Numerical simulation characterization method and system based on low-permeability oil field pressure drive oil increasing mechanism

Abstract

The invention discloses a numerical simulation characterization method and system based on a pressure-driving oil increasing mechanism of a low-permeability oil field, and relates to the technical field of oil-gas field development, and the method comprises the steps: building a fluid pressure-crustal stress-physical property coupling equation set based on the total stress tensor of a target low-permeability oil field, calculating a time-varying porosity field, a time-varying permeability field and pressure-driving fracture dynamic expansion parameters of the target low-permeability oil field; establishing a fracture conductivity attenuation function of the target low-permeability oil field based on fracture long-term conductivity test experimental data; respectively establishing a dynamic relative permeability curve control function and a dynamic capillary force curve control function of the target low-permeability oil field based on unsteady-state method relative permeability curve test experimental data and mercury injection experimental data; and establishing a numerical simulation model of the target low-permeability oil field, and performing numerical simulation characterization on the oil increasing mechanism in the pressure driving process of the target low-permeability oil field. The technical problem that in the prior art, coupling characterization means for various pressure-driving oil increasing mechanisms are lacked is solved.

Description

Technical Field

[0001] The invention relates to the technical field of oil and gas field development, and in particular to a numerical simulation characterization method and system based on a pressure-driven oil-increasing mechanism in a low-permeability oil field. Background Art

[0002] Low permeability reservoirs have abundant reserves, but their reservoir properties are poor and pressure conduction is slow. Conventional fracturing, water drive and chemical drive methods have a series of problems such as poor well connectivity, slow energy replenishment, low single well production capacity and poor development effect. Based on this situation, domestic oil and gas companies have proposed integrated fracturing oil recovery technology, also known as "pressure drive" through technical research. Pressure drive technology is an oil reservoir development technology that organically combines single well fracturing production increase technology, conventional water drive development technology and chemical agent oil recovery technology. Through hydraulic fracturing equipment, clean water and oil recovery agents are injected into the formation at high pressure and high speed to quickly replenish the energy of the oil reservoir and increase the pressure of the oil reservoir in a short time, so as to realize the opening of micro-cracks, increasing porosity and permeability, imbibition and oil replacement, oil recovery agent washing and other pressure drive oil recovery mechanisms, and improve the recovery rate of low permeability oil reservoirs.

[0003] Pressure-driven technology is a reservoir development and production-increasing technology that couples multiple oil-increasing mechanisms. Large-volume high-pressure water injection increases the pore fluid pressure around the wellbore, replenishes formation energy, expands pore size, and improves reservoir seepage performance; when the fluid injection pressure is close to the formation fracture pressure, natural micro-cracks and micro-cracks in the near-wellbore area open, and the injected water can more easily enter the deep reservoir, effectively expanding the affected area, while expanding the contact surface between the injected water and the formation crude oil, increasing the imbibition oil exchange and oil displacement agent washing effect.

[0004] The key to pressure-driven technology lies in the optimization design of injection parameters, and clarifying the applicable scope and degree of oil-increasing mechanisms of different pressure-driven technologies plays a key role in guiding parameter optimization design. The current research progress of pressure-driven mechanisms lags significantly behind field practice, and pressure-driven process design is mainly based on experience. There is no specific numerical simulation method for pressure-driven technology, and there is a lack of coupling characterization methods for multiple pressure-driven oil-increasing mechanisms. Summary of the invention

[0005] The purpose of the present invention is to provide a numerical simulation characterization method and system based on the pressure-driven oil-increasing mechanism of low-permeability oil fields in order to solve at least one of the above technical problems.

[0006] In the first aspect, an embodiment of the present invention provides a numerical simulation characterization method based on the pressure-driven oil-increasing mechanism of a low-permeability oil field, which is applied to a target low-permeability oil field; the method comprises: establishing a fluid pressure-ground stress-physical property coupling equation group based on the total stress tensor of the target low-permeability oil field; calculating the time-varying porosity field, time-varying permeability field and dynamic expansion parameters of pressure-driven fractures of the target low-permeability oil field based on the fluid pressure-ground stress-physical property coupling equation group; establishing a fracture conductivity attenuation function of the target low-permeability oil field based on the experimental data of the long-term conductivity test of the fracture; and calculating the relative permeability curve based on the non-steady-state method. The method comprises the following steps: based on the line test experimental data and the mercury injection experimental data, respectively establishing the dynamic phase permeability curve control function and the dynamic capillary force curve control function of the target low permeability oilfield; based on the fluid pressure-stress-physical property coupling equation group, the time-varying porosity field, the time-varying permeability field, the pressure-driven fracture dynamic expansion parameter, the fracture conductivity attenuation function, the dynamic phase permeability curve control function and the dynamic capillary force curve control function, establishing a numerical simulation model of the target low permeability oilfield; based on the numerical simulation model, numerically simulating and characterizing the oil increase mechanism during the pressure drive process of the target low permeability oilfield.

[0007] Furthermore, the fluid pressure-geo-stress-physical property coupling equation group includes:

[0008]

[0009] Where N c is the molar density of component c, S P is the P phase saturation, x c,P is the mole fraction of the c component P phase, ξ P is the molar density of phase P, is the stratum displacement vector, ρ r is the rock density at reference pressure, α is the Biot constant, is the total initial stress tensor in the formation, is the initial strain tensor, p0 is the initial pore pressure, λ and μ are functions of Young's modulus and Poisson's ratio, t is time, φ is the time-varying porosity field, O, W, G represent the oil phase, water phase and gas phase respectively, U P represents the seepage velocity vector, q c represents the inflow velocity of the P phase of the c component, p represents the pore pressure, σ ij is the total formation stress tensor, ∈ ij is the total strain tensor, δ ij is the Kronecker symbol.

[0010] Further, based on the fluid pressure-ground stress-physical property coupling equation group, the time-varying porosity field, the time-varying permeability field and the dynamic expansion parameters of the pressure-driven fracture of the target low-permeability oil field are calculated, including: the calculation formula of the time-varying porosity field includes:

[0011]

[0012] Wherein, φ is the time-varying porosity field; based on the relationship between the permeability retention coefficient and stress obtained from the core pressure drive experiment and the fluid pressure-ground stress-physical property coupling equation group, the time-varying permeability field is calculated; wherein, the relationship between the permeability retention coefficient and stress includes:

[0013]

[0014] Wherein, K is permeability, K0 is the initial permeability of the reservoir of the target low-permeability oilfield, σ is effective stress, A and B are adjustment variables for fitting the core pressure-drive experiment; based on the Mohr-Coulomb strength criterion and the fluid pressure-ground stress-physical property coupling equation group, the dynamic expansion parameters of the pressure-driven fractures in the pressure-drive process of the target low-permeability oilfield are calculated.

[0015] Furthermore, the fracture conductivity attenuation function includes:

[0016]

[0017] Where F is the fracture conductivity, F0 is the initial fracture conductivity, C is the tuning parameter for fitting the fracture conductivity attenuation experiment, and t is time.

[0018] Furthermore, based on the non-steady-state relative permeability curve test experimental data and the mercury injection test data, a dynamic phase permeability curve control function and a dynamic capillary force curve control function of the target low-permeability oil field are respectively established, including: based on the non-steady-state relative permeability curve test experimental data, a water drive relative permeability curve, a pressure drive relative permeability curve and a surfactant drive relative permeability curve are obtained; based on the water drive relative permeability curve, the pressure drive relative permeability curve and the surfactant drive relative permeability curve, a dynamic phase permeability curve control function with pressure and surfactant concentration as independent variables is established; based on the mercury injection test data, imbibition capillary force data, displacement capillary force data and the relationship between surfactant concentration and oil-water interfacial tension are obtained; based on the imbibition capillary force data, the displacement capillary force data and the relationship between surfactant concentration and oil-water interfacial tension, a dynamic capillary force curve control function with wetting order and surfactant concentration as independent variables is established.

[0019] Furthermore, the dynamic phase permeability curve control function includes:

[0020]

[0021] In the formula, p is pressure, C is surfactant concentration, K ri is the relative permeability of phase i, P surf+p is the pressure of the relative permeability curve of surfactant pressure drive, C surf is the surfactant concentration of the relative permeability of surfactant flooding, is the water flooding relative permeability curve, is the relative permeability curve of surfactant flooding, This is the relative permeability curve of surfactant pressure drive.

[0022] Further, the dynamic capillary force curve control function includes a dynamic capillary force curve control function with surfactant concentration as an independent variable and a dynamic capillary force curve control function with wetting order as an independent variable; wherein the dynamic capillary force curve control function with surfactant concentration as an independent variable includes:

[0023]

[0024] Where P cow is the oil-water capillary force, σ ow is the oil-water interfacial tension with surfactant concentration as the independent variable, σ Hg is the interfacial tension between mercury and air, θ ow is the oil-water contact angle, θ Hg is the contact angle between mercury and air, P Hg is the capillary force between mercury and air; the dynamic capillary force curve control function with the wetting order as the independent variable includes:

[0025] p c =(1-f)p cD +fp cI

[0026]

[0027] In the formula, p c is the capillary force, p cD is the capillary force, p cI is the capillary force of infiltration, S w is water saturation, S wi is the initial water saturation, S w max is the maximum achievable water saturation, and E is the curve parameter.

[0028] In the second aspect, an embodiment of the present invention further provides a numerical simulation characterization system based on the pressure-driven oil-increasing mechanism of a low-permeability oil field, which is applied to a target low-permeability oil field; it includes: a first establishment module, a calculation module, a second establishment module, a third establishment module, a fourth establishment module and a simulation characterization module; wherein the first establishment module is used to establish a fluid pressure-ground stress-physical property coupling equation group based on the total stress tensor of the target low-permeability oil field; the calculation module is used to calculate the time-varying porosity field, time-varying permeability field and dynamic expansion parameters of pressure-driven fractures of the target low-permeability oil field based on the fluid pressure-ground stress-physical property coupling equation group; the second establishment module is used to establish the fracture conductivity of the target low-permeability oil field based on the long-term conductivity test experimental data of the fracture capacity attenuation function; the third establishment module is used to establish the dynamic phase permeability curve control function and the dynamic capillary force curve control function of the target low permeability oil field based on the non-steady-state relative permeability curve test experimental data and the mercury injection experimental data; the fourth establishment module is used to establish the numerical simulation model of the target low permeability oil field based on the fluid pressure-stress-physical property coupling equation group, the time-varying porosity field, the time-varying permeability field, the pressure-driven fracture dynamic expansion parameter, the fracture conductivity attenuation function, the dynamic phase permeability curve control function and the dynamic capillary force curve control function; the simulation characterization module is used to perform numerical simulation characterization on the oil increase mechanism during the pressure drive process of the target low permeability oil field based on the numerical simulation model.

[0029] In a third aspect, an embodiment of the present invention further provides an electronic device, comprising: a memory, a processor, and a computer program stored in the memory and executable on the processor, wherein the processor implements the method provided in the embodiment of the present invention when executing the computer program.

[0030] In a fourth aspect, an embodiment of the present invention further provides a computer-readable storage medium, wherein the computer-readable storage medium stores computer instructions, and when the computer instructions are executed by a processor, the method provided in the embodiment of the present invention is implemented.

[0031] The present invention provides a numerical simulation characterization method and system based on the pressure-driven oil-increasing mechanism of low-permeability oil fields. Based on experimental data such as core pressure-driven experiments, non-steady-state relative permeability curve test experiments, mercury injection experiments, and fracture long-term conductivity test experiments, a control equation is constructed to introduce a conventional numerical simulation model, and the pressure-driven oil-increasing mechanism of low-permeability oil fields is coupled to characterize, thereby improving the pressure-driven simulation accuracy and alleviating the technical problem of the lack of coupled characterization means for multiple pressure-driven oil-increasing mechanisms in the prior art. BRIEF DESCRIPTION OF THE DRAWINGS

[0032] In order to more clearly illustrate the implementation methods of the present application or the technical solutions in the prior art, the drawings required for use in the specific implementation methods or the description of the prior art will be briefly introduced below. Obviously, the drawings described below are some implementation methods of the present application. For ordinary technicians in this field, other drawings can be obtained based on these drawings without paying any creative work.

[0033] Figure 1 A flow chart of a numerical simulation characterization method based on the pressure-driven oil-increasing mechanism of a low-permeability oil field provided by an embodiment of the present invention;

[0034] Figure 2 A flow chart of another numerical simulation characterization method based on the pressure-driven oil-increasing mechanism of a low-permeability oil field provided by an embodiment of the present invention;

[0035] Figure 3 A schematic diagram of a fitting curve of the relationship between permeability retention coefficient and stress provided in an embodiment of the present invention;

[0036] Figure 4 A flow chart for calculating the dynamic extension length and orientation of a pressure-driven crack provided in an embodiment of the present invention;

[0037] Figure 5 A schematic diagram of a fracture conductivity attenuation function curve provided by an embodiment of the present invention;

[0038] Figure 6 A schematic diagram of a phase permeability curve under water drive, pressure drive and surfactant drive conditions provided by an embodiment of the present invention;

[0039] Figure 7 A schematic diagram of a capillary force data curve of mercury injection experiment imbibition and expulsion provided by an embodiment of the present invention;

[0040] Figure 8 A schematic diagram of a history fitting curve of a numerical simulation model provided by an embodiment of the present invention;

[0041] Fig. 9 A schematic diagram of a history fitting curve of a conventional numerical simulation model provided in an embodiment of the present invention without considering the characterization of the fine pressure-driven oil-increasing mechanism;

[0042] Fig.10 A schematic diagram of a numerical simulation characterization system based on the pressure-driven oil-increasing mechanism in a low-permeability oil field provided in an embodiment of the present invention. DETAILED DESCRIPTION

[0043] The following will be combined with the drawings in the embodiments of the present invention to clearly and completely describe the technical solutions in the embodiments of the present invention. Obviously, the described embodiments are only part of the embodiments of the present invention, not all of the embodiments. Based on the embodiments of the present invention, all other embodiments obtained by ordinary technicians in this field without creative work are within the scope of protection of the present invention.

[0044] Embodiment 1

[0045] Figure 1 1 is a flow chart of a numerical simulation characterization method based on the pressure-driven oil-increasing mechanism of a low-permeability oil field provided in accordance with an embodiment of the present invention, and the method is applied to a target low-permeability oil field. Figure 1 As shown, the method specifically comprises the following steps:

[0046] Step S102, based on the total stress tensor of the target low-permeability oil field, establish a fluid pressure-ground stress-physical property coupling equation group.

[0047] Step S104, based on the fluid pressure-in-situ stress-physical property coupling equation group, calculate the time-varying porosity field, time-varying permeability field and pressure-driven fracture dynamic expansion parameters of the target low-permeability oil field.

[0048] Step S106, establishing a fracture conductivity attenuation function of the target low permeability oil field based on the fracture long-term conductivity test experimental data.

[0049] Step S108, based on the non-steady-state relative permeability curve test experimental data and the mercury injection experimental data, respectively establish a dynamic relative permeability curve control function and a dynamic capillary force curve control function of the target low permeability oil field.

[0050] Step S110, based on the fluid pressure-geo-stress-physical property coupling equations, time-varying porosity field, time-varying permeability field, pressure-driven fracture dynamic expansion parameters, fracture conductivity attenuation function, dynamic phase permeability curve control function and dynamic capillary force curve control function, a numerical simulation model of the target low permeability oil field is established.

[0051] Step S112, based on the numerical simulation model, numerical simulation characterization is performed on the oil-increasing mechanism in the pressure-driven process of the target low-permeability oil field, wherein the characterized oil-increasing mechanism includes time-varying geostress field, time-varying porosity and permeability, time-varying phase permeability, and imbibition replacement mechanisms.

[0052] Specifically, the fluid pressure-ground stress-physical property coupling equations include:

[0053]

[0054]

[0055] Where N cis the molar density of component c, S P is the P phase saturation, x c,P is the mole fraction of the c component P phase, ξ P is the molar density of phase P, is the stratum displacement vector, ρ r is the rock density at reference pressure, α is the Biot constant, is the total initial stress tensor in the formation, is the initial strain tensor, p0 is the initial pore pressure, λ and μ are functions of Young's modulus and Poisson's ratio, φ is the time-varying porosity field, O, W, G represent the oil phase, water phase and gas phase respectively, U P represents the seepage velocity vector, q c represents the inflow velocity of the P phase of the c component, p represents the pore pressure, σ ij is the total formation stress tensor, ∈ ij is the total strain tensor, δ ij is the Kronecker symbol, when i=j, δ ij =1, i≠j, δ ij =0.

[0056] Optionally, in the embodiment of the present invention, Young's modulus and Poisson's ratio are used to define the elastic characteristics of the rock. Specifically,

[0057]

[0058] Where E is Young's modulus and ν is Poisson's ratio.

[0059] Specifically, in step S104, the calculation formula for the time-varying porosity field includes:

[0060]

[0061] Where φ is the time-varying porosity field;

[0062] Based on the relationship between permeability retention coefficient and stress obtained from core pressure drive experiments and the fluid pressure-geo-stress-physical property coupling equation group, the time-varying permeability field is calculated; among which, the relationship between permeability retention coefficient and stress includes:

[0063]

[0064] Where K is the permeability, K0 is the initial permeability of the reservoir of the target low-permeability oil field, σ is the effective stress, and A and B are the adjustment variables for fitting the core pressure drive experiment.

[0065] Specifically, in step S104, the Mohr-Coulomb strength criterion, the Griffiths criterion or the expansion criterion is introduced to calculate the dynamic expansion parameters of the pressure-driven cracks in the pressure-driven process according to the time-varying ground stress field, Young's modulus, Poisson's ratio, etc. The dynamic expansion parameters of the pressure-driven cracks include the dynamic expansion length and orientation of the pressure-driven cracks.

[0066] Preferably, the dynamic expansion parameters of pressure-driven fractures in the pressure-driven process of the target low-permeability oil field are calculated based on the Mohr-Coulomb strength criterion and the fluid pressure-ground stress-physical property coupling equation group. Specifically, the method for judging the dynamic expansion of fractures based on the Mohr-Coulomb strength criterion includes:

[0067] σ1―σ3=(σ1+σ3)sinθ+2c·cosθ

[0068] Where σ1 and σ3 are the maximum and minimum principal stresses on the plane, θ is the friction angle, and c is the cohesion.

[0069] Specifically, the fracture conductivity attenuation function in step S106 includes:

[0070]

[0071] Where F is the fracture conductivity, F0 is the initial fracture conductivity, C is the tuning parameter for fitting the fracture conductivity attenuation experiment, and t is time.

[0072] Specifically, step S108 also includes the following steps:

[0073] Step S1081, based on the relative permeability curve test experimental data of the non-steady-state method, a water drive relative permeability curve, a pressure drive relative permeability curve and a surfactant drive relative permeability curve are obtained.

[0074] Step S1082: Based on the water drive relative permeability curve, the pressure drive relative permeability curve and the surfactant drive relative permeability curve, a dynamic phase permeability curve control function with pressure and surfactant concentration as independent variables is established. The dynamic phase permeability curve control function includes:

[0075]

[0076] In the formula, p is pressure, C is surfactant concentration, K ri is the relative permeability of phase i, P surf+p is the pressure of the relative permeability curve of surfactant pressure drive, C surf is the surfactant concentration of the relative permeability of surfactant flooding, is the water flooding relative permeability curve, is the relative permeability curve of surfactant flooding, This is the relative permeability curve of surfactant pressure drive.

[0077] Step S1083, based on the mercury injection test data, obtain the imbibition capillary force data, the displacement capillary force data and the relationship between the surfactant concentration and the oil-water interfacial tension.

[0078] Step S1084, based on the imbibition capillary force data, the displacement capillary force data and the relationship between surfactant concentration and oil-water interfacial tension, a dynamic capillary force curve control function with wetting sequence and surfactant concentration as independent variables is established.

[0079] Specifically, the dynamic capillary force curve control function includes a dynamic capillary force curve control function with surfactant concentration as an independent variable and a dynamic capillary force curve control function with wetting order as an independent variable; wherein,

[0080] The dynamic capillary force curve control function with surfactant concentration as the independent variable includes:

[0081]

[0082] Where P cow is the oil-water capillary force, σ ow is the oil-water interfacial tension with surfactant concentration as the independent variable, σ Hg is the interfacial tension between mercury and air, θ ow is the oil-water contact angle, θ Hg is the contact angle between mercury and air, P Hg is the capillary force between mercury and air;

[0083] The dynamic capillary force curve control function with wetting order as the independent variable includes:

[0084] p c =(1-f)p cD +fp cI

[0085]

[0086] In the formula, p c is the capillary force, p cD is the capillary force, p cI is the capillary force of infiltration, S w is water saturation, S wi is the initial water saturation, S w max is the maximum achievable water saturation, E is a curve parameter, and in this embodiment, the value is E=0.05.

[0087] Specifically, the embodiment of the present invention provides a numerical simulation characterization method based on the pressure-driven oil-increasing mechanism of low-permeability oil fields. First, based on the geological model and mechanical model of the target low-permeability oil field, the numerical simulation and history matching of the reservoir are carried out, so that the constructed numerical simulation model of the reservoir can characterize the production characteristics of the target low-permeability oil field. When simulating the pressure-driven process, the designed pressure-driven injection liquid displacement and total liquid volume are injected. Based on the fluid pressure-ground stress-physical property coupling equation group, the reservoir fluid pressure-ground stress-physical property changes caused by the injected liquid are calculated, and the time-varying mechanism of the ground stress field and the time-varying porosity and permeability are simulated. Based on the Mohr-Coulomb strength criterion and the fluid pressure-ground stress-physical property coupling equation group, the dynamic expansion parameters of the pressure-driven cracks in the pressure-driven process of the target low-permeability oil field are calculated, and the expansion mechanism of the fracturing cracks is simulated. The changes in the formation pressure and the concentration of the fluid surfactant caused by the external liquid cause the phase permeability and capillary force curves to change in real time, thereby simulating the mechanism of the phase permeability time-varying and the imbibition replacement.

[0088] The embodiment of the present invention provides a numerical simulation characterization method based on the pressure-driven oil-increasing mechanism of low-permeability oil fields. According to the pressure-driven characteristics of low-permeability oil layers, time-varying geostress field, time-varying porosity field, time-varying permeability field, dynamic expansion of pressure-driven fractures, attenuation of fracture conductivity, dynamic phase permeability curve, and dynamic capillary force curve models are established. Multiple pressure-driven oil-increasing mechanisms such as time-varying geostress, time-varying porosity and permeability, time-varying phase permeability, and imbibition replacement are coupled and characterized to improve the pressure-driven simulation accuracy, provide a theoretical basis and numerical simulation method for the pressure-driven technology of low-permeability oil reservoirs, and are of great significance to the selection of wells for pressure-driven wells in low-permeability oil layers and the optimization design of pressure-driven parameters.

[0089] Embodiment 2

[0090] The embodiment of the present invention takes the successful pressure drive test of a well in block A of an existing target low-permeability oil reservoir, and the need to establish an oil reservoir numerical simulation model as an example to illustrate the application process of the method provided by the embodiment of the present invention.

[0091] Figure 2 FIG. 1 is a flow chart of another numerical simulation characterization method based on the pressure-driven oil-increasing mechanism of a low-permeability oil field provided in accordance with an embodiment of the present invention. Figure 2 As shown, the specific steps include:

[0092] Step 1: Establish a fluid pressure-in-situ stress-physical property coupling equation group based on the total stress tensor; use Young's modulus and Poisson's ratio to define the elastic characteristics of the rock, and calculate the time-varying porosity field based on the time-varying in-situ stress field; use 4 cores to conduct pressure-driven experiments, and obtain the relationship between the permeability retention coefficient and stress as shown in Figure 3 As shown in the figure, the time-varying permeability field is calculated according to the time-varying geostress field; the Mohr-Coulomb strength criterion, Griffiths criterion, expansion criterion, etc. are introduced to calculate the dynamic extension length and orientation of the pressure-driven cracks in the pressure-driven process according to the time-varying geostress field, Young's modulus, Poisson's ratio, etc. The crack calculation flow chart is shown in the figure. Figure 4 shown.

[0093] Step 2: Conduct a long-term fracture conductivity test experiment. The experimental results show that the conductivity decreases rapidly in the early stage of fracture closure and slowly in the later stage. The overall change conforms to the exponential law. Normalize the experimental results and establish a fracture conductivity attenuation function according to the exponential decreasing law. The function curve is as follows: Figure 5 shown.

[0094] Step 3: Perform a non-steady-state relative permeability curve test under water flooding / surfactant flooding conditions to obtain a relative permeability curve under water flooding / surfactant flooding conditions as shown in Figure 6 As shown in the figure, a dynamic phase permeability curve with surfactant concentration as the independent variable was established; mercury injection test was carried out, and the injection / flowback capillary force data were obtained as shown in the figure. Figure 7 As shown, the relationship curve between surfactant concentration and interfacial tension obtained by interfacial tension test is used to establish a dynamic capillary force curve that takes into account both surfactant oil enhancement and imbibition displacement oil enhancement.

[0095] Step 4: Based on the existing static geological and fluid data of the mine, combined with the time-varying geostress field, time-varying porosity field, time-varying permeability field, dynamic expansion of pressure-driven fractures, attenuation of fracture conductivity, dynamic phase permeability curve, and dynamic capillary force curve, a pressure-driven fine reservoir numerical simulation model is established.

[0096] Perform history matching such as Figure 8 As shown in the figure, the conventional numerical model fitting results (such as Fig. 9 As shown in the figure). The comparison shows that conventional numerical models have more human intervention in parameter adjustment and the fitting is not accurate. The reservoir numerical simulation model formed by the present invention introduces the experimental results of porosity and permeability time variation, couples the time variation of ground stress, sets the fracturing pressure drive fluid volume according to the actual construction parameters, automatically simulates and generates the fracture network, improves the fitting production; increases the fracture conductivity attenuation function, improves the fitting bottom hole flow pressure; and greatly reduces human intervention in parameter adjustment. The historical fitting results are more accurate, which verifies the accuracy of the fine numerical model coupling multiple pressure drive mechanisms.

[0097] Based on the constructed numerical model, the capacity contribution analysis of the oil increase mechanism was carried out. The specific simulation scheme design is shown in Table 1, and the numerical simulation results are shown in Table 2.

[0098] Table 1 Simulation scheme design

[0099]

[0100] Table 2 Numerical simulation characterization of oil increase mechanism

[0101]

[0102]

[0103] Embodiment 3

[0104] Fig.10 Schematic diagram of a numerical simulation characterization system based on the pressure-driven oil-increasing mechanism of a low-permeability oil field provided according to an embodiment of the present invention, the system is applied to a target low-permeability oil field. Fig.10 As shown, the system includes: a first establishment module 10 , a calculation module 20 , a second establishment module 30 , a third establishment module 40 , a fourth establishment module 50 and a simulation characterization module 60 .

[0105] Specifically, the first establishing module 10 is used to establish a fluid pressure-geo-stress-physical property coupling equation group based on the total stress tensor of the target low-permeability oil field.

[0106] The calculation module 20 is used to calculate the time-varying porosity field, the time-varying permeability field and the dynamic expansion parameters of the pressure-driven fracture of the target low-permeability oil field based on the fluid pressure-ground stress-physical property coupling equation group.

[0107] The second establishing module 30 is used to establish a fracture conductivity attenuation function of a target low-permeability oil field based on the fracture long-term conductivity test experimental data.

[0108] The third establishing module 40 is used to establish a dynamic relative permeability curve control function and a dynamic capillary force curve control function of the target low permeability oil field based on the non-steady-state relative permeability curve test experimental data and the mercury injection experimental data.

[0109] The fourth establishment module 50 is used to establish a numerical simulation model of the target low-permeability oil field based on the fluid pressure-geo-stress-physical property coupling equation group, the time-varying porosity field, the time-varying permeability field, the pressure-driven fracture dynamic expansion parameter, the fracture conductivity attenuation function, the dynamic phase permeability curve control function and the dynamic capillary force curve control function.

[0110] The simulation characterization module 60 is used to perform numerical simulation characterization on the oil increase mechanism during the pressure drive process of the target low-permeability oil field based on the numerical simulation model.

[0111] Specifically, the third establishing module 40 is further used for:

[0112] Based on the experimental data of relative permeability curve test using non-steady-state method, water drive relative permeability curve, pressure drive relative permeability curve and surfactant drive relative permeability curve are obtained;

[0113] Based on the water drive relative permeability curve, pressure drive relative permeability curve and surfactant drive relative permeability curve, a dynamic relative permeability curve control function with pressure and surfactant concentration as independent variables is established;

[0114] Based on the mercury injection test data, the data of the imbibition capillary force, the data of the displacement capillary force and the relationship between the surfactant concentration and the oil-water interfacial tension were obtained;

[0115] Based on the data of imbibition capillary force, displacement capillary force and the relationship between surfactant concentration and oil-water interfacial tension, a dynamic capillary force curve control function with wetting sequence and surfactant concentration as independent variables was established.

[0116] The present invention further provides an electronic device, comprising: a memory, a processor, and a computer program stored in the memory and executable on the processor, wherein the processor implements the method provided in the embodiment of the present invention when executing the computer program.

[0117] The present invention also provides a computer-readable storage medium, which stores computer instructions. When the computer instructions are executed by a processor, the method provided in the embodiment of the present invention is implemented.

[0118] It will be apparent to those skilled in the art that the invention is not limited to the details of the exemplary embodiments described above and that the invention can be implemented in other specific forms without departing from the spirit or essential features of the invention. Therefore, the embodiments should be considered exemplary and non-limiting in all respects, and the scope of the invention is defined by the appended claims rather than the foregoing description, and it is intended that all variations falling within the meaning and scope of the equivalent elements of the claims be included in the invention. Any reference numeral in a claim should not be considered as limiting the claim to which it relates.

[0119] In addition, it should be understood that although the present specification is described according to implementation modes, not every implementation mode contains only one independent technical solution. This description of the specification is only for the sake of clarity. Those skilled in the art should regard the specification as a whole. The technical solutions in each embodiment may also be appropriately combined to form other implementation modes that can be understood by those skilled in the art.

Claims

1. A numerical simulation characterization method based on the mechanism of pressure-driven oil production in low-permeability oil fields, characterized in that: Applied to a target low-permeability oil field; the method comprises: Based on the total stress tensor of the target low-permeability oil field, a fluid pressure-ground stress-physical property coupling equation group is established; Based on the fluid pressure-in-situ stress-physical property coupling equation group, the time-varying porosity field, the time-varying permeability field and the dynamic expansion parameters of the pressure-driven fracture of the target low-permeability oil field are calculated; Based on the long-term fracture conductivity test experimental data, a fracture conductivity attenuation function of the target low-permeability oil field is established; Based on the non-steady-state relative permeability curve test experimental data and the mercury injection test data, a dynamic relative permeability curve control function and a dynamic capillary force curve control function of the target low-permeability oil field are established respectively; A numerical simulation model of the target low-permeability oil field is established based on the fluid pressure-in-situ stress-physical property coupling equation group, the time-varying porosity field, the time-varying permeability field, the pressure-driven fracture dynamic expansion parameter, the fracture conductivity attenuation function, the dynamic phase permeability curve control function and the dynamic capillary force curve control function; Based on the numerical simulation model, a numerical simulation characterization is performed on the oil increase mechanism during the pressure drive process of the target low-permeability oil field.

2. The method according to claim 1, characterized in that: The fluid pressure-geo-stress-physical property coupling equation group includes: Where N c is the molar density of component c, S P is the P phase saturation, x c,P is the mole fraction of the c component P phase, ξ P is the molar density of phase P, is the stratum displacement vector, ρ r is the rock density at reference pressure, α is the Biot constant, is the total initial stress tensor in the formation, is the initial strain tensor, p0 is the initial pore pressure, λ and μ are functions of Young's modulus and Poisson's ratio, t is time, φ is the time-varying porosity field, O, W, G represent the oil phase, water phase and gas phase respectively, U P represents the seepage velocity vector, q c represents the inflow velocity of the P phase of the c component, p represents the pore pressure, σ ij is the total formation stress tensor, ∈ ij is the total strain tensor, δ ij is the Kronecker symbol.

3. The method according to claim 1, characterized in that: Based on the fluid pressure-geo-stress-physical property coupling equation group, the time-varying porosity field, the time-varying permeability field and the dynamic expansion parameters of the pressure-driven fracture of the target low-permeability oil field are calculated, including: The calculation formula of the time-varying porosity field includes: Where φ is the time-varying porosity field; Based on the relationship between the permeability retention coefficient and stress obtained from the core pressure drive experiment and the fluid pressure-geo-stress-physical property coupling equation group, the time-varying permeability field is calculated; wherein the relationship between the permeability retention coefficient and stress includes: Wherein, K is permeability, K0 is the initial permeability of the reservoir of the target low-permeability oil field, σ is effective stress, and A and B are adjustment variables for fitting the core pressure drive experiment; Based on the Mohr-Coulomb strength criterion and the fluid pressure-in-situ stress-physical property coupling equation group, the dynamic expansion parameters of the pressure-driven fractures in the pressure-driven process of the target low-permeability oil field are calculated.

4. The method according to claim 1, characterized in that: The fracture conductivity attenuation function includes: Where F is the fracture conductivity, F0 is the initial fracture conductivity, C is the tuning parameter for fitting the fracture conductivity attenuation experiment, and t is time.

5. The method according to claim 1, characterized in that: Based on the non-steady-state relative permeability curve test experimental data and mercury injection experimental data, a dynamic relative permeability curve control function and a dynamic capillary force curve control function of the target low permeability oil field are established respectively, including: Based on the relative permeability curve test experimental data of the non-steady-state method, a water drive relative permeability curve, a pressure drive relative permeability curve and a surfactant drive relative permeability curve are obtained; Based on the water drive relative permeability curve, the pressure drive relative permeability curve and the surfactant drive relative permeability curve, a dynamic relative permeability curve control function with pressure and surfactant concentration as independent variables is established; Based on the mercury injection test data, the data of the imbibition capillary force, the data of the displacement capillary force and the relationship between the surfactant concentration and the oil-water interfacial tension are obtained; Based on the imbibition capillary force data, the displacement capillary force data and the relationship between surfactant concentration and oil-water interfacial tension, a dynamic capillary force curve control function with wetting sequence and surfactant concentration as independent variables is established.

6. The method according to claim 1 or 5, characterized in that: The dynamic phase permeability curve control function includes: In the formula, p is pressure, C is surfactant concentration, K ri is the relative permeability of phase i, P surf+p is the pressure of the relative permeability curve of surfactant pressure drive, C surf is the surfactant concentration of the relative permeability of surfactant flooding, is the water flooding relative permeability curve, is the relative permeability curve of surfactant flooding, This is the relative permeability curve of surfactant pressure drive.

7. The method according to claim 5, characterized in that: The dynamic capillary force curve control function includes a dynamic capillary force curve control function with surfactant concentration as an independent variable and a dynamic capillary force curve control function with wetting order as an independent variable; wherein, The dynamic capillary force curve control function with surfactant concentration as an independent variable includes: Where P cow is the oil-water capillary force, σ ow is the oil-water interfacial tension with surfactant concentration as the independent variable, σ Hg is the interfacial tension between mercury and air, θ ow is the oil-water contact angle, θ Hg is the contact angle between mercury and air, P Hg is the capillary force between mercury and air; The dynamic capillary force curve control function with the wetting order as an independent variable includes: p c =(1―f)p cD +fp cI In the formula, p c is the capillary force, p cD is the capillary force, p cI is the capillary force of infiltration, S w is water saturation, S wi is the initial water saturation, S w max is the maximum achievable water saturation, and E is the curve parameter.

8. A numerical simulation characterization system based on the mechanism of pressure-driven oil production in low-permeability oil fields, characterized in that: Applied to target low permeability oil fields; including: a first establishment module, a calculation module, a second establishment module, a third establishment module, a fourth establishment module and a simulation characterization module; wherein, The first establishing module is used to establish a fluid pressure-ground stress-physical property coupling equation group based on the total stress tensor of the target low-permeability oil field; The calculation module is used to calculate the time-varying porosity field, the time-varying permeability field and the dynamic expansion parameters of the pressure-driven fracture of the target low-permeability oil field based on the fluid pressure-in-situ stress-physical property coupling equation group; The second establishing module is used to establish a fracture conductivity attenuation function of the target low-permeability oil field based on the fracture long-term conductivity test experimental data; The third establishment module is used to establish a dynamic relative permeability curve control function and a dynamic capillary force curve control function of the target low-permeability oil field based on the non-steady-state relative permeability curve test experimental data and the mercury injection experimental data; The fourth establishment module is used to establish a numerical simulation model of the target low-permeability oil field based on the fluid pressure-in-situ stress-physical property coupling equation group, the time-varying porosity field, the time-varying permeability field, the pressure-driven fracture dynamic expansion parameter, the fracture conductivity attenuation function, the dynamic phase permeability curve control function and the dynamic capillary force curve control function; The simulation characterization module is used to perform numerical simulation characterization on the oil increase mechanism during the pressure drive process of the target low-permeability oil field based on the numerical simulation model.

9. An electronic device, characterized in that: include: A memory, a processor, and a computer program stored in the memory and executable on the processor, wherein the processor implements the method according to any one of claims 1 to 7 when executing the computer program.

10. A computer-readable storage medium, characterized in that: The computer-readable storage medium stores computer instructions, and when the computer instructions are executed by a processor, the method according to any one of claims 1 to 7 is implemented.

Images