Fracturing-exploration integrated equivalent numerical simulation method for tight oil and gas reservoirs

Abstract

The application provides a compact oil and gas reservoir fracturing-mining integrated equivalent numerical simulation method, which comprises the following steps: step 1, depicting the hydraulic fracturing fracture morphology of the compact oil and gas reservoir, and giving corresponding physical property parameters; step 2, establishing a fracturing fracture opening-expansion-proppant filling equivalent reaction model to simulate the dynamic formation process of the fracturing fracture; step 3, carrying out wellbore pipe flow-reservoir seepage-fracturing reaction coupling calculation to realize the fracturing-mining integrated equivalent simulation. The compact oil and gas reservoir fracturing-mining integrated equivalent numerical simulation method can design and optimize injection-production parameters as a whole in the fracturing and mining process, and provides a new research tool for the design and optimization of the compact oil and gas reservoir fracturing-mining integrated scheme.

Description

TECHNICAL FIELD

[0001] The present application relates to the technical field of compact oil and gas reservoir development, in particular to a compact oil and gas reservoir fracturing-mining integrated equivalent numerical simulation method. BACKGROUND

[0002] Due to the characteristics of compact oil and gas reservoirs such as complex lithology, strong water sensitivity and reservoir damage, there are often problems such as unsatisfactory fracture network formation, strong pressure sensitivity of fracture conductivity, difficulty in formation energy supplement and rapid production decline in the process of fracturing and mining, which requires comprehensive design and optimization of the fracturing and development process as a whole. Since the fracturing and development process involves wellbore pipe flow, formation seepage and rock mechanics, etc., it involves thermal-flow-solidification-force multi-field coupling calculation, but there is no good fracturing-development integrated numerical simulation method at present.

[0003] At present, there are many numerical simulation methods, models or software for wellbore pipe flow, hydraulic fracturing and reservoir seepage, but most of them are considered separately, or although coupled, one of the functions is weak. Commonly used wellbore multiphase flow calculation software includes Pipesim and OLGA, commonly used reservoir numerical simulation software includes Eclipse, CMG and VIP, and commonly used hydraulic fracturing simulation software includes FracMan, COMSOL, ABAQUS, etc. Among them, the numerical simulation methods of hydraulic fracturing mainly include boundary element method, unconventional fracture model, discretized fracture network model and extended finite element method, etc. The boundary element method is a numerical simulation method developed under the influence of finite difference and finite element. This method is based on the basic solution of the control differential equation to establish the boundary integral equation to express the problem, which is discretized by interpolating the boundary element, and is solved as an algebraic equation system. The unconventional fracture model is established based on the pseudo-three-dimensional model, considering the stress field of the reservoir and the stress interference between adjacent fractures. The control equation of this model includes the settling equation of proppant, G-W fracture extension criterion and fracture deformation equation. This model can calculate parameters such as fracture width. The discretized fracture network model is a relatively mature model for simulating complex fracture network of hydraulic fracturing. This model assumes that the fracture network is a pseudo-elliptical sphere, the main fracture is perpendicular to the minimum horizontal principal stress σh, and the secondary fracture intersects the main fracture to form an orthogonal fracture network. The extended finite element method is a method developed on the basis of the classical finite element method by increasing the generalized node freedom and improving the interpolation function. It is the most accurate method for solving discontinuity problems and is widely used at home and abroad. However, none of the above methods couples the reservoir seepage model or the coupled reservoir seepage model has weak function in characterizing the stimulation mechanism. For example, CO2 can not only help to produce a large number of induced fractures to form a fracture network with larger coverage area and more complex morphology, but also can play the stimulation mechanism of swelling and viscosity reduction, and gas dissolution, etc. Therefore, the fracturing-development integrated model needs to have more powerful functions.

[0004] In the Chinese patent application No. CN202010926532.3, it relates to the field of CO2 flooding numerical simulation for improving recovery in low permeability reservoirs, and particularly relates to a method for simulating CO2 flooding in fractured reservoirs. The method comprises the following steps: determining the position of artificial large fractures and micro-fracture regions generated by fracturing, and establishing a geometric model of the fractured reservoir; establishing a mixed model to represent fractures of different scales, performing grid division, and forming a grid system; establishing a component model to describe the CO2 flooding process, considering the components therein, describing the phase change and the miscibility mechanism of CO2 and crude oil; developing a solution scheme to solve the complex component model of the fractured reservoir, and making the simulation process stable. The method can accurately describe both artificial large fractures and small fractures generated during fracturing or gas injection while simulating the CO2 flooding process, overcoming the difficulties faced by the existing CO2 flooding methods in fractured reservoirs.

[0005] In the Chinese patent application No. CN201910055675.9, it relates to a method and device for simulating productivity of fractured-fissured reservoirs. The method comprises: establishing multiple embedded discrete fracture numerical simulation models according to multiple sets of initial characteristic values of fracture parameters, reservoir structural characteristic parameters, reservoir attribute characteristic parameters, and numerical discrete solution format parameters; obtaining multiple sets of productivity parameter simulation values of the reservoir according to the multiple embedded discrete fracture numerical simulation models; updating the multiple sets of initial characteristic values of the fracture parameters according to the multiple sets of productivity parameter simulation values of the reservoir to obtain multiple sets of updated characteristic values of the fracture parameters; taking the multiple sets of updated characteristic values of the fracture parameters as the multiple sets of initial characteristic values of the fracture parameters, and re-executing the above steps until the number of re-executions reaches a preset iteration number, and outputting the latest multiple sets of productivity parameter simulation values of the reservoir. The invention can simulate the productivity of fractured-fissured reservoirs with small calculation amount and high precision.

[0006] In the Chinese patent application No. CN202110439529.3, it relates to a method for simulating repeated fracturing of horizontal wells in tight conglomerate reservoirs. The method comprises the following steps: establishing a geological model according to reservoir data; obtaining an initial fracture network model through UFM fracture expansion simulation and correcting to obtain a final fracturing simulation fracture network morphology; establishing an unstructured grid numerical simulation model and correcting through production dynamic simulation; optimizing the water injection scheme through water injection energy simulation and optimizing the soaking time based on the optimized water injection scheme through four-dimensional geological modeling; establishing a fracture network model after repeated fracturing; and establishing a numerical simulation model after repeated fracturing and performing repeated fracturing production dynamic simulation. The invention makes the fracture expansion more consistent with the conglomerate reservoir by assuming the existence of multiple groups of micro-scale natural fractures equivalent to conglomerate; through four-dimensional geostress modeling, a geostress model at different time points is established, and according to the geostress recovery, a basis is provided for determining the water injection scheme and soaking time after water injection in the conglomerate reservoir, i.e., when to carry out repeated fracturing work.

[0007] The above prior art is quite different from the present application, and cannot solve the technical problems we want to solve. Therefore, we have invented a new compact oil and gas reservoir fracturing-mining integrated equivalent numerical simulation method. SUMMARY

[0008] The purpose of the present application is to provide a compact oil and gas reservoir fracturing-mining integrated equivalent numerical simulation method, which can provide a new research tool for compact oil and gas reservoir fracturing-mining integrated scheme design and optimization, thereby realizing efficient and stable development of compact oil and gas reservoirs.

[0009] The purpose of the present application can be achieved by the following technical measures: a compact oil and gas reservoir fracturing-mining integrated equivalent numerical simulation method, comprising:

[0010] Step 1, depicting the shape of the hydraulic fracture of the compact oil and gas reservoir, and assigning the corresponding physical property parameters;

[0011] Step 2, establishing a fracturing fracture opening-expansion-proppant filling equivalent reaction model to simulate the dynamic formation process of the fracturing fracture;

[0012] Step 3, performing wellbore pipe flow-reservoir seepage-fracturing reaction coupling calculation to realize fracturing-mining integrated equivalent simulation.

[0013] The purpose of the present application can also be achieved by the following technical measures:

[0014] Step 1 includes:

[0015] S11, depicting the distribution and trend of the main fracture and branch fracture;

[0016] S12, according to the results of formation breakdown pressure, matrix permeability and fracture conductivity laboratory test, obtaining the data of porosity, permeability, compressibility and porosity-permeability relationship table of different medium regions of matrix, main fracture and branch fracture;

[0017] S13, assigning the physical property parameters of different medium regions to the geological model, so that different medium regions in the geological model have different pressure sensitivities, and the effect of fracture cracking when the pore pressure reaches the formation breakdown pressure can be achieved.

[0018] In step 11, based on microseismic data or fracturing interpretation results, the fracture morphology is identified, and the distribution and trend of the main fracture and branch fracture are depicted by using geological modeling software and encrypted grid.

[0019] Step 2 includes:

[0020] S21, pressurizing the formation before injection;

[0021] S22, injecting sand-carrying fluid to fill the support cracks into the cracks;

[0022] S23, injecting displacement fluid to displace the proppant into the deep cracks;

[0023] S24, after the fracturing fluid is discharged, the formation forms a high conductivity crack.

[0024] In step 21, for the preflush injection stage, the rock compressibility coefficient is used to simulate the increase of porosity caused by the increase of injection pressure; the relationship between permeability and porosity is used to simulate the increase of permeability caused by the increase of porosity, and for the fracture area, the corresponding permeability of the porosity is set to suddenly increase when the formation pressure reaches above the fracture pressure, to simulate the opening of the crack.

[0025] In step 22, for the sand-carrying fluid injection stage, the proppant in the sand-carrying fluid is defined as a water phase component P(w), a certain concentration of solid phase component R(S) is set in the grid of the crack to be opened, and a solid phase component P(S) is defined. When the formation pressure exceeds the fracture pressure, the three components contact and the following reaction occurs:

[0026] P(w)+R(S)+H2O→P(S)+nH2O

[0027] Wherein, the density of P(S) is large enough, so that the volume of P(S) after the reaction is significantly smaller than R(S), or P(S) is directly ignored, thereby increasing the porosity, to simulate the filling process of the proppant in the crack, and to ensure that the crack still has a larger porosity and higher conductivity after the fracturing is completed; In addition, further local equilibrium reaction setting is adopted to realize that the above reaction only occurs when the formation pore pressure exceeds the fracture pressure.

[0028] In step 23, for the displacement fluid injection stage, it is similar to the sand-carrying fluid injection stage, but without proppant, no reaction occurs.

[0029] In step 24, for the fracturing fluid discharge stage, the fracturing fluid is discharged by pressure reduction, and the bottom hole flowing pressure is reduced.

[0030] In step 24, for the gel breaking process of the fracturing fluid, component W nj is defined as a high viscosity component in the fracturing fluid, and water and gel breaking product W pj are generated. The specific reaction is as follows:

[0031] W nj →mH2O+W pj .

[0032] Step 3 includes:

[0033] S31, based on pipe flow theory, establish a fracturing wellbore multiphase flow transient model;

[0034] S32, by means of the flexible well model in the numerical simulation method of the oil reservoir, realizing transient simulation of the multi-phase flow of the fractured wellbore;

[0035] S33, coupling the flexible well model with the oil reservoir percolation model, realizing integrated simulation of the wellbore pipe flow and the formation percolation;

[0036] S34, further coupling the fracture opening-expansion-supporting agent filling reaction model, realizing integrated simulation of fracturing and production.

[0037] The purpose of the present application can also be achieved by the following technical measures: the dense oil and gas reservoir fracturing-production integrated equivalent numerical simulation system adopts the dense oil and gas reservoir fracturing-production integrated equivalent numerical simulation method to design and optimize injection-production parameters as a whole for the fracturing and production processes.

[0038] The dense oil and gas reservoir fracturing-production integrated equivalent numerical simulation method in the present application relates to hydraulic fracturing and development numerical simulation, and can realize simulation of the whole process of injection of fracturing fluid along the wellbore, opening-expansion of the fracture, filling of the supporting agent and production by blowout on the basis of coupled calculation of the wellbore pipe flow and the formation percolation. By means of the method, the fracturing and production processes can be designed and optimized as a whole, thereby providing a new research tool for design and optimization of the dense oil and gas reservoir fracturing-production integrated scheme. BRIEF DESCRIPTION OF DRAWINGS

[0039] Figure 1 It is a schematic diagram of fracture parameter setting of the geological model in a specific embodiment of the present application;

[0040] Figure 2 It is a schematic diagram of change of the formation fracture permeability, i.e., the conductivity, in the fracturing-flowback process in a specific embodiment of the present application;

[0041] Figure 3 It is a flowchart of a specific embodiment of the dense oil and gas reservoir fracturing-production integrated equivalent numerical simulation method of the present application;

[0042] Figure 4 It is a schematic diagram of phase state change of CO2 in the fracturing-flowback process in a specific embodiment of the present application;

[0043] Figure 5 It is a schematic diagram of phase state change of CO2 at different CO2 injection temperatures in the fracturing-flowback process in a specific embodiment of the present application;

[0044] Figure 6 It is a schematic diagram of phase state change of CO2 at different CO2 injection amounts in the fracturing-flowback process in a specific embodiment of the present application. Detailed Implementation

[0045] It should be noted that the following detailed descriptions are exemplary and intended to provide further illustration of the invention. Unless otherwise specified, all technical and scientific terms used herein have the same meaning as commonly understood by one of ordinary skill in the art to which this invention pertains.

[0046] It should be noted that the terminology used herein is for the purpose of describing particular embodiments only and is not intended to limit the exemplary embodiments of the present invention. As used herein, the singular form is intended to include the plural form as well, unless the context clearly indicates otherwise. Furthermore, it should be understood that when the terms "comprising" and / or "including" are used in this specification, they indicate the presence of features, steps, operations, and / or combinations thereof.

[0047] like Figure 3 As shown, Figure 3 This is a flowchart of the integrated fracturing-production equivalent numerical simulation method for tight oil and gas reservoirs according to the present invention. The integrated fracturing-production equivalent numerical simulation method for tight oil and gas reservoirs includes:

[0048] S1. Use geological modeling software to characterize the morphology of hydraulic fracturing fractures in tight oil and gas reservoirs and assign corresponding physical property parameters;

[0049] S2. Establish an equivalent reaction model of hydraulic fracturing fracture initiation-propagation-propulsion filling to simulate the dynamic formation process of hydraulic fracturing fractures;

[0050] S3. Perform coupled calculations of wellbore flow, reservoir seepage, and fracturing reaction to achieve an integrated equivalent simulation of fracturing and production.

[0051] Preferably, in step S1, the steps of characterizing the morphology of hydraulic fracturing fractures in tight oil and gas reservoirs using geological modeling software and assigning corresponding physical property parameters are as follows:

[0052] S11. Based on microseismic data or fracturing interpretation results, identify fracture morphology and use geological modeling software and a denser mesh to depict the distribution and orientation of main fractures and branch fractures.

[0053] S12. Based on the indoor test results of formation fracture pressure, matrix permeability and fracture conductivity, obtain data such as porosity, permeability, compressibility coefficient and porosity-permeability relationship table for different media regions such as matrix, main fracture and branch fracture.

[0054] S13. Assigning physical property parameters of different medium regions to the geological model, so that different medium regions in the geological model have different pressure sensitivity, can achieve the effect of cracking after the pore pressure reaches the formation fracture pressure.

[0055] Preferably, in step S2, the equivalent reaction model of fracturing fracture opening-expansion-proppant filling is established to simulate the dynamic formation process of the fracturing fracture as follows:

[0056] S21, the simulated hydraulic fracturing process mainly includes the following steps: (1) injecting preflush to open the formation; (2) injecting sand-carrying fluid to fill proppant into the fracture; (3) injecting displacement fluid to displace proppant to the deep part of the fracture; (4) after the fracturing fluid is flowed back, the formation forms a high-conductivity fracture.

[0057] S22, for the preflush injection stage: use the rock compression coefficient to simulate the increase of porosity caused by the increase of injection pressure; use the permeability-porosity relationship table to simulate the increase of permeability caused by the increase of porosity, and for the fracture area, set the corresponding permeability of the porosity when the formation pressure reaches above the breakdown pressure to suddenly increase to simulate the opening of the fracture.

[0058] S23, for the sand-carrying fluid injection stage: define the proppant in the sand-carrying fluid as a water phase component P(w), set a certain concentration of solid phase component R(S) in the grid of the fracture to be opened, and then define a solid phase component P(S), when the formation pressure reaches above the breakdown pressure, the three components contact to occur the following reaction:

[0059] P(w)+R(S)+H2O→P(S)+nH2O

[0060] Wherein, the density of P(S) is large enough to make the volume of P(S) significantly smaller than R(S) after the reaction, or P(S) is directly ignored, thereby producing the effect of increasing porosity, to simulate the filling process of proppant in the fracture, and to ensure that the fracture still has a larger porosity and higher conductivity after the fracturing is completed. In addition, further local equilibrium reaction setting is adopted to realize that the above reaction only occurs when the formation pore pressure exceeds the breakdown pressure.

[0061] S24, for the displacement fluid injection stage: similar to the sand-carrying fluid, but without proppant, no reaction occurs.

[0062] S25, for the fracturing fluid flow-back stage: the fracturing fluid is flowed back under reduced pressure, and the bottom-hole flowing pressure is reduced. For the gel breaking process of the fracturing fluid, define component W nj as a high-viscosity component in the fracturing fluid, and water and gel breaking product W pj are generated, and the specific reaction is as follows:

[0063] W nj →mH2O+W pj

[0064] Preferably, in step S3, the steps of wellbore pipe flow-reservoir seepage-fracturing reaction coupling calculation are as follows to realize the integrated equivalent simulation of fracturing-production.

[0065] S31, based on pipe flow theory, a fracturing wellbore multiphase flow transient model is established.

[0066] S32, by means of a flexible well model in the numerical simulation method of the oil reservoir, the fracturing wellbore multiphase flow transient simulation is realized.

[0067] S33, the flexible well model is coupled with the oil reservoir seepage model, and the wellbore pipe flow and the formation seepage integrated simulation is realized.

[0068] S34, further coupling the fracture opening-expansion-support agent filling reaction model, the fracturing-mining integrated simulation is realized;

[0069] The following are several specific embodiments of the application

[0070] Example 1

[0071] In a specific embodiment 1 of the application, a straight well CO2 energy-increasing numerical simulation model is established with reference to the hydraulic fracturing working condition of the production well of the dense oil reservoir of Block Yan 222 of Shengli Oilfield. The basic parameter settings of the model are shown in Table 1. The geological model is composed of two parts. The near wellbore formation attached to the flexible well from the ground to 3900m underground is 10x10x100m in grid size, and the number of grids is 3x3x39=351, and the porosity and permeability are both 0. The target reservoir from 3900m to 3950m underground is 50m in layer thickness, 8% in porosity, 1.6md in permeability, 150℃ in temperature, 38.71MPa in pressure, 10x10x10m in grid size, and 51x29x5=7395 in the number of reservoir grids. Figure 1 a) Under the typical fracturing condition, the CO2 injection temperature is-20℃, the bottom hole temperature is 15℃, the total CO2 injection amount is 200t, the injection speed is 2t / min, the total fracturing fluid injection amount is 900m 3 , the injection speed is 10m 3 / min, the well is closed for 12h, the blowout speed is 3m 3 / h, and the blowout lasts for 30 days. It is expected to form a main fracture half length of 150m, a branch fracture half width of 45m, and a fracture height of 30m. The grid is densified to 5x5x1 at the fracture, the main fracture conductivity is 983x0.6md.m, and the branch fracture conductivity is 250x0.6md.m Figure 1 b); at the same time, through indoor experiment, the matrix, main fracture and branch fracture pressure-sensitive porosity-permeability relationship of the target reservoir is determined, as shown in Figure 1 c.

[0072] Table 1 Basic parameter table of CO2 energy-increasing fracturing numerical simulation model

[0073]

[0074] The permeability variation of fractures in different stages of fracturing and flowback is predicted as shown in Figure 2 As shown in the figure, after CO2 is injected into the ground, due to the low viscosity of CO2, induced fractures are mainly generated along the main fracture direction, and micro-fractures are generated along the branch fracture direction. After subsequent injection of sand-carrying fracturing fluid, the permeability of the main fracture and the branch fracture near the well bottom is significantly improved due to the high viscosity of the fracturing fluid. During the shut-in period, due to the energy-increasing effect of CO2, the fractures have the tendency of further expansion and increased permeability. After the well is opened, the fracture conductivity is well maintained as the bottom hole flow pressure decreases.

[0075] The temperature, pressure and phase state changes of CO2 in the wellbore and fractures during the fracturing process are shown in Figure 4 The key node positions marked in the figure are: 1-5, wellhead, 1000m, 2000m, 3000m, and well bottom at the end of CO2 injection; 6-7, free CO2 wave front and oil phase CO2 wave front in the fractures at the end of CO2 injection; 8-9, free CO2 wave front and oil phase CO2 wave front in the fractures at the end of fracturing fluid injection; 10-11, free CO2 wave front and oil phase CO2 wave front in the fractures at the end of soak; 12-16, well bottom, 3000m, 2000m, 1000m, and wellhead at the initial appearance of CO2 during flowback. The phase state curve of CO2, the partition, and the phase state curve of CO2 hydrate are marked in the figure.

[0076] The simulation results show that at the end of CO2 injection, the temperature of the wellbore gradually increases downward from -20°C at the wellhead to 15.82°C at the bottom of the well, and the pressure increases from 17.05 MPa to 51.12 MPa, and the CO2 in the whole wellbore is in liquid state; a low-temperature zone with a radius of about 10 m is formed near the bottom of the well, and the CO2 sweep radius is about 50 m, and the CO2 changes from liquid state to supercritical state from the bottom of the well to the deep fracture. When the fracturing fluid injection is completed, the temperature of the reservoir further decreases along the fracture direction, the radius of the low-temperature zone expands to 20 m, the temperature is 20-30°C, and the distribution range of CO2 is further expanded. During the shut-in period, the temperature of the near-well formation recovers to some extent, but the pressure sweep range and the CO2 distribution range are further expanded. At the end of the shut-in period, the temperature of the near-well formation recovers to 40-60°C, and the CO2 sweep radius expands to 110 m. When CO2 is seen during the blowout, the bottom hole temperature recovers to 34.68°C, the near-well formation temperature recovers to about 90°C, and the CO2 distribution range decreases. CO2 mainly exists in the form of dissolved state and supercritical state in the formation, and the distribution range in the oil phase is greater than that in the supercritical state, the temperature and pressure of the CO2 sweep front are similar to the original formation conditions, and are not much affected by the injection temperature. During the flowback, the temperature of the wellbore increases first and then decreases from the bottom to the wellhead, and CO2 changes from supercritical state to gaseous state. Through analysis, the temperature and pressure of the wellbore during CO2 injection meet the hydrate formation conditions, and the hydrate risk needs to be prevented, while the temperature is relatively high and the pressure is relatively low in the formation and the flowback wellbore, and the hydrate risk is small.

[0077] Example 2

[0078] In the specific embodiment 2 of the application, based on example 1, the effect of CO2 injection temperature on the fracturing-flowback effect is analyzed by changing the CO2 injection temperature, and the changes of CO2 temperature, pressure and phase state in the wellbore and formation during fracturing under different CO2 injection temperatures are shown in FIG. 2. Figure 5 As shown in the figure, the smaller the CO2 injection temperature, the lower the bottom hole temperature at the end of CO2 injection (42.84→15.82°C), but the CO2 in the wellbore is generally in liquid state, and only when the injection temperature is 20°C, the CO2 in the wellbore will change phase, i.e. from liquid state to supercritical state; the CO2 injection temperature has little effect on the reservoir pressure and CO2 distribution, and CO2 is in supercritical state in the formation; during blowout production, the lower the CO2 injection temperature, the smaller the bottom hole temperature (58.76→34.68°C), but it has little effect on the temperature and pressure conditions of the wellbore above 3000 m and the process of CO2 changing from supercritical state to gaseous state in the 1000 m well section. In addition, the higher the CO2 injection temperature, the lower the hydrate risk in the wellbore, and when the injection temperature is 20°C, there is no hydrate risk in the wellbore.

[0079] Example 3

[0080] In the specific embodiment 3 of the application, based on the embodiment 1, the total amount of CO2 injection is changed to analyze the influence of the total amount of CO2 injection on the fracturing-flowback effect. The CO2 temperature, pressure and phase state changes in the wellbore and formation during fracturing under different total amounts of CO2 injection are shown in the table. Figure 6 As shown in the table, the greater the total amount of CO2 injection, the lower the bottom hole temperature at the end of CO2 injection (24.09→12.85℃), and the greater the distribution range in the formation. The CO2 remains in liquid state in the wellbore and turns into supercritical state after entering the formation. When the blowout production is carried out, the greater the total amount of CO2 injection, the smaller the bottom hole temperature recovery (44.3→31.73℃), but the influence on the phase change of CO2 in the wellbore is small. In addition, the smaller the total amount of CO2 injection, the smaller the hydrate risk in the wellbore.

[0081] Finally, it should be noted that the above description is only the preferred embodiments of the application and is not intended to limit the application. Although the application has been described in detail with reference to the foregoing embodiments, those skilled in the art can still modify the technical solutions recorded in the foregoing embodiments or make equivalent replacements to some technical features. Any modification, equivalent replacement, improvement, etc. within the spirit and principles of the application shall be included in the protection scope of the application.

[0082] In addition to the technical features described in the specification, they are known to those skilled in the art.

Claims

1. A compact oil and gas reservoir fracturing-exploration integrated equivalent numerical simulation method, characterized in that, The compact oil and gas reservoir fracturing-mining integrated equivalent numerical simulation method comprises: Step 1, depicting the hydraulic fracture morphology of the compact oil and gas reservoir, and assigning corresponding physical property parameters; Step 2, establishing a fracturing fracture opening-expansion-proppant filling equivalent reaction model to simulate the dynamic formation process of the fracturing fracture; Step 3, performing wellbore pipe flow-reservoir seepage-fracturing reaction coupling calculation to realize fracturing-mining integrated equivalent simulation; Step 2 comprises: S21, injecting preflush to open the formation; S22, injecting sand-carrying fluid to fill proppant into the fracture; S23, injecting displacement fluid to displace proppant to the deep part of the fracture; S24, after the fracturing fluid is flowed back, the formation forms a fracture with high conductivity; In step 22, for the sand-carrying fluid injection stage, the proppant in the sand-carrying fluid is defined as a water phase component P(w), a solid phase component R(S) is set in the grid of the fracture network to be opened, and a solid phase component P(S) is defined, when the formation pressure exceeds the fracturing pressure, the three components contact to generate the following reaction: P(w)+ R(S)+H2O→P(S)+nH2O Wherein, the density of P(S) is large enough, so that the volume of P(S) after the reaction is significantly smaller than R(S), or P(S) is directly ignored, thereby producing the effect of increased porosity, to simulate the proppant filling process in the fracture, and to ensure that the fracture still has a larger porosity and higher conductivity after the fracturing is completed; in addition, a local equilibrium reaction setting is further adopted to realize that the above reaction only occurs when the formation pore pressure exceeds the fracturing pressure; Step 3 comprises: S31, based on pipe flow theory, establishing a fracturing wellbore multiphase flow transient model; S32, using the flexible well model in the numerical simulation method of the reservoir, realizing transient simulation of fracturing wellbore multiphase flow; S33, coupling the flexible well model with the reservoir seepage model to realize integrated simulation of wellbore pipe flow and formation seepage; S34, further coupling the fracture opening-expansion-proppant filling reaction model to realize fracturing-mining integrated simulation.

2. The integrated fracturing-recovery equivalent numerical simulation method for tight oil and gas reservoirs according to claim 1, characterized in that, Step 1 comprises: S11, depicting the distribution and trend of the main fracture and branch fracture; S12, according to the results of formation fracturing pressure, matrix permeability and fracture conductivity test, obtaining the data of porosity, permeability, compressibility and porosity-permeability relationship of different medium regions of matrix, main fracture and branch fracture; S13, assigning the physical property parameters of different medium regions to the geological model, so that different medium regions in the geological model have different pressure sensitivities, which can achieve the effect of fracture opening when the pore pressure reaches the formation fracturing pressure.

3. The integrated fracturing-recovery equivalent numerical simulation method for tight oil and gas reservoirs according to claim 2, characterized in that, In step S11, based on microseismic data or fracturing interpretation results, the fracture morphology is identified, and the distribution and trend of the main fracture and branch fracture are depicted by using geological modeling software and encrypted grid.

4. The integrated fracturing-recovery equivalent numerical simulation method for tight oil and gas reservoirs according to claim 3, characterized in that, In step S21, for the preflush injection stage, the rock compressibility coefficient is used to simulate the increase in porosity caused by the increase in injection pressure; the permeability-porosity relationship table is used to simulate the increase in permeability caused by the increase in porosity; for the fracture area, the permeability corresponding to the porosity when the formation pressure exceeds the fracture pressure is set to be suddenly increased to simulate the opening of the fracture.

5. The integrated fracturing-production equivalent numerical simulation method for tight oil and gas reservoirs according to claim 1, characterized in that, In step S23, for the displacement fluid injection stage, it is similar to the sand-carrying fluid injection stage, but without proppant and without reaction.

6. The integrated fracturing-production equivalent numerical simulation method for tight oil and gas reservoirs according to claim 1, characterized in that, In step S24, for the fracturing fluid flowback stage, the fracturing fluid is flowed back under reduced pressure, and the bottom-hole flow pressure is reduced.

7. The integrated fracturing-recovery equivalent numerical simulation method for tight oil and gas reservoirs according to claim 6, characterized in that, At step S24, component W is defined for the gel breaking process of the fracturing fluid nj Water and gel breaking product W are generated as high viscosity components in the fracturing fluid pj The specific reaction is as follows: W nj → mH2O + W pj .

8. A compact oil and gas reservoir fracturing-exploration integrated equivalent numerical simulation system, characterized in that, The tight oil and gas reservoir fracturing-mining integrated equivalent numerical simulation system adopts the tight oil and gas reservoir fracturing-mining integrated equivalent numerical simulation method in any one of claims 1-7 to design and optimize injection-production parameters as a whole for the fracturing and mining processes.

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