Compact oil and gas reservoir fracturing-exploitation integrated equivalent numerical simulation method

Abstract

The invention provides a compact oil and gas reservoir fracturing-exploitation integrated equivalent numerical simulation method, which comprises the following steps of: 1, depicting a hydraulic fracturing fracture form of a compact oil and gas reservoir, and endowing corresponding physical property parameters; step 2, establishing a fracturing crack opening-expanding-propping agent filling equivalent reaction model to simulate a fracturing crack dynamic forming process; and 3, shaft pipe flow-oil reservoir seepage-fracturing reaction coupling calculation is conducted, and fracturing-exploitation integrated equivalent simulation is achieved. According to the compact oil and gas reservoir fracturing-exploitation integrated equivalent numerical simulation method, the fracturing and exploitation processes can be used as a whole for injection-exploitation parameter design and optimization, and a new research tool is provided for design and optimization of a compact oil and gas reservoir fracturing-exploitation integrated scheme.

Description

Technical Field

[0001] The present invention relates to the technical field of tight oil and gas reservoir development, and particularly to an equivalent numerical simulation method for integrated fracturing-production of tight oil and gas reservoirs. Background Technique

[0002] Due to the characteristics of complex lithology, strong water sensitivity, and easy reservoir damage in tight oil and gas reservoirs, there are often problems such as unsatisfactory formation of fracture networks, strong pressure sensitivity of fracture conductivity, difficult formation energy replenishment, and rapid production decline during fracturing and production processes. It is necessary to comprehensively design and optimize the fracturing and development processes as a whole. Since the fracturing-development process involves multiple disciplines such as wellbore pipe flow, formation seepage, and rock mechanics, and involves multi-field coupling calculations of heat-fluid-solid-chemistry-mechanics, there is currently no good integrated numerical simulation method for fracturing-development.

[0003] Currently, 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 they are coupled, one of the functions is relatively weak. Commonly used wellbore multiphase flow calculation software includes Pipesim and OLGA, etc., commonly used reservoir numerical simulation software includes Eclipse, CMG, and VIP, etc., and commonly used hydraulic fracturing simulation software includes FracMan, COMSOL, ABAQUS, etc. Among them, the main numerical simulation methods for hydraulic fracturing include the 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 methods. This method establishes a boundary integral equation based on the fundamental solution of the control differential equation to express the problem, and through interpolation and discretization of the boundary elements, it is transformed into a system of algebraic equations for solution. The unconventional fracture model is established on the basis of a quasi-three-dimensional model, considering the stress field of the reservoir and the stress interference between adjacent fractures. The control equations of this model include the proppant settlement equation, G-W fracture extension criterion, and fracture deformation equation. Using this model, parameters such as the width of the fracture can be calculated. The discretized fracture network model is a relatively mature model for simulating complex fracture networks in hydraulic fracturing. This model assumes that the fracture network is a quasi-elliptical sphere, the main fracture is perpendicular to the minimum horizontal principal stress σh, and intersects with secondary fractures to form an orthogonal fracture network. The extended finite element method is proposed by adding generalized node degrees of freedom on the basis of the classical finite element method and improving the interpolation shape function. It is currently the most accurate method for solving discontinuous problems and is widely used at home and abroad. However, none of the above methods have coupled the reservoir seepage model, or the coupled reservoir seepage model has a weak function in characterizing the stimulation mechanism, such as CO 2 During the energy-enhanced fracturing process, CO 2It not only helps to generate a large number of induced fractures to form a fracture network with a larger coverage area and a more complex shape, but also can play the production-increasing mechanisms such as swelling and viscosity reduction, and solution gas drive. This requires a more powerful integrated fracturing-development model.

[0004] In the Chinese patent application with the application number: CN202010926532.3, it relates to the field of numerical simulation of enhanced oil recovery by CO 2 flooding in low-permeability oil reservoirs, and particularly relates to a method for simulating the oil displacement flow in a fractured oil reservoir by CO 2 flooding. The method includes the following steps: determining the positions of artificial major fractures and micro-fracture regions generated by fracturing, and establishing a geometric model of the fractured oil reservoir; establishing a hybrid model to characterize fractures at different scales, performing grid meshing to form a grid system; establishing a component model to describe the CO 2 oil displacement process, considering the components therein, and describing the phase change and the miscible mechanism of CO 2 and crude oil; formulating a solution scheme to solve the complex component model of the fractured oil reservoir to make the simulation process stable. The method of the present invention can accurately describe both artificial major fractures and small fractures generated during the fracturing or gas injection process while simulating the CO 2 oil displacement flow process, overcoming the difficulties faced by the existing methods for simulating the CO 2 oil displacement in fractured oil reservoirs as described above.

[0005] In the Chinese patent application with the application number: CN201910055675.9, it relates to a method and device for simulating the productivity of a fractured reservoir. The method includes: establishing a plurality of embedded discrete fracture numerical simulation models according to multiple groups of initial eigenvalue of fracture parameters, reservoir structure characteristic parameters of the oil reservoir, reservoir property characteristic parameters of the oil reservoir, and numerical discrete solution format parameters; obtaining multiple groups of simulated values of the productivity parameters of the oil reservoir according to the plurality of embedded discrete fracture numerical simulation models; updating the multiple groups of initial eigenvalue of the fracture parameters according to the multiple groups of simulated values of the productivity parameters of the oil reservoir to obtain multiple groups of eigenvalue of the updated fracture parameters; using the multiple groups of eigenvalue of the updated fracture parameters as the multiple groups of initial eigenvalue of the fracture parameters, and re-executing the above steps until the number of times of re-execution reaches a preset iteration number, and outputting the multiple groups of simulated values of the latest productivity parameters of the oil reservoir. The present invention can simulate the productivity of a fractured reservoir, with small computational amount and high accuracy.

[0006] In the Chinese patent application with the application number CN202110439529.3, a simulation method for repeated fracturing of horizontal wells in tight conglomerate reservoirs is involved, including the following steps: establishing a geological model based on reservoir data; obtaining an initial fracture network model through UFM fracture propagation simulation and correcting it to obtain the final fracturing simulation fracture network morphology; establishing an unstructured grid numerical simulation model and correcting it through production performance simulation; optimizing the water injection plan through water injection energy increase simulation and optimizing the shut-in time through four-dimensional geological modeling based on the optimized water injection plan; establishing a fracture network model after repeated fracturing; establishing a numerical simulation model after repeated fracturing and conducting repeated fracturing production performance simulation. By adopting the existence of multiple groups of micro-scale natural fractures equivalent to gravel, the invention makes the fracture propagation more in line with the conglomerate reservoir; through four-dimensional in-situ stress modeling, an in-situ stress model at different time points is established, and based on the in-situ stress recovery situation, it provides a basis for determining the water injection plan and the shut-in time after water injection in the conglomerate reservoir, that is, when to carry out repeated fracturing work.

[0007] The above existing technologies are all quite different from the present invention and fail to solve the technical problems we want to solve. Therefore, we have invented a new equivalent numerical simulation method for integrated fracturing and production in tight oil and gas reservoirs. Summary of the Invention

[0008] The object of the present invention is to provide an equivalent numerical simulation method for integrated fracturing and production in tight oil and gas reservoirs, which can provide a new research tool for the design and optimization of integrated fracturing and production plans in tight oil and gas reservoirs, so as to achieve the efficient and stable development of tight oil and gas reservoirs.

[0009] The object of the present invention can be achieved by the following technical measures: an equivalent numerical simulation method for integrated fracturing and production in tight oil and gas reservoirs, which includes:

[0010] Step 1, depict the hydraulic fracturing fracture morphology of the tight oil and gas reservoir and endow corresponding physical properties;

[0011] Step 2, establish an equivalent reaction model for fracture opening - propagation - proppant filling to simulate the dynamic formation process of the fracture;

[0012] Step 3, conduct coupled calculations of wellbore tubing flow - reservoir seepage - fracturing reaction to achieve equivalent simulation of integrated fracturing and production.

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

[0014] Step 1 includes:

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

[0016] S12. Based on the indoor test results of formation fracture pressure, matrix permeability, and fracture conductivity, obtain the porosity, permeability, compressibility, and porosity-permeability relationship tables for different medium regions such as the matrix, main fractures, and branched fractures;

[0017] S13. Assign 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, achieving the effect of fracture cracking after the pore pressure reaches the formation fracture pressure.

[0018] In step 11, based on microseismic data or fracture interpretation results, identify the fracture morphology, and use geological modeling software and the method of encrypted grids to depict the distribution and trend of main fractures and branched fractures.

[0019] Step 2 includes:

[0020] S21. Inject preflush fluid to open the formation;

[0021] S22. Inject proppant-carrying fluid to fill the proppant into the fractures;

[0022] S23. Inject displacement fluid to displace the proppant deep into the fractures;

[0023] S24. After the fracturing fluid flows back, high-conductivity fractures are formed in the formation.

[0024] In step 21, for the preflush fluid injection stage, use the rock compressibility to simulate the increase in porosity caused by the increase in injection pressure; use the porosity-permeability relationship table to simulate the increase in permeability caused by the increase in porosity. For the fracture region, set the permeability corresponding to the porosity to suddenly increase when the formation pressure reaches above the fracture pressure to simulate the opening of the fractures.

[0025] In step 22, for the proppant-carrying fluid injection stage, define the proppant in the proppant-carrying fluid as the aqueous phase component P(w), set a certain concentration of the solid phase component R(S) in the fracture grid to be opened, and then define a solid phase component P(S). When the formation pressure reaches above the fracture pressure, the following reaction occurs when the three come into contact:

[0026] P(w)+R(S)+H 2 O→P(S)+nH 2 O

[0027] Among them, the density of P(S) should be large enough so that the volume of P(S) after the reaction is significantly smaller than that of R(S), or directly ignore the generation of P(S), thereby producing the effect of increased porosity to simulate the filling process of the proppant in the fractures, and ensure that after the fracturing is completed, the fractures can still maintain a large porosity and high conductivity; in addition, further use local equilibrium reaction settings to ensure that the above reaction occurs only when the formation pore pressure exceeds the fracture pressure.

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

[0029] In step 24, for the fracturing fluid flowback stage, the fracturing fluid is flowed back under reduced pressure and the bottom-hole flowing pressure decreases.

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

[0031] W nj →mH 2 O + W pj .

[0032] Step 3 includes:

[0033] S31. Based on the pipe flow theory, establish a transient model of multiphase flow in the fracturing wellbore;

[0034] S32. By means of the flexible well model in the reservoir numerical simulation method, realize the transient simulation of multiphase flow in the fracturing wellbore;

[0035] S33. Couple the flexible well model with the reservoir seepage model to realize the integrated simulation of wellbore pipe flow and formation seepage;

[0036] S34. Further couple the fracture opening - propagation - proppant filling reaction model to realize the integrated simulation of fracturing - production.

[0037] The object of the present invention can also be achieved by the following technical measures: a tight oil and gas reservoir fracturing - production integrated equivalent numerical simulation system, which uses the tight oil and gas reservoir fracturing - production integrated equivalent numerical simulation method to design and optimize the injection - production parameters by taking the fracturing and production processes as a whole.

[0038] The tight oil and gas reservoir fracturing - production integrated equivalent numerical simulation method in the present invention relates to the numerical simulation of hydraulic fracturing and development. Based on the coupled calculation of wellbore pipe flow and formation seepage, it can realize the simulation of the whole process of fracturing fluid injection along the wellbore, fracture opening - propagation - proppant filling and flowback production. With the help of this method, the fracturing and production processes can be taken as a whole to design and optimize the injection - production parameters, providing a new research tool for the design and optimization of the tight oil and gas reservoir fracturing - production integrated plan. Description of the Drawings

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

[0040] Figure 2 Schematic diagram of the change in formation fracture permeability, i.e., the conductivity, during the fracturing - flowback process in a specific embodiment of the present invention;

[0041] Figure 3 Flowchart of a specific embodiment of the equivalent numerical simulation method for integrated fracturing - production in tight oil and gas reservoirs of the present invention;

[0042] Figure 4 In a specific embodiment of the present invention, during the fracturing - flowback process, the 2 phase change diagram of CO;

[0043] Figure 5 In a specific embodiment of the present invention, during the fracturing - flowback process, the 2 phase change diagrams of CO at different 2 injection temperatures;

[0044] Figure 6 In a specific embodiment of the present invention, during the fracturing - flowback process, the 2 phase change diagrams of CO at different 2 injection volumes. Detailed implementation manners

[0045] It should be noted that the following detailed description is exemplary and is intended to provide further explanation of the present invention. Unless otherwise specified, all technical and scientific terms used herein have the same meaning as commonly understood by those of ordinary skill in the technical field to which the present invention belongs.

[0046] It should be noted that the terms used herein are only for describing specific implementation manners and are not intended to limit the exemplary embodiments according to the present invention. As used herein, unless the context clearly indicates otherwise, the singular forms are also intended to include the plural forms. In addition, it should be understood that when the terms "comprising" and / or "including" are used in this specification, they specify the presence of features, steps, operations, and / or combinations thereof.

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

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

[0049] S2. Establish an equivalent reaction model for fracture opening - propagation - proppant filling to simulate the dynamic formation process of fractures;

[0050] S3. Perform the coupling calculation of wellbore pipe flow - reservoir seepage - fracturing reaction to achieve the equivalent simulation of integrated fracturing - production.

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

[0052] S11. Identify the crack morphology based on microseismic data or fracturing interpretation results, and use geological modeling software and the method of encrypted grids to depict the distribution and trend of main cracks and branch cracks.

[0053] S12. According to the formation fracture pressure, indoor test results of matrix permeability and fracture conductivity, obtain data such as porosity, permeability, compressibility, and pore - permeability relationship tables of different medium regions such as matrix, main cracks, and branch cracks.

[0054] S13. Assign 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 crack opening can be achieved when the pore pressure reaches the formation fracture pressure.

[0055] Preferably, in step S2, the steps of establishing an equivalent reaction model for fracture opening - propagation - proppant filling to simulate the dynamic formation process of fractures are as follows:

[0056] S21. The simulated hydraulic fracturing process mainly includes the following steps: (1) Inject the pre - flush fluid to open the formation; (2) Inject the sand - carrying fluid to fill the proppant into the fracture; (3) Inject the displacement fluid to displace the proppant to the deep part of the fracture; (4) After the fracturing fluid flows back, a high - conductivity fracture is formed in the formation.

[0057] S22. For the pre - flush fluid injection stage: Use the rock compressibility to simulate the increase in porosity caused by the increase in injection pressure; use the relationship table between permeability and porosity to simulate the increase in permeability caused by the increase in porosity. For the fracture region, set the permeability corresponding to the porosity to suddenly increase when the formation pressure reaches above the fracture pressure 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 the aqueous phase component P(w), set a certain concentration of solid phase component R(S) in the fracture grid to be opened, and then define a solid phase component P(S). When the formation pressure reaches above the fracture pressure, the following reaction occurs when the three come into contact:

[0059] P(w)+R(S)+H 2 O→P(S)+nH 2 O

[0060] Among them, the density of P(S) must be large enough so that the volume of P(S) after the reaction is significantly smaller than R(S), or the generation of P(S) can be directly ignored, thereby producing the effect of increasing porosity to simulate the filling process of proppant in the fracture and ensure that after the fracturing is completed, the fracture can still maintain a large porosity and high conductivity. In addition, a local equilibrium reaction setting is further adopted to achieve the above reaction only when the formation pore pressure exceeds the fracture 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 flowback stage: the fracturing fluid is depressurized and flowed back, and the bottom hole flow pressure is reduced. For the gel breaking process of the fracturing fluid, define component W nj It is a high viscosity component in the fracturing fluid, generating water and gel breaking product W pj The specific reactions are as follows:

[0063] W nj →mH 2 O+W pj

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

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

[0066] S32. With the help of the flexible well model in the reservoir numerical simulation method, the transient simulation of multiphase flow in the fractured wellbore is realized.

[0067] S33. Couple the flexible well model with the reservoir seepage model to achieve integrated simulation of wellbore flow and formation seepage.

[0068] S34, further coupling the fracture opening-extension-proppant filling reaction model to achieve integrated fracturing-production simulation;

[0069] The following are several specific embodiments of the present invention.

[0070] Example 1

[0071] In a specific embodiment 1 of the present invention, a vertical well CO2 is established by referring to the hydraulic fracturing conditions of the production wells in the salt 222 block of the Shengli Oilfield tight oil reservoir. 2Energy - increasing numerical simulation model, and the basic parameters of the model are set as shown in Table 1. The geological model consists of two parts. The near - wellbore formation attached to the flexible well is from the ground to 3900 m underground, with a grid size of 10×10×100 m, the number of grids is 3×3×39 = 351, and both the porosity and permeability are 0. The target reservoir is from 3900 m to 3950 m underground, with a thickness of 50 m, a porosity of 8%, a permeability of 1.6 md, a temperature of 150 °C, a pressure of 38.71 MPa, and a grid size of 10×10×10 m. The number of grids in the reservoir is 51×29×5 = 7395( Figure 1 a). Under typical fracturing conditions, the injection temperature of CO 2 is - 20 °C, the bottom - hole temperature is 15 °C, the total injection volume of CO 2 is 200 t, the injection speed is 2 t / min, the total injection volume of the fracturing fluid is 900 m 3 , the injection speed is 10 m 3 / min, shut - in for 12 h, the flow - back speed is 3 m 3 / h, flow - back for 30 days. It is expected that the half - length of the main fracture can reach 150 m, the half - bandwidth of the branch fracture can reach 45 m, the fracture height can reach 30 m, the grid near the fracture is encrypted to 5×5×1, the conductivity of the main fracture is 983×0.6 md·m, and the conductivity of the branch fracture is 250×0.6 md·m( Figure 1 b); at the same time, through laboratory experiments, the relationships between the matrix, main fracture, and branch - fracture pressure - sensitive porosity and permeability of the target reservoir are determined, as shown in Figure 1 c).

[0072] Table 1 Basic parameter table of the energy - increasing fracturing numerical simulation model of CO 2 The predicted changes in fracture permeability at different stages of fracturing and flow - back are shown in

[0073]

[0074] As can be seen from the figure, after CO Figure 2 is injected underground, due to the low viscosity of CO 2 , induced fractures are mainly generated along the direction of the main fracture, and micro - fractures are generated in the direction of the branch fracture. After the subsequent injection of the proppant - carrying fracturing fluid, due to the high viscosity of the fracturing fluid, the permeability of the main fracture and branch fracture near the bottom - hole increases significantly; during the shut - in period, due to the energy - increasing effect of CO 2 , the fractures tend to further expand and increase permeability; after opening the well, as the bottom - hole flowing pressure drops, the fracture conductivity is well maintained. 2 The changes in temperature, pressure, and phase state of CO

[0075] along the wellbore and fractures during the fracturing process are shown in 2 As shown. The key node positions marked in the figure are: 1 - 5 - CO Figure 4 shown. The key node positions marked in the figure are: 1 - 5 - CO 2At the end of injection: wellhead, 1000 m depth, 2000 m depth, 3000 m depth, bottom hole; 6 - 7 - CO 2 Free CO in the fracture at the end of injection 2 Swept front, CO in oil phase 2 Swept front; Free CO in the fracture at the end of fracturing fluid injection: 8 - 9 2 Swept front, CO in oil phase 2 Swept front; Free CO in the fracture at the end of shut - in: 10 - 11 2 Swept front, CO in oil phase 2 Swept front; First appearance of CO during flow - back: 12 - 16 2 At bottom hole, 3000 m depth, 2000 m depth, 1000 m depth, wellhead. The phase curves, zones of CO 2 and the phase curve of CO hydrate are marked in the figure 2

[0076] It is obtained through simulation that: for CO 2 At the end of injection, the temperature in the wellbore gradually increases downward, from - 20 °C at the wellhead to 15.82 °C at the bottom hole, and the pressure increases from 17.05 MPa to 51.12 MPa. CO in the whole wellbore 2 is in liquid state; The radius of the low - temperature zone formed near the bottom hole is about 10 m, and the swept radius of CO 2 is about 50 m. From the bottom hole to the deep part of the fracture, CO 2 changes from liquid state to supercritical state. When the injection of fracturing fluid ends, the reservoir temperature along the fracture direction further decreases, the radius of the low - temperature zone expands to 20 m, the temperature is between 20 - 30 °C, and the distribution range of CO 2 also expands further. During the shut - in period, the temperature of the near - wellbore formation recovers somewhat, but the pressure - swept range and the distribution range of CO 2 further expand. At the end of the shut - in, the temperature of the near - wellbore formation recovers to 40 - 60 °C, and the swept radius of CO 2 expands to 110 m. When CO appears during flow - back 2 the temperature at the bottom hole returns to 34.68 °C, the temperature of the near - wellbore formation recovers to about 90 °C, and the distribution range of CO 2 decreases. CO in the formation 2 mainly exists in dissolved state and supercritical state. The distribution range in the oil phase is larger than that in the supercritical state. The temperature and pressure at the swept front are close to the original formation conditions and are not greatly affected by the injection temperature. During flow - back, the temperature in the wellbore first rises and then falls from the bottom hole to the wellhead, and CO 2 changes from supercritical state to gaseous state. Through analysis, for CO 2 2 ​​When the wellbore temperature and pressure during injection meet the hydrate formation conditions, it is necessary to prevent hydrate risks. However, in the formation and the flowing-back wellbore, the temperature is relatively high and the pressure is relatively low, so the hydrate risk is small.

[0077] Example 2

[0078] In the specific Example 2 of applying the present invention, on the basis of Example 1, the CO 2 injection temperature was changed, and the influence analysis of the CO 2 injection temperature on the fracturing - flowing - back effect was carried out. During the fracturing process at different CO 2 injection temperatures, the CO 2 temperature, pressure and phase changes in the wellbore and formation are as Figure 5 shown. It can be seen from the figure that the smaller the CO 2 injection temperature, the lower the bottom - hole temperature at the end of CO 2 injection (42.84 → 15.82 °C), but the CO 2 in the wellbore is generally in a liquid state. Only when the injection temperature is 20 °C, the CO2 in the wellbore will undergo a phase change, that is, from a liquid state to a supercritical state; the CO 2 injection temperature has little influence on the reservoir pressure and the CO 2 distribution. The CO 2 is in a supercritical state in the formation; during the blow - down production, the lower the CO 2 injection temperature, the smaller the bottom - hole temperature rise (58.76 → 34.68 °C), but it has little influence on the wellbore temperature and pressure conditions above 3000 m and the process of the CO 2 changing from a supercritical state to a gaseous state within a 1000 - m well section. In addition, the higher the CO 2 injection temperature, the lower the hydrate risk in the wellbore. When the injection temperature is 20 °C, there is no hydrate risk in the wellbore.

[0079] Example 3

[0080] In the specific Example 3 of applying the present invention, on the basis of Example 1, the CO 2 injection total amount was changed, and the influence analysis of the CO 2 injection total amount on the fracturing - flowing - back effect was carried out. During the fracturing process at different CO 2 injection total amounts, the CO 2 temperature, pressure and phase changes in the wellbore and formation are as Figure 6 shown. It can be seen from the figure that the larger the CO 2 injection total amount, the lower the bottom - hole temperature at the end of CO 2 injection (24.09 → 12.85 °C), and the larger the distribution range in the formation. The CO 2 remains in a liquid state in the wellbore and turns into a supercritical state after entering the formation; when the blow - down production is carried out, the CO 2The greater the total injection volume, the smaller the bottom-hole temperature rise (44.3 → 31.73 °C), but the influence on the phase change of CO in the wellbore is relatively small. In addition, the smaller the total injection volume of CO, the smaller the risk of hydrates in the wellbore. 2 The influence on the phase change of CO is relatively small. 2 The smaller the total injection volume, the smaller the risk of hydrates in the wellbore.

[0081] Finally, it should be noted that the above are only the preferred embodiments of the present invention and are not used to limit the present invention. Although the present invention has been described in detail with reference to the foregoing embodiments, those skilled in the art can still modify the technical solutions described in the foregoing embodiments, or perform equivalent replacements for some of the technical features. Any modifications, equivalent replacements, improvements, etc. made within the spirit and principle of the present invention shall be included within the protection scope of the present invention.

[0082] Except for the technical features described in the specification, the rest are known technologies to those skilled in the art.

Claims

1. An equivalent numerical simulation method for integrated fracturing - production in tight oil and gas reservoirs, characterized in that, the equivalent numerical simulation method for integrated fracturing - production in tight oil and gas reservoirs includes: Step 1: Characterize the hydraulic fracturing crack morphology in the tight oil and gas reservoir and assign corresponding physical property parameters; Step 2: Establish an equivalent reaction model for fracture opening - propagation - proppant filling to simulate the dynamic formation process of the fracture; Step 3: Conduct coupled calculations of wellbore pipe flow - reservoir seepage - fracturing reaction to achieve equivalent simulation of integrated fracturing - production.

2. The equivalent numerical simulation method for integrated fracturing - production in tight oil and gas reservoirs according to claim 1, characterized in that, Step 1 includes: S11: Characterize the distribution and trend of the main fracture and branch fractures; S12: Obtain data such as porosity, permeability, compressibility, and the pore - permeability relationship table for different medium regions of the matrix, main fracture, and branch fractures according to the formation fracture pressure and the indoor test results of matrix permeability and fracture conductivity; S13: Assign 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, achieving the effect of fracture cracking after the pore pressure reaches the formation fracture pressure.

3. The equivalent numerical simulation method for integrated fracturing - production in tight oil and gas reservoirs according to claim 2, characterized in that, In step 11, based on micro - seismic data or fracturing interpretation results, fracture morphology recognition is carried out, and the distribution and trend of the main fracture and branch fractures are characterized by using geological modeling software and the method of encrypted grids.

4. The equivalent numerical simulation method for integrated fracturing - production in tight oil and gas reservoirs according to claim 1, characterized in that, Step 2 includes: S21: Inject the pre - flush fluid to open the formation; S22: Inject the proppant - carrying fluid to fill the fracture with proppant; S23: Inject the displacement fluid to displace the proppant deep into the fracture; S24: After the fracturing fluid flows back, high - conductivity fractures are formed in the formation.

5. The equivalent numerical simulation method for integrated fracturing - production in tight oil and gas reservoirs according to claim 4, characterized in that, In step 21, for the pre - flush fluid injection stage, the rock compressibility is used to simulate the increase in porosity caused by the increase in injection pressure; the relationship table between permeability and porosity is used to simulate the increase in permeability caused by the increase in porosity. For the fracture region, when the formation pressure reaches above the fracture pressure, the permeability corresponding to the porosity suddenly becomes larger to simulate the opening of the fracture.

6. The equivalent numerical simulation method for integrated fracturing - production in tight oil and gas reservoirs according to claim 4, characterized in that, In step 22, for the proppant - carrying fluid injection stage, the proppant in the proppant - carrying fluid is defined as the aqueous phase component P(w), a certain concentration of solid phase component R(S) is set in the fracture grid to be opened, and then a solid phase component P(S) is defined. When the formation pressure reaches above the fracture pressure, the following reaction occurs when the three come into contact: P(w)+R(S)+H 2 O→P(S)+nH 2 O Among them, the density of P(S) must be large enough so that the volume of P(S) after the reaction is significantly smaller than R(S), or the generation of P(S) can be directly ignored, thereby producing the effect of increased porosity to simulate the filling process of the proppant in the fracture and ensure that after the fracturing is completed, the fracture can still maintain a large porosity and high conductivity; in addition, a local equilibrium reaction setting is further adopted to achieve that the above reaction will only occur when the formation pore pressure exceeds the fracture pressure.

7. The equivalent numerical simulation method for integrated fracturing and production of tight oil and gas reservoirs according to claim 4, It is characterized in that In step 23, the displacement fluid injection stage is similar to the sand-carrying fluid injection stage, but without proppant, and no reaction occurs.

8. The equivalent numerical simulation method for integrated fracturing and production of tight oil and gas reservoirs according to claim 4, It is characterized in that In step 24, during the fracturing fluid flowback stage, the fracturing fluid is flowed back at a reduced pressure, and the bottom hole flow pressure is reduced.

9. The equivalent numerical simulation method for integrated fracturing and production of tight oil and gas reservoirs according to claim 8, It is characterized in that In step 24, for the gel-breaking process of the fracturing fluid, component W is defined nj as the high-viscosity component in the fracturing fluid, generating water and gel-breaking product W pj , and the specific reaction is as follows: W nj → mH 2 O + W pj 。 10. The equivalent numerical simulation method for integrated fracturing and production of tight oil and gas reservoirs according to claim 1, It is characterized in that Step 3 includes: S31. Based on pipe flow theory, a transient model of multiphase flow in a fracturing wellbore is established; S32. Using the flexible well model in the reservoir numerical simulation method, the transient simulation of multiphase flow in the fractured wellbore is realized; S33, coupling the flexible well model with the reservoir seepage model to achieve integrated simulation of wellbore pipe flow and formation seepage; S34. Further couple the fracture opening-extension-proppant filling reaction model to achieve integrated fracturing-production simulation.

11. Tight oil and gas reservoir fracturing-production integrated equivalent numerical simulation system, It is characterized in that The tight oil and gas reservoir fracturing-production integrated equivalent numerical simulation system adopts the tight oil and gas reservoir fracturing-production integrated equivalent numerical simulation method described in any one of claims 1 to 10 to design and optimize injection and production parameters of the fracturing and production process as a whole.

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