representing the oil and gas seepage characteristics within the target oil and gas reservoir, and an adsorption equation representing the adsorption characteristics of adsorbed gas within the target oil and gas reservoir; optimizing the gas phase seepage control equation using the adsorption equation to obtain an optimal oil and gas seepage control equation that conforms to reality; and determining, based on the optimal oil and gas seepage control equation, an ordinary differential equation concerning the mean formation pressure to obtain the mean formation pressure at different production stages.

[0007] Preferably, the step of determining the oil and gas seepage control equation includes: determining the continuity equations of the oil phase fluid and the gas phase fluid in the target oil and gas reservoir during the flow process based on the law of conservation of mass, thereby obtaining the volume conservation equations that match the oil phase fluid and the gas phase fluid respectively; determining the fluid motion equation of the target oil and gas reservoir based on Darcy's law, and further combining the volume conservation equations to form the oil and gas seepage control equation.

[0008] Preferably, in the step of determining the adsorption equation, the Langmuir isotherm adsorption equation is used as the adsorption equation.

[0009] Preferably, the step of determining the ordinary differential equation for mean formation pressure includes: adding the optimal oil phase flow control equation and the optimal gas phase flow control equation, then determining the boundary conditions, and converting the integral of the added equation with respect to volume into an integral with respect to the boundary, thereby obtaining the ordinary differential equation.

[0010] Preferably, the step of obtaining the average formation pressure during different production periods includes: solving the ordinary differential equation using the Runge-Kutta method to obtain the average formation pressure during different production periods.

[0011] Preferably, the oil and gas seepage control equation is expressed using the following expression:

[0012]

[0013]

[0014] in, Denotes the Hamiltonian operator, k o Indicates oil phase permeability, μ o Indicates the viscosity of the oil phase, B o Indicates the oil phase volume coefficient. Let t represent the pressure gradient and t represent time. S represents porosity. o k represents the degree of oil saturation. gRepresents gas phase permeability, μ g B represents the viscosity of the gas phase. g R represents the gas phase volume coefficient. so S represents the dissolved gas-oil ratio. g Indicates gas saturation.

[0015] Preferably, the optimal gas-phase flow control equation is expressed by the following expression:

[0016]

[0017] Where, ρ B V represents the matrix density. a This indicates the volume of adsorbed gas per unit mass.

[0018] Preferably, the geological characteristic parameters include, but are not limited to: PVT parameters and relative oil and gas permeability, wherein the PVT parameters include, but are not limited to: dissolved gas-oil ratio, volume factor, compressibility factor, and viscosity.

[0019] The present invention also provides a computer-readable storage medium comprising a series of instructions for performing method steps for calculating the mean formation pressure of a shale condensate oil and gas reservoir.

[0020] On the other hand, the present invention also provides a system for calculating the mean formation pressure of shale condensate oil and gas reservoirs. The system includes the following modules: a basic equation construction module, which is used to obtain the geological characteristic parameters of the target shale condensate oil and gas reservoir, and determine the oil and gas seepage control equation representing the oil and gas seepage characteristics in the target oil and gas reservoir, and the adsorption equation representing the adsorption characteristics of adsorbed gas in the target oil and gas reservoir based on the geological characteristic parameters; an equation optimization module, which is used to optimize the gas phase seepage control equation using the adsorption equation to obtain the optimal oil and gas seepage control equation that conforms to reality; and a mean formation pressure calculation module, which is used to determine the ordinary differential equation about the mean formation pressure based on the optimal oil and gas seepage control equation to obtain the mean formation pressure at different production periods.

[0021] Compared with the prior art, one or more embodiments of the above solutions may have the following advantages or beneficial effects:

[0022] This invention proposes a method and system for calculating the mean formation pressure of shale condensate gas reservoirs. The method first establishes a multiphase flow control equation (i.e., the optimal oil and gas flow control equation) considering the special mechanisms of shale condensate gas reservoirs (e.g., shale adsorption gas terms) based on the geological characteristic parameters of the target shale condensate gas reservoir. Then, the boundary conditions are determined based on the established multiphase flow control equation, and the ordinary differential equation concerning the mean formation pressure is determined by converting the integral of the equation with respect to volume to the integral with respect to the boundary. Finally, the Runge-Kutta method is used to solve the ordinary differential equation, obtaining the relationship between the mean formation pressure and time, thus obtaining the mean formation pressure at different production stages. This invention overcomes the deficiency in existing theoretical research on multiphase flow differential mass balance equations for shale condensate gas reservoirs, considers the two-phase flow of oil and gas caused by condensate oil precipitation, and achieves accurate calculation of the mean formation pressure at different production stages, providing technical support for production capacity evaluation. Furthermore, this invention is a semi-analytical method, requiring fewer parameters, and significantly improves the calculation speed compared to numerical simulation.

[0023] Other features and advantages of the invention will be set forth in the description which follows, and will be apparent in part from the description, or may be learned by practicing the invention. The objects and other advantages of the invention may be realized and obtained by means of the structures particularly pointed out in the description, claims, and drawings. Attached Figure Description

[0024] The accompanying drawings are provided to further illustrate the invention and form part of the specification. They are used in conjunction with the embodiments of the invention to explain the invention and do not constitute a limitation thereof. In the drawings:

[0025] Figure 1 This diagram illustrates the steps of a method for calculating the average formation pressure of a shale condensate oil and gas reservoir, as described in an embodiment of this application.

[0026] Figure 2 This is a block diagram of the system for calculating the average formation pressure of shale condensate oil and gas reservoirs according to an embodiment of this application. Detailed Implementation

[0027] The embodiments of the present invention will be described in detail below with reference to the accompanying drawings and examples, so that the process of how the present invention uses technical means to solve technical problems and achieve technical effects can be fully understood and implemented accordingly. It should be noted that, as long as there is no conflict, the various embodiments and features in the various embodiments of the present invention can be combined with each other, and the resulting technical solutions are all within the protection scope of the present invention.

[0028] Furthermore, the steps shown in the flowchart in the accompanying drawings can be executed in a computer system such as a set of computer-executable instructions, and although a logical order is shown in the flowchart, in some cases the steps shown or described may be executed in a different order than that shown here.

[0029] With the rapid growth in resource demand, global energy development has entered a critical stage of transition from fossil fuels to new energy sources. As the cleanest energy source among fossil fuels, natural gas is a crucial transitional element in this shift. Conventional natural gas resources are easy to extract but have small reserves. Shale gas, as a clean and efficient unconventional fossil energy source, has received widespread attention in recent years, with global shale gas production showing a year-on-year increasing trend. In the future, shale gas will occupy an important position in the global energy market.

[0030] With the deepening of exploration, development, and theoretical research, more and more shale condensate gas reservoirs are being discovered and gaining attention. In-depth research on the fluid flow patterns and phase changes in condensate gas reservoirs, as well as the application of technologies such as horizontal drilling and volumetric fracturing, has made shale condensate oil and gas extraction an economic reality, thereby increasing the importance of shale condensate gas reservoirs in oil and gas field development.

[0031] Condensate gas reservoirs are a common type of oil and gas reservoir. Compared to traditional gas reservoirs, condensate gas has better expandability, which can alleviate the reduction in reservoir pressure, thus resulting in higher production. However, the development of shale condensate gas reservoirs is relatively complex due to their more intricate flow mechanisms and the dense reservoir structure, which makes gas flow very difficult. To effectively develop shale condensate gas reservoirs, large-scale hydraulic fracturing is usually required to create highly conductive hydraulic fractures, thereby connecting natural and hydraulically induced fractures in the reservoir.

[0032] Numerous studies have shown that the mass balance method is a crucial approach for calculating mean formation pressure, estimating original geological reserves, and establishing production capacity equations. Calculating mean formation pressure using mass balance is fundamental to PVT property calculations. However, traditional volume conservation methods often neglect complex flow mechanisms such as adsorption / desorption and the influence of natural fracture networks. Furthermore, shale condensate gas reservoirs experience two-phase or even multi-phase flow during extraction, and current technologies have limited or overly complex studies on the mean formation pressure-time relationship in shale condensate gas reservoirs. Therefore, there is an urgent need to research precise mass balance methods for multiphase flow in shale condensate gas.

[0033] Therefore, to address the aforementioned problems, this invention proposes a method and system for calculating the mean formation pressure of shale condensate gas reservoirs. The method first establishes a multiphase flow control equation (i.e., the optimal oil and gas flow control equation) considering the special mechanisms of shale condensate gas reservoirs (e.g., shale adsorption gas terms) based on the geological characteristic parameters of the target shale condensate gas reservoir. Then, boundary conditions are determined based on the established multiphase flow control equation, and an ordinary differential equation concerning the mean formation pressure is determined by converting the integral of the equation with respect to volume to the integral with respect to the boundary. Finally, the Runge-Kutta method is used to solve the ordinary differential equation, obtaining the relationship between the mean formation pressure and time, thereby obtaining the mean formation pressure at different production stages. This invention overcomes the deficiency in existing theoretical research on multiphase flow differential mass balance equations for shale condensate gas reservoirs, considers the two-phase flow of oil and gas caused by condensate oil precipitation, and achieves accurate calculation of the mean formation pressure at different production stages, providing technical support for production capacity evaluation. Furthermore, this invention is a semi-analytical method, requiring fewer parameters, and significantly improves calculation speed compared to numerical simulation.

[0034] Example 1

[0035] Figure 1 This diagram illustrates the steps of a method for calculating the mean formation pressure of a shale condensate oil and gas reservoir according to an embodiment of this application. See below for reference. Figure 1 This will explain each step of the method.

[0036] like Figure 1 As shown, in step S110, the geological characteristic parameters of the target shale condensate oil and gas reservoir are obtained, and based on the geological characteristic parameters, the oil and gas seepage control equation representing the oil and gas seepage characteristics in the target oil and gas reservoir and the adsorption equation representing the adsorption characteristics of adsorbed gas in the target oil and gas reservoir are determined.

[0037] Specifically, this embodiment employs relevant empirical formulas to calculate the geological characteristic parameters required for calculating the average formation of shale condensate oil and gas reservoirs, thereby using the currently calculated geological characteristic parameters as the geological characteristic parameters of the target shale condensate oil and gas reservoir. After obtaining the geological characteristic parameters of the target shale condensate oil and gas reservoir, based on the current geological characteristic parameters, oil and gas seepage control equations representing the oil and gas seepage characteristics within the target oil and gas reservoir, and adsorption equations representing the adsorption characteristics of adsorbed gas within the target oil and gas reservoir, are constructed.

[0038] In one specific embodiment of this application, the geological characteristic parameters include, but are not limited to, PVT parameters and relative oil and gas permeability, wherein the PVT parameters include, but are not limited to, dissolved gas-oil ratio, volume factor, compressibility factor and viscosity.

[0039] First, the calculation process of the dissolved gas-oil ratio will be explained in detail.

[0040] At a specific temperature and pressure, the amount of gas dissolved in a unit volume of oil is defined as the dissolved gas-oil ratio (DGR). When the reservoir pressure is higher than the bubble point pressure, all gas dissolves in the oil, resulting in a maximum and constant DGR; when the reservoir pressure is lower than the bubble point pressure, the release of bubbles from the crude oil reduces the DGR. Therefore, this embodiment calculates the DGR based on the Standing correlation formula using the following expression:

[0041]

[0042] α=0.00091(T-460)-0.0125API (2)

[0043] Among them, R so Indicates the dissolved gas-oil ratio, γ g α represents the relative density of the gas phase, P represents the formation pressure, α represents the intermediate variable, T represents the formation temperature, and API represents the API gravity of crude oil.

[0044] Secondly, the calculation process of the volume factor is explained in detail.

[0045] During oil production, as oil pressure decreases under surface conditions, dissolved gases are released from the oil, resulting in oil shrinkage. The relationship between oil volume under reservoir and surface conditions is defined as the formation oil volume factor. In other words, the formation oil volume factor is the ratio of oil volume under reservoir conditions to the produced oil volume under standard conditions. Therefore, this embodiment also uses the Standing correlation formula to calculate the oil phase volume factor using the following expression:

[0046]

[0047] Among them, B o γ represents the oil phase volume coefficient. o This indicates the relative density of the oil phase.

[0048] The gas phase volume factor is the ratio of the volume of the same weight of natural gas under reservoir conditions to the volume of the same weight of natural gas under standard conditions. Therefore, this embodiment calculates the gas phase volume factor based on the real gas equation of state using the following expression:

[0049]

[0050] Among them, B g T represents the gas phase volume coefficient, n represents the amount of substance of the gas, Z represents the gas phase compressibility coefficient, and T represents the gas phase volume coefficient. sc P represents the formation temperature under standard conditions. sc This indicates the formation pressure under standard conditions.

[0051] Next, the calculation process of the compression coefficient will be explained in detail.

[0052] Crude oil compressibility plays a crucial role in oil production, serving as a primary mechanism for oil recovery from undersaturated reservoirs. The formation crude oil compressibility coefficient is defined as the ratio of the relative volume change of oil per unit pressure drop. Therefore, the oil-phase compressibility coefficient is calculated using the following expression:

[0053]

[0054] Among them, C o R represents the oil phase compressibility coefficient. sb γ represents the dissolved gas ratio at bubble point pressure. g This represents the relative density of a gas.

[0055] The compressibility factor of an isothermal gas refers to the relative change in gas volume per unit pressure change at a constant temperature. Natural gas is a compressible fluid, and its compressibility can be described using the real gas law. Therefore, this embodiment also uses the real gas law to calculate the gas-phase compressibility factor using the following expression:

[0056]

[0057] Among them, C g This represents the gas-phase compressibility coefficient.

[0058] Next, based on the empirical correlation of oil viscosity under bubble point pressure proposed by Chewe and Connally, this embodiment calculates the oil phase viscosity using the following expression:

[0059]

[0060] a = R so (2.2×10 -7 R so -7.4×10 -4 (8)

[0061] b = 0.68 × 10 c +0.25×10 d +0.062×10 e (9)

[0062] c = -0.0000862R so (10)

[0063] d = -0.0011R so (11)

[0064] e = -0.00374R so (12)

[0065] Where, μ o Indicates the viscosity of the oil phase, μ od The value represents the dead oil viscosity, and a, b, c, d, and e represent intermediate variables.

[0066] This embodiment is based on the gas viscosity prediction model proposed by Lee et al., and calculates the gas phase viscosity using the following expression:

[0067]

[0068]

[0069] y v =2.4-0.2x v (15)

[0070]

[0071] Where, μ g k represents the viscosity of the gas phase. v x v and y v ρ represents an intermediate variable, exp represents an exponential function, and ρ represents an intermediate variable. g MW represents the gas phase density, and MW represents the molecular weight of the mixture.

[0072] Finally, the calculation process for the relative permeability of oil and gas is explained in detail.

[0073] Based on the definition of relative permeability, the following formula applies to oil-gas two-phase systems:

[0074]

[0075]

[0076] Where, k g K represents the relative permeability of the gas phase. g K represents the gas phase permeability, and K represents the absolute permeability of the reservoir rock. o K represents the relative permeability of the oil phase. o This indicates the oil phase permeability.

[0077] This embodiment is based on the Brooks-Corey (MBC) model, and uses the aforementioned calculation formulas for oil and gas two-phase systems to obtain the relative permeability at the two-phase endpoints. The relative permeability of oil and gas is calculated using the following expression:

[0078]

[0079]

[0080] in, S represents the relative permeability at the oil phase endpoint. o Indicates oil saturation, S or Indicates residual oil saturation, n1 and n2 represent exponents, S gr Indicates residual gas saturation. This represents the relative permeability at the gas phase endpoint.

[0081] In the process of determining the control equations for oil and gas seepage, the continuity equations for the oil phase fluid and gas phase fluid in the target oil and gas reservoir are first determined based on the law of conservation of mass, and then the volume conservation equations that match the oil phase fluid and gas phase fluid are obtained respectively. Then, based on Darcy's law, the fluid motion equations of the target oil and gas reservoir are determined, and the volume conservation equations are further combined to form the control equations for oil and gas seepage.

[0082] Specifically, in a seepage system, the oil phase and gas phase each follow the law of conservation of mass during flow. Therefore, based on the law of conservation of mass, this embodiment determines the continuity equations for the oil phase fluid and gas phase fluid during the flow process within the target oil and gas reservoir, respectively. The continuity equations are expressed using the following expressions:

[0083]

[0084]

[0085] in, Represents the Hamiltonian operator, ρ o V represents the density of the oil phase. o The value represents the oil phase flow rate, and t represents time. V represents porosity. g S represents the gas phase flow rate. g Indicates gas saturation.

[0086] Next, based on the aforementioned continuity equation, volume conservation equations matching the oil phase fluid and the gas phase fluid are obtained respectively. The volume conservation equations matching the oil phase fluid and the gas phase fluid are expressed by the following expressions:

[0087]

[0088]

[0089] Subsequently, without considering capillary forces and gravity, the fluid motion equations for the target oil and gas reservoir are established based on Darcy's law. Then, the established fluid motion equations are substituted into the aforementioned volume conservation equations to obtain the oil and gas seepage control equations.

[0090] In this embodiment, the fluid motion equation is expressed using the following expression:

[0091]

[0092] Where i represents the oil phase or gas phase, v represents the flow rate, k represents the relative permeability, and μ represents the viscosity. This represents the pressure gradient.

[0093] In this embodiment, the control equation for oil and gas seepage is expressed by the following expression:

[0094]

[0095]

[0096] Next, the gas adsorbed on the shale surface conforms to the Langmuir isotherm adsorption equation. Therefore, in the step of determining the adsorption equation, this embodiment uses the Langmuir isotherm adsorption equation as the adsorption equation. The adsorption equation is expressed using the following expression:

[0097]

[0098] Among them, V a V represents the volume of adsorbed gas per unit mass. m denoted by Langmuir volume, p by reservoir pressure, and b0 by Langmuir constant.

[0099] Furthermore, in step S120, the gas phase seepage control equation is optimized using the adsorption equation to obtain the optimal oil and gas seepage control equation that conforms to reality.

[0100] Specifically, this embodiment considers the influence of adsorbed gas terms on the oil and gas seepage state, and incorporates the adsorption equation into the oil and gas seepage control equation to optimize the gas phase seepage control equation. This makes the oil and gas seepage control equation (i.e., the optimal oil and gas seepage control equation), composed of the current oil phase seepage control equation and the optimized optimal gas phase seepage control equation, more consistent with reality. Based on the optimal oil and gas seepage control equation, this invention determines the ordinary differential equation regarding average formation pressure, providing a guarantee for accurately calculating the average formation pressure of shale condensate oil and gas reservoirs.

[0101] In this embodiment, the optimal gas-phase flow control equation is expressed by the following expression:

[0102]

[0103] Where, ρ B This indicates the matrix density.

[0104] Furthermore, in step S130, an ordinary differential equation for the average formation pressure is determined based on the optimal oil and gas seepage control equation, so as to obtain the average formation pressure at different production periods.

[0105] Specifically, this embodiment derives an ordinary differential equation concerning average formation pressure, which serves as the differential mass balance equation, based on the optimal oil and gas flow control equation. Then, by solving this ordinary differential equation, the average formation pressure at different production stages is obtained.

[0106] In the steps of determining the ordinary differential equation for mean formation pressure, the optimal oil phase flow control equation and the optimal gas phase flow control equation are added together. Then the boundary conditions are determined, and the integral over volume is converted into an integral over the boundary using the Otto-Gau formula. The resulting ordinary differential equation for mean formation pressure is the differential mass balance equation.

[0107] In this embodiment, the optimal oil phase flow control equation and the optimal gas phase flow control equation are added together to obtain the following equation after addition:

[0108]

[0109] Next, based on the equations obtained by addition, the following inner and outer boundary conditions are determined:

[0110]

[0111]

[0112] Among them, S 内 Let S represent the area of ​​the inner boundary, S represent the area of ​​the integral object, and q represent the oil and gas production. 外 This represents the area of ​​the outer boundary.

[0113] After obtaining the summed equation, in addition to determining the aforementioned boundary conditions, we also achieve the goal of simultaneously adding point source terms related to formation pressure to both sides of the summed equation by integrating both sides with respect to the formation volume and then dividing by the formation volume. Then, we use the combined domain integration method to integrate the equation with the added point source terms related to formation pressure, obtaining the following integrated equation:

[0114]

[0115] Where V represents the formation volume.

[0116] Furthermore, the process of obtaining the ordinary differential equation is explained in detail.

[0117] First, the integrated equation is combined with the aforementioned boundary conditions to process the current integrated equation. The left and right sides of the processed equation are expressed by the following expressions:

[0118]

[0119]

[0120] in, S represents the mean formation pressure. o ′ represents the derivative of oil saturation with respect to mean pressure, B o ′ represents the derivative of the oil phase volume coefficient with respect to the mean pressure, S g ′ represents the derivative of gas saturation with respect to mean pressure, B g R′ represents the derivative of the gas phase volume coefficient with respect to the mean pressure. so This represents the derivative of the dissolved gas-oil ratio with respect to the average pressure.

[0121] Next, the pore volume compressibility coefficient is obtained using the following expression, and the oil phase compressibility coefficient and gas phase compressibility coefficient are obtained in a manner different from the aforementioned method:

[0122]

[0123]

[0124]

[0125] in, This represents the pore volume compressibility coefficient.

[0126] At this point, transforming the right-hand side of the currently processed equation yields the following expression used to form the ordinary differential equation:

[0127]

[0128]

[0129]

[0130]

[0131] Where λ(o) represents the intermediate variable with respect to the oil phase, λ(g) represents the intermediate variable with respect to the gas phase, and λ(a) represents the intermediate variable with respect to the adsorbed gas.

[0132] In this embodiment of the application, the ordinary differential equation is represented by the following expression:

[0133]

[0134] In the step of obtaining the average formation pressure during different production periods, the Runge-Kutta method is used to solve the ordinary differential equation to obtain the average formation pressure during different production periods.

[0135] In this embodiment of the application, after transforming formula (43), the transformed formula can be regarded as Here, f(p) is a function of formation pressure. The Runge-Kutta method is then used to solve the ordinary differential equation to obtain the relationship between mean formation pressure and time, thus enabling the determination of mean formation pressure during different production periods.

[0136] Example 2

[0137] This invention also provides a computer-readable storage medium storing at least one instruction that is loaded and executed by a processor to perform the operation of calculating the mean formation pressure of a shale condensate oil and gas reservoir as performed in the method of the above embodiments. For example, the computer-readable storage medium may be a ROM (Read Only Memory), RAM (Random Access Memory), CD-ROM (Compact Disc-Read Only Memory), magnetic tape, floppy disk, or optical data storage device, etc.

[0138] Example 3

[0139] Based on the method for calculating the average formation pressure of shale condensate oil and gas reservoirs described in Embodiment 1 above, this embodiment of the invention also provides a system for calculating the average formation pressure of shale condensate oil and gas reservoirs.

[0140] Figure 2 This is a block diagram of the system for calculating the average formation pressure of shale condensate oil and gas reservoirs, as described in an embodiment of this application. Figure 2 As shown, the system for calculating the average formation pressure of shale condensate oil and gas reservoirs in this embodiment of the invention includes: a basic equation construction module 21, an equation optimization module 22, and an average formation pressure calculation module 23. Specifically, the basic equation construction module 21 is implemented according to the method described in step S110 above, configured to obtain the geological characteristic parameters of the target shale condensate oil and gas reservoir, and determine the oil and gas seepage control equation representing the oil and gas seepage characteristics in the target oil and gas reservoir, and the adsorption equation representing the adsorption characteristics of adsorbed gas in the target oil and gas reservoir, based on the geological characteristic parameters; the equation optimization module 22 is implemented according to the method described in step S120 above, configured to optimize the gas phase seepage control equation using the adsorption equation to obtain the optimal oil and gas seepage control equation that conforms to reality; the average formation pressure calculation module 23 is implemented according to the method described in step S130 above, configured to determine the ordinary differential equation about the average formation pressure based on the optimal oil and gas seepage control equation, so as to obtain the average formation pressure at different production periods.

[0141] This invention discloses a method and system for calculating the mean formation pressure of shale condensate gas reservoirs. The method first establishes a multiphase flow control equation (i.e., the optimal oil and gas flow control equation) considering the special mechanisms of shale condensate gas reservoirs (e.g., shale adsorption gas terms) based on the geological characteristic parameters of the target shale condensate gas reservoir. Then, the boundary conditions are determined based on the established multiphase flow control equation, and the ordinary differential equation concerning the mean formation pressure is determined by converting the integral of the equation with respect to volume to the integral with respect to the boundary. Finally, the Runge-Kutta method is used to solve the ordinary differential equation, obtaining the relationship between the mean formation pressure and time, thereby obtaining the mean formation pressure at different production stages. This invention overcomes the deficiency in existing theoretical research on multiphase flow differential material balance equations for shale condensate gas reservoirs, considers the two-phase flow of oil and gas caused by condensate oil precipitation, and achieves accurate calculation of the mean formation pressure at different production stages, providing technical support for production capacity evaluation. Furthermore, this invention is a semi-analytical method, requiring fewer parameters, and significantly improves the calculation speed compared to numerical simulation.

[0142] The above description is merely a preferred embodiment of the present invention, but the scope of protection of the present invention is not limited thereto. Any variations or substitutions that can be easily conceived by those skilled in the art within the technical scope disclosed in the present invention should be included within the scope of protection of the present invention. Therefore, the scope of protection of the present invention should be determined by the scope of the claims.

[0143] Of course, the present invention may have other various embodiments. Without departing from the spirit and essence of the present invention, those skilled in the art can make various corresponding changes and modifications according to the present invention, but these corresponding changes and modifications should all fall within the protection scope of the claims of the present invention.

[0144] Those skilled in the art will understand that the modules or steps of the present invention described above can be implemented using general-purpose computing devices. They can be centralized on a single computing device or distributed across a network of multiple computing devices. Optionally, they can be implemented using computer-executable program code, thereby storing them in a storage device for execution by a computing device, or fabricating them separately as individual integrated circuit modules, or fabricating multiple modules or steps as a single integrated circuit module. Thus, the present invention is not limited to any particular hardware and software combination.

[0145] While the embodiments disclosed in this invention are as described above, the content is merely for the purpose of facilitating understanding of the invention and is not intended to limit the invention. Any person skilled in the art to which this invention pertains may make any modifications and variations in form and detail of the implementation without departing from the spirit and scope disclosed herein; however, the scope of patent protection for this invention shall still be determined by the scope defined in the appended claims.

Claims

1. A method for calculating the mean formation pressure of shale condensate oil and gas reservoirs, characterized in that, include: Obtain the geological characteristic parameters of the target shale condensate oil and gas reservoir, and based on the geological characteristic parameters, determine the oil and gas seepage control equation representing the oil and gas seepage characteristics in the target oil and gas reservoir, and the adsorption equation representing the adsorption characteristics of adsorbed gas in the target oil and gas reservoir. The adsorption equation was used to optimize the gas phase seepage control equation, and the optimal oil and gas seepage control equation that conforms to reality was obtained. Based on the optimal oil and gas flow control equation, an ordinary differential equation for the average formation pressure is determined to obtain the average formation pressure at different production stages.

2. The method according to claim 1, characterized in that, The step of determining the governing equations for oil and gas seepage includes: Based on the law of conservation of mass, the continuity equations for the oil phase fluid and gas phase fluid in the target oil and gas reservoir during the flow process are determined respectively, and then the volume conservation equations that match the oil phase fluid and gas phase fluid are obtained respectively. Based on Darcy's law, the fluid motion equation of the target oil and gas reservoir is determined, and further combined with the volume conservation equation, the oil and gas seepage control equation is formed.

3. The method according to claim 1 or 2, characterized in that, In the step of determining the adsorption equation, the Langmuir isotherm adsorption equation is used as the adsorption equation.

4. The method according to any one of claims 1 to 3, characterized in that, The steps in determining the ordinary differential equation for mean formation pressure include: The optimal oil phase flow control equation and the optimal gas phase flow control equation are added together, the boundary conditions are determined, and the integral of the added equation with respect to volume is converted into an integral with respect to the boundary, thereby obtaining the ordinary differential equation.

5. The method according to any one of claims 1 to 4, characterized in that, The steps for obtaining the average formation pressure during different production periods include: The Runge-Kutta method was used to solve the ordinary differential equation to obtain the average formation pressure during different production periods.

6. The method according to claim 2, characterized in that, The oil and gas seepage control equation is expressed by the following expression: in, Denotes the Hamiltonian operator, k o Indicates oil phase permeability, μ o B represents the viscosity of the oil phase. o Indicates the oil phase volume factor. Let t represent the pressure gradient and t represent time. S represents porosity. o k represents the degree of oil saturation. g Represents gas phase permeability, μ g B represents the viscosity of the gas phase. g R represents the gas phase volume coefficient. so S represents the dissolved gas-oil ratio. g Indicates gas saturation.

7. The method according to claim 6, characterized in that, The optimal gas-phase flow control equation is expressed by the following expression: Where, ρ B V represents the matrix density. a This indicates the volume of adsorbed gas per unit mass.

8. The method according to any one of claims 1 to 7, characterized in that, The geological characteristic parameters include, but are not limited to: PVT parameters and relative oil and gas permeability, wherein, The PVT parameters include, but are not limited to: dissolved gas-oil ratio, volume factor, compressibility factor, and viscosity.

9. A computer-readable storage medium, characterized in that, It includes a series of instructions for performing the method steps of calculating the mean formation pressure of a shale condensate oil and gas reservoir as described in any one of claims 1 to 8.

10. A system for calculating the mean formation pressure of shale condensate oil and gas reservoirs, characterized in that, The system includes the following modules: The basic equation construction module is used to obtain the geological characteristic parameters of the target shale condensate oil and gas reservoir, and based on the geological characteristic parameters, to determine the oil and gas seepage control equation representing the oil and gas seepage characteristics in the target oil and gas reservoir, and the adsorption equation representing the adsorption characteristics of adsorbed gas in the target oil and gas reservoir. The equation optimization module is used to optimize the gas phase seepage control equation using the adsorption equation to obtain the optimal oil and gas seepage control equation that conforms to reality. The mean formation pressure calculation module is used to determine the ordinary differential equation for mean formation pressure based on the optimal oil and gas flow control equation, so as to obtain the mean formation pressure at different production periods.

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