CO2-water drive reservoir remaining oil dynamic evaluation method

Abstract

The invention belongs to the field of residual oil dynamic analysis, and discloses a CO2-water drive reservoir residual oil dynamic evaluation method. Comprising the steps of establishing a fine three-dimensional geologic model, fitting fluid PVT experimental data, performing historical fitting on an oil reservoir component numerical simulation model and production data of a research area, partitioning reservoirs, calculating remaining oil reserves, and determining the distribution condition and the dynamic change condition of remaining oil between wells. The problem that the dynamic change rule of the remaining oil in different areas is not fully considered in an existing method is solved, and a basis is provided for adjustment of a development strategy in the next step.

Description

Technical Field

[0001] The present invention belongs to the field of remaining oil dynamic analysis, and particularly relates to a method for dynamically evaluating remaining oil in a CO2-water flooding reservoir. Background Art

[0002] The growing global energy demand has greatly promoted the exploration process of unconventional oil and gas resources.

[0003] Applying CO2 flooding is one of the important technologies for enhanced oil recovery. Since the 1950s, the application and research of CO2 flooding technology for enhanced oil recovery have kicked off. The United States took the lead in using CO2 flooding and achieved great success. Countries such as Russia, Hungary, Canada, Turkey, France, and Germany have also successively developed and utilized CO2 flooding technology.

[0004] Due to the lack of natural CO2 gas sources in China, the research on CO2 flooding started relatively late. In the early 1960s, China began indoor experimental research and pilot field tests on CO2 flooding technology for enhanced oil recovery. Although the start was a bit late, it has developed rapidly.

[0005] As a tertiary oil recovery technology, the sweep and displacement degree of remaining oil is an important indicator for evaluating the effect of CO2 flooding. However, the dynamic distribution of remaining oil has always been one of the difficulties in reservoir analysis work. Existing remaining oil analysis is generally based on a reservoir numerical simulation model after historical matching. However, limited by the reservoir heterogeneity and the limitations of existing software in regional remaining oil analysis, it is difficult to form a convenient and systematic evaluation of the dynamic production effect of regional remaining oil.

[0006] Research shows that the refinement degree of the geological model grid directly affects the effect in the study of remaining oil distribution (Feng Mingsheng (2008)). Especially in order to simulate the fluid property changes in gas flooding, it is necessary to use a compositional model for analysis, which further increases the difficulty of analysis.

[0007] Zhu Xiaolin et al. (2022) and others, on the basis of reservoir classification, clarified the remaining oil distribution law and occurrence situation, and provided a set of potential tapping strategies in combination with numerical simulation technology. However, there is still a large room for improvement in the refined and systematic quantitative description of remaining oil.

[0008] The description of remaining oil in the prior art focuses on static analysis, and there are few analysis results on dynamic remaining oil. Conducting refined dynamic description of remaining oil in different regions can clarify the flow direction of the oil phase in the reservoir at different times, and further clarify the influence of different stimulation measures such as perforation, well pattern densification, injection conversion to pumping, etc. on the reservoir production effect. Currently, many development practices in low-permeability reservoirs show that: the water absorption capacity of some injection wells is low, the startup pressure and injection pressure are high, and as the injection time prolongs, the contradiction intensifies, and even water cannot be injected. The bottom hole pressure of the water well approaches the formation fracture pressure, and it is difficult to establish an effective displacement pressure system in the reservoir. The reason is that: there is a startup pressure gradient in low (extra-low) permeability reservoirs, and this resistance must be overcome during water injection development. At the same time, due to the solid-liquid interface effect, there is interfacial layer fluid on the pore surface, and a certain external force is required for the interfacial layer fluid to flow. For low-porosity and low-permeability cores, since the throat radius is very small, most or all of the seepage throats are occupied by the interfacial layer fluid. Therefore, there are pseudo startup pressure gradients and true startup pressure gradients to varying degrees in fluid seepage. Therefore, the prior art has not accurately simulated the non-linear seepage state at reservoir temperature, and it is urgent to improve the experimental method and establish a testing technology for the non-linear seepage section of carbon dioxide flooding under formation temperature and pressure. The current non-linear motion equations can be mainly divided into segmented models and continuous models. The pseudo startup pressure gradient model is a typical segmented model, which describes the non-linear seepage problem by replacing the non-linear section with a straight line. Essentially, it is a startup pressure gradient problem and is only applicable to conventional low-permeability reservoirs with an insignificant non-linear section. Summary of the Invention

[0009] In order to overcome the deficiencies of the prior art, the present invention provides a method for dynamically evaluating remaining oil in a CO2-water flooding reservoir. For low-permeability - shale oil reservoir rock samples, a method for evaluating the effective displacement distance of carbon dioxide injection in low-permeability - tight reservoirs is established. Based on the traditional startup pressure gradient testing technology, a mathematical relationship between the startup pressure gradient and permeability is established, and the effective displacement distance under different permeability reservoirs and different pressure gradient conditions is calculated; according to the actual operating regime parameters of the reservoir, the actual carbon dioxide displacement distance of the reservoir is obtained.

[0010] The above object of the present invention is achieved by the following technical solutions: A method for dynamically evaluating remaining oil in a CO2-water flooding reservoir, the steps are as follows:

[0011] 1. Apply petrel software to establish a fine three-dimensional geological model for the study area, and its grid accuracy is: the plane grid size shall not be greater than 20m × 20m, and the longitudinal grid height shall not exceed 1m;

[0012] 2. Apply the PVTi module of eclipse to fit the PVT experimental data of the fluid. Among them, CO2 needs to be used as a separate component, and in terms of the fitting results, the fitting errors of various indicators such as liquid phase viscosity and relative volume should be within 10%.

[0013] 3. Based on the established fine three-dimensional geological model, organize the well history data of production wells, and thus establish a numerical simulation model of reservoir component for the study area. To fully simulate the interlayer crossflow of multi-layer commingled production wells and the impact of crossflow between wells caused by the existence of fractures on numerical simulation, measures such as perforation and fracturing need to be considered;

[0014] 4. Conduct historical matching on production data, with the error between the measured cumulative oil production of the oilfield and the cumulative oil production calculated by the model not exceeding 2%, the error between the measured production of a single well and the production calculated by the model not exceeding 10%, and the fitting error of water cut of a single well not exceeding 10%;

[0015] 5. Divide the reservoir according to the actual development situation of the oil reservoir. In area flooding, divide the block equally, and in gravity flooding, divide different regions of the oil reservoir according to the structural situation of the formation;

[0016] 6. Calculate the remaining oil reserves of the oil reservoir in different regions at different times respectively, and make a trend chart. Combine measures such as water injection, perforation, gas injection, and well pattern infilling in the development process to analyze the change trend of the remaining oil, and clarify the adaptability of different regions under different production enhancement measures; Here, it is necessary to observe the change trend of the remaining oil reserves. If the decline rate of the remaining oil is small before the production enhancement measure, while the decline rate of the remaining oil is large after the production enhancement measure and the oil production increases significantly, it proves that the production enhancement measure has good adaptability in this region, otherwise it proves poor adaptability;

[0017] 7. When the local recovery rate of a certain key area is lower than the average recovery rate of the oil reservoir, there is more remaining oil in this area. Therefore, it can be used as a key area for secondary subdivision of the reservoir, conduct dynamic and detailed research on the remaining oil in different regions, so as to clarify the distribution and dynamic changes of the remaining oil between wells, and lay a foundation for the formulation of the next production enhancement measures.

[0018] Further, the specific steps of step 1 are as follows:

[0019] ① Based on the fracture system and geological stratification, establish a three-dimensional fault model and a stratigraphic framework model;

[0020] ② According to the sandstone thickness and sand-to-shale ratio distribution characteristics, draw a trend plan of sand body development probability, and establish a lithofacies model by constraint;

[0021] ③ In the sandstone and mudstone facies, use the hierarchical facies control method to simulate the reservoir property model;

[0022] ④ Based on the understanding of the oil-water distribution characteristics, conduct reserve fitting by stratification and zoning, and verify the geological model by multiple methods.

[0023] The beneficial effects of the present invention compared with the prior art are as follows: For low-permeability shale oil reservoir rock samples, an evaluation method for the effective displacement distance of carbon dioxide injection in low-permeability tight oil reservoirs is established. Based on the traditional startup pressure gradient test technology, a mathematical relationship between the startup pressure gradient and permeability is established, and the effective displacement distances under different permeability reservoirs and different pressure gradient conditions are calculated. According to the actual operating regime parameters of the reservoir, the actual carbon dioxide displacement distance of the reservoir is obtained, thus solving the problem that the dynamic change law of remaining oil in different regions is not fully considered in the existing methods, and further providing a basis for the adjustment of the next development strategy. BRIEF DESCRIPTION OF THE DRAWINGS

[0024] The present invention will be further described below in conjunction with the drawings and specific embodiments.

[0025] Figure 1 It is a relationship diagram of startup pressure and permeability of the present invention;

[0026] Figure 2 It is a relationship diagram of displacement distance and permeability of the present invention

[0027] Figure 3 It is a fine three-dimensional geological model diagram of the present invention;

[0028] Figure 4 It is a fluid phase diagram and key fluid physical property parameter diagram of the present invention;

[0029] Figure 5 It is a reservoir numerical simulation model of the research area of the present invention;

[0030] Figure 6 It is a diagram of the permeability distribution of different sub-areas calculated by numerical simulation of the present invention;

[0031] Figure 7 It is a schematic diagram of the percentage change of remaining oil over time in the key area of the reservoir of the present invention;

[0032] Figure 8 It is a secondary subdivision diagram of the reservoir in the key area (Area 19) of the reservoir of the present invention;

[0033] Figure 9 It is a dynamic change diagram of remaining oil in the key area of the secondary subdivision reservoir of the present invention. SPECIFIC EMBODIMENTS

[0034] The present invention will be described in detail below through specific embodiments, but the protection scope of the present invention is not limited. Unless otherwise specified, the experimental methods used in the present invention are all conventional methods, and the experimental equipment, materials, reagents, etc. used can be obtained from commercial channels.

[0035] Example 1

[0036] A method for dynamically evaluating remaining oil in a CO2-water flooding reservoir comprises the following steps:

[0037] (1) Apply Petrel software to establish a fine three-dimensional geological model for the study area, with its grid accuracy as follows: the plane grid size should not be greater than 20m×20m, and the vertical grid height should not exceed 1m.

[0038] ① Based on the fault system and geological stratification, establish a three-dimensional fault model and a stratigraphic framework model;

[0039] ② According to the distribution characteristics of sandstone thickness and sand-to-shale ratio, draw a trend plane map of sand body development probability to constrain the establishment of a lithofacies model;

[0040] ③ Adopt a hierarchical facies control method within the sandstone and mudstone facies to simulate the reservoir property model;

[0041] ④ Based on the understanding of the oil-water distribution characteristics, conduct reserve fitting by stratification and zoning, and verify the geological model with multiple methods.

[0042] (2) Apply the PVTi module of Eclipse to fit the PVT experimental data of fluids. Among them, CO2 needs to be regarded as a separate component, and in terms of the fitting results, the fitting errors of various indicators such as liquid-phase viscosity and relative volume should be within 10%.

[0043] (3) On the basis of establishing a fine three-dimensional geological model, sort out the well history data of production wells, so as to establish a numerical simulation model of reservoir components for the study area. To fully simulate the influence of interlayer crossflow in multi-layer commingled production wells and crossflow between wells caused by the existence of fractures on numerical simulation, it is necessary to consider measures such as perforation and fracturing.

[0044] (4) Conduct history matching on production data. The error between the measured cumulative oil production of the oilfield and the cumulative oil production calculated by the model should not be greater than 2%, the error between the measured production of a single well and the production calculated by the model should not be greater than 10%, and the fitting error of the water cut of a single well should not be greater than 10%.

[0045] (5) Divide the reservoir into zones in combination with the actual development situation of the oil reservoir. For example, in area flooding, the block can be equally divided into zones, and in gravity drainage, different regions of the oil reservoir can be divided according to the structural conditions of the formation.

[0046] (6) Calculate the remaining oil reserves of the oil reservoir in different regions at different times respectively, and make a trend chart.

[0047] Combined with measures such as water injection, well plugging, gas injection, and well pattern infilling during the development process, analyze the changing trend of remaining oil to clarify the adaptability of different regions under different production enhancement measures. Here, it is necessary to observe the changing trend of remaining oil reserves. If the decline rate of remaining oil is small before the production enhancement measure and large after the measure, and the oil production increases significantly, it proves that the production enhancement measure has good adaptability in this region; otherwise, it proves poor adaptability.

[0048] When the local recovery factor of a key region is lower than the average recovery factor of the reservoir, there is more remaining oil in this region. Therefore, it can be used as a key region for secondary subdivision of the reservoir, and conduct dynamic and detailed research on the remaining oil in different regions to clarify the distribution and dynamic changes of remaining oil between wells, so as to enhance production in the next step.

[0049] The basic data and experimental results of the nonlinear seepage experiment rock samples are shown in Table 1. Figure 1 Give the relationship between the starting pressure and permeability, Figure 2 Give the relationship between the displacement distance and permeability.

[0050] Table 1 Test results of the starting pressure of carbon dioxide flooding for 4 groups of rock samples

[0051]

[0052] Example 2

[0053] The method is the same as that in Example 1.

[0054] Taking a certain oilfield in Yitong Basin as an example, first establish a fine three-dimensional geological model as Figure 3 shown.

[0055] Then, use the PVTi module of eclipse to fit the PVT experimental data of reservoir fluids, and its phase diagram and key fluid physical property parameters are as Figure 4 shown.

[0056] Considering measures such as well plugging and fracturing, establish a reservoir numerical simulation model for the study area, as Figure 5 shown.

[0057] Conduct historical matching on production data. The error between the measured cumulative oil production of the oilfield and the cumulative oil production calculated by the model is not greater than 2%, the error between the measured single-well oil production and the oil production calculated by the model is not greater than 10%, and the fitting error of single-well water cut is not greater than 10%.

[0058] Combine the actual development situation of the reservoir to divide the reservoir into zones. In this invention example, the reservoir is equally divided. To study the production effect of remaining oil, the reservoir is divided into 24 zones on the plane, as Figure 6 shown.

[0059] Select four key development areas, namely Area 7, Area 11, Area 15 and Area 19, and make a trend chart of remaining oil, such as Figure 7 Shown

[0060] As can be seen from the figure, the distribution of remaining oil in different areas varies greatly. The analysis shows that:

[0061] In the 12 area, CO2 injection was carried out in 2014-2015. From the change of the remaining oil percentage, the gas injection adaptability of the 7 and 15 areas is better, and the remaining oil in these areas has a more obvious downward trend after gas injection. However, the gas injection adaptability of the 11 area is slightly worse, and the downward trend of the remaining oil after gas injection is not obvious.

[0062] In area 19, part of the oil phase is displaced to this area due to the displacement of surrounding injection wells. Therefore, this area is one of the key areas for increasing production. This area is further subdivided below to analyze the distribution of remaining oil between wells.

[0063] like Figure 8 Shown is a further regional breakdown for 19 regions.

[0064] Based on the reservoir subdivision, the remaining oil variation in different areas is studied and the remaining oil dynamics in different areas are analyzed, such as Figure 9 The figure shows the dynamic change of remaining oil in 11 selected study areas. It can be seen from the figure that there is obviously more remaining oil in this area. In areas 1, 2, 3, 6, and 11, the remaining oil shows a stable downward trend and the recovery rate is good, which proves that wells such as Y59-6-8 and Y59-8-10 in this area can maintain the existing working system. In areas 13, 14, 15, 18, 19, and 20, there is more remaining oil, and it is necessary to adopt working system adjustment methods such as plugging holes and fracturing for wells 0019 and 0010 in this area, or adopt measures such as well network density to improve the recovery rate.

[0065] Figure 1 The relationship between the starting pressure gradient and permeability of the target reservoir is given. Figure 1 It can be seen that there is a good negative correlation between the real start-up pressure gradient, the pseudo-start-up pressure gradient and the core permeability; the pseudo-start-up pressure gradient is 2.3 times the real start-up pressure gradient; the start-up pressure gradients corresponding to core permeabilities of 5.07mD, 3.13mD, 1.20mD and 0.53mD are 0.0087, 0.0210, 0.0970 and 0.2642MPa / m respectively.

[0066] Nonlinear seepage experimental data has a wide range of applications in oil and gas development. The limit well spacing method, effective production coefficient method, and numerical simulation method can be used to calculate the limit distance of fluid flow. The effective production coefficient method and numerical simulation method can calculate the limit well spacing more accurately, but both require a large amount of data. Therefore, this paper simply uses the limit well spacing method to calculate the limit distance of fluid flow. The advantage of this method is that the calculation is simple and fast, and it requires fewer basic parameters. Its specific theoretical basis is as follows:

[0067] The seepage theory of equal production - source - sink steady radial flow shows that among all streamlines, the seepage velocity on the main streamline is the largest; at the same streamline, the seepage velocity is the smallest at the point equidistant from the source and sink.

[0068] In the case of steady flow, Q = v·A = constant, and the seepage velocity can be expressed as:

[0069]

[0070] Plane radial flow production formula:

[0071]

[0072] In the formula: λ is the starting pressure gradient.

[0073] Substituting the production formula into the seepage velocity formula, we can get:

[0074]

[0075] According to the flow velocity formula, the pressure gradient at any point in the formation can be expressed as:

[0076]

[0077] Therefore, the pressure gradient at the mid - point of equal production - source - sink is:

[0078]

[0079] In the formula: P w is the bottom - hole flowing pressure of the oil well, MPa; P H is the bottom - hole flowing pressure of the water injection well, MPa; R is the injection - production well spacing, m; r w is the wellbore radius, m; dp / dr: the radial pressure gradient of the oil well, MPa / m; pe is the pressure at the oil - supply radius, MPa; re is the supply - edge radius, m; A is the radial seepage area, m 2 ; Q is the flow rate: m 3 / s; K is the reservoir permeability; h: the reservoir thickness, m. dp / dr: the radial pressure gradient of the oil well, MPa / m; pe is the pressure at the oil - supply radius, MPa; re is the supply - edge radius, m; A is the radial seepage area, m 2; Q is the flow rate: m 3 / s; K is the reservoir permeability; h: the reservoir thickness, m

[0080] If the oil is to flow at the midpoint of the main streamline, the driving pressure gradient at this point must be greater than the starting pressure gradient. Then, the limit injection-production well spacing at different injection-production pressure differences under a certain permeability condition can be calculated, that is:

[0081]

[0082] Assume that the effective injection-production pressure difference is 25 MPa, ignoring the wellbore radius, and use the average true starting pressure gradient in different permeability intervals and different states to calculate the limit distance s of fluid flow. The calculation results are as Figure 2 shown.

[0083] Table 2 Relationship between displacement distance and permeability

[0084]

[0085] In a specific embodiment, taking the wellhead pressure of the injection well as 18 MPa as the standard, the well depth is 2400 m, and the bottom hole pressure of the well is 38 MPa. In the actual oilfield exploitation, the bottom hole pressure of the production well is between 12 and 15 MPa. Therefore, the pressure difference in actual exploitation is close to 23 - 26 MPa. From Table 2 and Figure 2 it can be seen that: calculated with a displacement pressure difference of 23 MPa, the effective displacement distances corresponding to 5 mD, 2 mD, and 1 mD reservoirs are 610 m, 239 m, and 118 m respectively; calculated with a displacement pressure difference of 26 MPa, the effective displacement distances corresponding to 5 mD, 2 mD, and 1 mD reservoirs are 690 m, 271 m, and 133 m respectively.

[0086] The present invention takes a certain oilfield in Yitong Basin as an example to implement on typical rock samples. The experimental results are as Figures 1 to 2 shown in Tables 1 - 27.

[0087] Based on the fine zoning of the reservoir, the change of remaining oil in different regions is studied, and the remaining oil dynamics in different regions is analyzed. As Figure 7 shown is the remaining oil dynamic change diagram of 11 selected study areas. It can be seen from the figure that there are obviously more remaining oils in this area. In areas 1, 2, 3, 6, and 11, the remaining oil shows a stable downward trend and the production rate is good, which proves that wells such as Y59 - 6 - 8 and Y59 - 8 - 10 in this area can maintain the existing working system. While in areas 13, 14, 15, 18, 19, and 20, there are more remaining oils, and it is necessary to adopt work system adjustment methods such as perforating and fracturing for wells 0019 and 0010 in this area, or measures such as well pattern densification to improve the recovery factor.

[0088] (1) Figure 1Give the relationship between the starting pressure gradient and permeability of the target reservoir. From Figure 1 It can be seen that there is a good negative correlation between the true starting pressure gradient, the pseudo starting pressure gradient and the core permeability; the pseudo starting pressure gradient is 2.3 times that of the true starting pressure gradient; the starting pressure gradients corresponding to core permeabilities of 5.07 mD, 3.13 mD, 1.20 mD and 0.53 mD are 0.0087, 0.0210, 0.0970 and 0.2642 MPa / m, respectively.

[0089] (2) In a specific embodiment, taking the wellhead pressure of the injection well as 18 MPa as the standard, the well depth is 2400 m, and the bottom hole pressure of the well is 38 MPa. In the actual oilfield exploitation, the bottom hole pressure of the production well is between 12 and 15 MPa. Therefore, the pressure difference in actual exploitation is close to 23 - 26 MPa. From Table 2 and Figure 2 It can be seen that: calculated with a displacement pressure difference of 23 MPa, the effective displacement distances corresponding to 5 mD, 2 mD and 1 mD reservoirs are 610 m, 239 m and 118 m, respectively; calculated with a displacement pressure difference of 26 MPa, the effective displacement distances corresponding to 5 mD, 2 mD and 1 mD reservoirs are 690 m, 271 m and 133 m, respectively.

[0090] The above - described embodiments are only the preferred embodiments of the present invention, rather than all the feasible embodiments of the present invention. For those of ordinary skill in the art, any obvious changes made without departing from the principle and spirit of the present invention should be considered to be included within the protection scope of the claims of the present invention.

Claims

1. A method for dynamically evaluating residual oil in a CO2-water flooding reservoir, characterized in that, The steps are as follows: S1. Apply Petrel software to establish a fine three-dimensional geological model for the study area; S2. Use the PVTi module of Eclipse to fit the PVT experimental data of the fluid; S3. On the basis of the established fine three-dimensional geological model, sort out the well history data of the production wells, so as to establish a numerical simulation model of reservoir component for the study area; S4. Conduct history matching on the production data; S5. Divide the reservoir into zones in combination with the actual development situation of the reservoir; S6. Calculate the remaining oil reserves of the reservoir in different regions at different times respectively, and make a trend chart; S7. When the local recovery rate of a key area is lower than the average recovery rate of the reservoir, there is more remaining oil in this area. Therefore, it can be used as a key area for secondary subdivision of the reservoir, and the remaining oil in different regions can be studied dynamically and in detail, so as to clarify the distribution and dynamic changes of the remaining oil between wells, laying a foundation for the formulation of the next production increase measures.

2. The method for dynamically evaluating residual oil in a CO2-water flooding reservoir according to claim 1, characterized in that, The specific content of step S1 is as follows: ① Based on the fracture system and geological stratification, establish a three-dimensional fault model and a stratigraphic framework model; ② According to the sandstone thickness and sand-to-shale ratio distribution characteristics, draw a trend plan of sand body development probability, and establish a lithofacies model by constraint; ③ In the sandstone and mudstone facies, adopt a hierarchical facies control method to simulate the reservoir property model; ④ Based on the understanding of the oil-water distribution characteristics, conduct reserve fitting layer by layer and zone by zone, and verify the geological model by multiple methods.

3. The method for dynamically evaluating residual oil in a CO2-water flooding reservoir according to claim 1, characterized in that, The grid accuracy of the fine three-dimensional geological model in step S1 is: the plane grid size shall not be greater than 20m×20m, and the longitudinal grid height shall not exceed 1m.

4. The method for dynamically evaluating residual oil in a CO2-water flooding reservoir according to claim 1, characterized in that, In the fitting of step S2, CO2 needs to be regarded as a separate component, and in terms of the fitting results, the fitting errors of various indicators such as liquid phase viscosity and relative volume should be within 10%.

5. The method for dynamically evaluating residual oil in a CO2-water flooding reservoir according to claim 1, characterized in that, Step S3 is to fully simulate the influence of interlayer crossflow of multi-layer combined production wells and crossflow between wells caused by the existence of fractures on numerical simulation, and it is necessary to consider measures such as perforation and fracturing.

6. The method for dynamically evaluating residual oil in a CO2-water flooding reservoir according to claim 1, characterized in that, In the fitting of step S4, the error between the measured cumulative oil production of the oilfield and the cumulative oil production calculated by the model shall not be greater than 2%, the error between the measured production of a single well and the production calculated by the model shall not be greater than 10%, and the fitting error of the water cut of a single well shall not be greater than 10%.

7. The method for dynamically evaluating residual oil in a CO2-water flooding reservoir according to claim 1, characterized in that, The specific content of step S5 is: divide the block equally in area flooding, and divide different regions of the reservoir according to the structural situation of the formation in gravity flooding.

8. The method for dynamically evaluating residual oil in a CO2-water flooding reservoir according to claim 1, characterized in that, The specific content of step S6 is: combine measures such as water injection, perforation, gas injection, and well pattern infilling in the development process to analyze the change trend of the remaining oil, and clarify the adaptability of different regions under different production increase measures; here, it is necessary to observe the change trend of the remaining oil reserves. If the decline rate of the remaining oil is small before the production increase measures, while the decline rate of the remaining oil is large after the production increase measures, and the oil production increases significantly, it proves that the production increase measures are well adapted to this area, otherwise it proves poor adaptability.

Images