Experimental comprehensive evaluation method for sealing effect of carbon dioxide oil reservoir

Abstract

The invention belongs to the technical field of CO2 geological sequestration experiment evaluation in a CCUS-EOR project, and particularly relates to a carbon dioxide reservoir sequestration effect experiment comprehensive evaluation method. The method comprises the following steps: carrying out a carbon dioxide displacement saturated oil-water rock core experiment, simulating an actual oil reservoir CO2 injection and geological storage process, and calculating a storage evaluation index of CO2 in an experiment simulated oil reservoir on a rock core scale in combination with experimental test data; and quantitatively evaluating the carbon dioxide reservoir storage effect of the target reservoir under the corresponding working conditions by using the core scale CO2 storage index. The technical problem that a CO2 storage experiment method and a storage index quantitative evaluation method for oil reservoirs in the later stage of water flooding development are lacked at present is solved.

Description

TECHNICAL FIELD

[0001] The present application belongs to the field of CO2 geological storage experimental evaluation in CCUS-EOR projects, and particularly relates to a comprehensive evaluation method for CO2 reservoir storage effect experiment. BACKGROUND

[0002] With the increasing seriousness of global climate change, CO2 emission control and reduction technology has become the focus of global attention. Carbon capture, utilization and storage (CCUS) technology, as an important emission reduction means, has been widely studied and applied. Among them, CO2 geological storage technology is an important part of CCUS, which aims to store the captured CO2 in underground formations for a long time, so as to reduce the concentration of CO2 in the atmosphere and alleviate the greenhouse effect. In the CO2 geological storage technology, oil reservoirs, as a potential CO2 storage site, have attracted widespread attention due to their large storage space and good sealing properties. Especially for depleted oil reservoirs in the late stage of water flooding development, their utilization value is greater. Using depleted oil reservoirs to store CO2 not only effectively utilizes the remaining pore space, but also realizes long-term storage of CO2 and reduces its emission into the atmosphere. At the same time, the injection of CO2 can also be used to improve the recovery efficiency of oilfields. Therefore, the storage of CO2 in depleted oil reservoirs has dual benefits, i.e., both CO2 emission reduction and further improvement of oilfield recovery efficiency.

[0003] Although the storage of CO2 in depleted oil reservoirs has significant advantages, in the actual application process, it still faces a series of technical challenges and uncertainty factors. CO2 storage capacity and storage efficiency are important indicators for evaluating the storage capacity of geological structures. Accurate evaluation of CO2 storage capacity and storage efficiency of geological structures, and clear understanding of the main control factors and influence law of CO2 storage indicators, are of great significance to the key technology reserve and development of CO2 storage projects, the optimization design of CO2-EOR schemes, the engineering and economic feasibility analysis of CO2 storage projects, etc. However, at present, there are relatively few indoor physical simulation experiments and evaluation methods for the storage of CO2 in oil reservoirs, and the influence law of possible geological and engineering factors on CO2 storage indicators is not clear. In particular, the experimental quantitative analysis of CO2 storage capacity, storage capacity and storage efficiency, and the understanding of the main control factors and influence law of CO2 storage indicators are still relatively lacking. These deficiencies limit our comprehensive understanding and optimization of the CO2 storage process. In practical applications, there is a lack of a comprehensive experimental evaluation method that can fully and accurately simulate and evaluate various CO2 storage indicators in oil reservoirs. Therefore, it is urgent to establish an indoor physical simulation experiment and comprehensive evaluation method suitable for the storage of CO2 in oil reservoirs from the mechanism of CO2 storage, so as to provide a scientific basis for further technological development and application.

[0004] This invention addresses the shortcomings of existing technologies by proposing a method for indoor physical simulation experiments and comprehensive evaluation of CO2 storage in oil reservoirs. This method establishes experimental and data analysis methods for CO2 storage in oil reservoirs. Through experiments simulating the injection process of CO2 in oil reservoirs at different water-drive stages, and based on the experimental test results, employs reliable data analysis and processing techniques to comprehensively evaluate the experimental data. It quantitatively analyzes various storage indicators for CO2 in depleted oil reservoirs, forming a comprehensive experimental evaluation technique for CO2 storage in oil reservoirs. This provides more comprehensive guidance and support for understanding the CO2 storage mechanism, assessing the feasibility of storage projects, and estimating storage indicators during the project operation phase. Summary of the Invention

[0005] To address the shortcomings of existing technologies, this invention provides an indoor physical simulation experiment and comprehensive evaluation method for CO2 storage in oil reservoirs. This method aims to solve the current problem of lacking experimental methods for CO2 storage in reservoirs during the later stages of waterflooding development, as well as quantitative evaluation methods for storage indicators.

[0006] This invention discloses a comprehensive evaluation method for the effectiveness of carbon dioxide reservoir storage, the method of which is as follows: Under different conditions, carbon dioxide displacement saturated oil-water core experiments were carried out to simulate the CO2 sequestration process of actual oil reservoirs. Based on the experimental test data, the core-scale CO2 sequestration index of the simulated oil reservoir was calculated. The core-scale CO2 sequestration index includes: core-scale physical limit sequestration capacity. σ c Core-scale structural preservation capacity σ c,1 Core-scale dissolution and preservation capacity σ c,2 Core-scale storage efficiency η Core-scale storage efficiency factor ζ Contribution of core-scale structural preservation α stru and the contribution ratio of core-scale dissolution and sequestration β diss ; The above-mentioned core-scale CO2 sequestration indices were used to evaluate the CO2 reservoir sequestration effect of the target reservoir under corresponding conditions. The different conditions are: different initial water saturation states, different injection rates, different injection pressures, and different experimental temperatures.

[0007] Preferably, the physical limit of core-scale sequestration capacity σ c The calculation formula is as follows: ; in, σc For the physical limit of core-scale sequestration capacity, cm 3 ; R fo,lab The final oil displacement efficiency of the core sample is % R fw,lab The final water displacement efficiency of the core sample is % C CO2-Oil The experiment simulated the solubility and mole fraction of CO2 in crude oil under simulated temperature and pressure conditions. C CO2-Water The solubility and mole fraction of CO2 in water were calculated to simulate the temperature and pressure conditions used in the experiment. L Core length ， cm; r Core radius ， cm; σ Core porosity, %.

[0008] Preferably, core-scale structural preservation capacity σ c,1 The calculation formula is as follows: ; in, σ c,1 For core-scale structural preservation capacity, cm 3 ; S wi The initial water saturation of the core, %.

[0009] Preferably, core-scale dissolution and preservation capacity σ c,2 The calculation formula is as follows: ; in, σ c,2 For core-scale dissolution and sequestration capacity, cm 3 ; S oi The initial oil saturation of the core is %.

[0010] Preferably, core-scale storage efficiency σ The calculation formula is as follows: ; in, σ For the final storage efficiency, % V p The pore volume of the rock sample is expressed in cm³. 3 ; S g,max This represents the maximum gas saturation of the core at the end of gas drive, in percentages.

[0011] Preferably, the core-scale storage efficiency factor σ The calculation formula is as follows: ; in, σ The sealing efficiency factor is dimensionless.

[0012] Preferably, the contribution ratio of core-scale structural preservation α stru The calculation formula is as follows: ; in, α stru The proportion of contribution to core-scale structural preservation.

[0013] Preferably, the contribution ratio of core-scale dissolution and sequestration β diss The calculation formula is as follows: ; in: β diss Contribution to core-scale structural preservation, % When CO2 injection ends, the oil displacement efficiency at that moment will be calculated. E o,CO2 and water displacement efficiency E w,CO2 These are respectively denoted as the final oil displacement efficiency of the core. R fo,lab and the final water displacement efficiency of the core R fw,lab .

[0014] Preferably, the final oil displacement efficiency of the core R fo,lab and the final water displacement efficiency of the core R fw,lab The following method is used to obtain it: Based on experimental test data, the residual water saturation, residual oil saturation, oil displacement efficiency, and water displacement efficiency were calculated after CO2 displacement of the core sample. Residual oil saturation S or The expression is as follows: ; Residual water saturation Swr The expression is as follows: ; In the formula: S or The residual oil saturation after CO2 displacement is % (%). S wr The residual water saturation after CO2 displacement is % (%). m oi Initial water-bearing conditions of the core S wi The oil content below, in grams; m wi Initial water-bearing conditions of the core S wi The water content below, in grams; m o,out The mass of oil produced by CO2 displacement is expressed in grams. m w,out The mass of water produced by CO2 displacement is expressed in grams. A The area of ​​the core end face, in cm² 2 ; L The length of the rock core is in cm. σ The core porosity is %; σ o The density of crude oil at room temperature, in g / cm³ 3 ; σ w Density of formation water at room temperature, in g / cm³ 3 ; r The radius of the core is in cm; At the end of CO2 displacement of oil and water, the maximum gas saturation in the core is the sum of the losses of the initial oil saturation and the initial water saturation. The mass of produced oil and produced water is obtained according to the law of conservation of mass. The total mass and total volume of produced oil and produced water can be expressed by the following formula: ; In the formula: V w,out The volume of water produced is expressed in cm. 3 ; V o,out The volume of oil produced is expressed in cm. 3 ; mow,out The mass of the total oil and water produced after CO2 displacement is expressed in grams. V ow,out The total volume of oil and water produced after CO2 displacement is expressed in cm³. 3 ; The volumes of produced oil and water are expressed as follows: ; Based on the densities of oil and water under surface conditions, and combined with the volumes of produced oil and water, the masses of produced oil and water can be calculated separately, as shown in the following expressions: ; Therefore, the maximum gas saturation of the core at the end of gas drive S g,max Calculated by the following formula: ; In the formula: S g,max The maximum gas saturation of the core at the end of gas drive, % The CO2 injection process displaces oil and water, achieving an oil displacement efficiency of [missing information]. E o,CO2 (%) and water displacement efficiency E w,CO2 (%) can be calculated using the following formula: ; In the formula: E w,CO2 For water displacement efficiency, % E o,CO2 For oil displacement efficiency, %. Based on the above, the final oil displacement efficiency of the core sample can be obtained. R fo,lab and the final water displacement efficiency of the core R fw,lab .

[0015] Preferably, the initial water saturation of the core S wi Compared with the initial oil saturation of the core S oi The calculation formula is as follows: ;

[0016] In the formula: S wi The initial water saturation of the core, % m i For the first iOil and water core mass (g) under the oil-water injection volume flow rate ratio; m 0 represents the dry core mass, in grams; σ o To simulate the density of oil at the measurement temperature, g / cm³ 3 ; σ w The density of simulated formation water in saturated core samples at the measured temperature, in g / cm³. 3 ; S oi The initial oil saturation of the core, in %. Evaluation method. The technical advantages of this invention are as follows: (1) The indoor physical simulation experiment and comprehensive evaluation method for CO2 storage in reservoirs provided by this invention simulates the injection process of CO2 in reservoirs during the later stages of waterflood development, and realistically simulates the storage behavior of CO2 under different reservoir and injection conditions. This method can systematically and quantitatively analyze various storage indicators of CO2 in depleted reservoirs, explore the main controlling factors of CO2 storage and their influencing laws, deepen the understanding of CO2 storage mechanism, and provide solid theoretical support for optimizing storage strategies.

[0017] (2) The method provided by the present invention can accurately assess the amount and efficiency of CO2 storage and help technicians identify the geological and engineering factors that affect the storage effect, thereby effectively reducing the geological and engineering risks in the CO2 storage process and ensuring the safety and stability of the storage process.

[0018] (3) The method of the present invention can not only provide guidance for the actual operation of CO2 storage projects and help analyze and optimize various storage indicators in the storage process, but also effectively support the demonstration of storage projects and improve the overall reliability and storage benefits of the projects. Attached Figure Description

[0019] σ This is a technical roadmap of the method in the embodiments.

[0020] σ This is a flowchart of the experiment.

[0021] σ The solubility of CO2 in crude oil varies with pressure at different temperatures.

[0022] σ The solubility of CO2 in crude oil varies with temperature under different pressures.

[0023] σ The solubility of CO2 in formation water varies with pressure at different temperatures.

[0024] σ The solubility of CO2 in the formation varies with temperature under different pressures.

[0025] σ The solubility of CO2 in water-containing crude oil varies with temperature under different water saturation levels.

[0026] σ The solubility of CO2 in water-containing crude oil varies with pressure at different water saturation levels.

[0027] σ The variation of gas saturation with CO2 injection pore volume ratio (PV number) under different initial water saturation conditions.

[0028] σ The variation of water efficiency with injected PV number in oil displacement of long cores under different initial water saturation conditions.

[0029] σ The calculation results of various CO2 sequestration indices under different initial water saturation conditions.

[0030] σ The variation of oil displacement efficiency with CO2 injection pore volume ratio (PV number) at different injection rates.

[0031] σ The calculation results of various CO2 sequestration indicators under different injection rates are presented.

[0032] σ The variation of oil displacement efficiency with CO2 injection pore volume ratio (PV number) under different injection pressure conditions.

[0033] σ The calculation results of various CO2 sequestration indicators under different injection pressure conditions.

[0034] σ The variation of oil displacement efficiency with CO2 injection pore volume ratio (PV number) under different temperature conditions.

[0035] σ The calculation results are for various CO2 sequestration indices under different temperature conditions. Detailed Implementation

[0036] The present invention will be described below with reference to the accompanying drawings.

[0037] The specific embodiments of the present invention are described below to enable those skilled in the art to understand the present invention. However, it should be understood that the present invention is not limited to the scope of the specific embodiments. For those skilled in the art, various changes are obvious as long as they are within the spirit and scope of the present invention as defined and determined by the appended claims. All inventions utilizing the concept of the present invention are protected.

[0038] S1. Analyze the reservoir and fluid characteristics of the target area, test the basic physical parameters of the obtained core samples, screen the core samples, and prepare the formation fluids.

[0039] S1-1. After core sampling from the target area, the obtained core samples undergo basic physical property testing, including the determination of key parameters such as porosity, permeability, and density.

[0040] Laboratory measurements allow us to understand the physical structure and reservoir conditions of the core samples. The test results of all core physical properties (Table 1) show that the porosity of the core samples in the study area is mainly concentrated between 3% and 10%, with an average of 6.02%; the gas permeability ranges from 0.02 to 3 mD, with an average of 0.94 mD.

[0041] Table 1. Results of core porosity and permeability parameter tests

[0042] S1-2. Screen core samples and select representative samples for further research.

[0043] Based on the test results of the basic physical properties of the S1-1 core, and considering the distribution range of core porosity and permeability, rock integrity, and the presence of microfractures, suitable samples were selected to compose long cores to better represent the actual situation of the reservoir. These cores were then used to simulate CO2 displacement of oil and water flow. The composition and basic physical properties of the long cores after selection are shown in Table 2.

[0044] Table 2 Composition and basic physical properties of long core samples

[0045] S1-3. Analyze the high-pressure physical property test results and configure the formation fluid based on the characteristics of the formation fluid in the study area.

[0046] High-pressure physical property testing data for crude oil and formation water indicate that, under surface conditions, the crude oil has a density of 0.85 g / cm³, a viscosity of 9 mPa·s, and a pour point of 22℃, classifying it as a light, medium-viscosity conventional crude oil. Under formation conditions, high-pressure physical property testing shows that the crude oil has a density of 0.798 g / cm³, a viscosity of 2.50 mPa·s, a volume factor of 1.122, and an initial gas-oil ratio of 36.47 m³ / t. Chemical analysis of the formation water shows a chloride ion content of 16926.7 mg / L and a total salinity of 20161.2 mg / L, classifying it as CaCl₂ water.

[0047] Before the experiment, a simulated oil was prepared by mixing degassed crude oil and kerosene, with a viscosity of 9 mPa·s; the injected gas was 99.99% pure CO2 gas.

[0048] S2. Establish a physical simulation experimental method for CO2 storage in reservoirs during the later stages of water-drive development.

[0049] Furthermore, in step S2, establishing a physical simulation experimental method for CO2 storage in reservoirs during the later stages of waterflood development includes the following steps: S21. Under reservoir temperature and pressure, establish the core bound water saturation state for oil-driven water and calculate the core bound water saturation.

[0050] First, saturate the rock sample with water, weigh it, and calculate the pore volume of the rock sample. V p Then, an oil-water displacement experiment was conducted at a low flow rate (typically 0.1 mL / min), gradually increasing the displacement rate until no more water was displaced. The volume of water displaced from the rock was recorded. V w Calculate the bound water saturation using the following formula ( S wc This refers to the water saturation level in rock pores that cannot be displaced. The formula is as follows: (1) In the formula: S wc To bind water saturation, % V p The pore volume of the rock sample is expressed in cm³. 3 ; V w The volume of water displaced is expressed in mL.

[0051] S22. Construct the initial water-bearing state of the core and simulate the water-bearing conditions of the reservoir at different stages of water drive development.

[0052] Simulated oil and formation water were injected into a clean core at the ratios shown in Table 3, with the total flow rate remaining constant. Once the pressure difference between the inlet and outlet stabilized and the oil and water flow rates at the outlet ceased to change, the oil and water saturation state of the core gradually stabilized, and the initial oil and water saturation was calculated. This cyclic experiment can construct different initial water-bearing states of the core, i.e., construct different initial water saturation levels of the core. S wi ) and oil saturation ( S oi ).

[0053] Table 3. Oil-water injection volumetric flow rate ratio at the core injection end

[0054] The water saturation is calculated using the gravimetric method, and the formula is as follows: (2) (3) In the formula: S wi The initial water saturation of the core, % m i For the first i Oil and water core mass (g) under the oil-water injection volume flow rate ratio; m 0 represents the dry core mass, in grams; σ o To simulate the density of oil at the measurement temperature, g / cm³ 3 ; σ w The density of simulated formation water in saturated core samples at the measured temperature, in g / cm³. 3 ; S oi The initial oil saturation of the core is %.

[0055] S3. Under different conditions, CO2 displacement experiments were conducted in the core to simulate the CO2 sequestration process in actual oil reservoirs.

[0056] Different experimental conditions were implemented, including four factors: different initial water saturation, different injection rates, different injection pressures, and different experimental temperatures. The gas-driven control group experiment was repeated, and the experimental control group design is as follows (Table 4): Table 4 Experimental control group setup

[0057] After establishing bound water saturation through oil-driven water injection and obtaining the bound water saturation of the core sample using a gravimetric method, the core sample needs to be washed with oil to restore it to its initial clean state. Specifically, petroleum ether is injected into the core sample at a low speed for washing until the effluent is colorless and transparent. The core sample is then placed in a fume hood to allow the petroleum ether to completely evaporate. Finally, the core sample is dried in an oven at 80°C to ensure it is completely dry for subsequent gas-driven experiments.

[0058] Simulated oil and formation water were injected into a clean core at a certain flow rate ratio while maintaining a constant total flow rate. Once the pressure difference between the inlet and outlet stabilized and the oil and water flow rates at the outlet no longer changed, the oil-water saturation state of the core gradually stabilized. The criteria for judging stability are twofold: 1) Requirements for injection volume: The volume of each fluid (whether oil or water) injected must be at least three times the pore volume of the rock sample; 2) Requirements for pressure difference stability: During the experiment, the pressure difference across the rock sample needs to be continuously monitored. Once the injected fluid reaches the specified volume, the pressure difference across the rock sample should remain stable and no longer change significantly. This condition indicates that the fluid flow in the rock sample has reached a steady state.

[0059] When constructing cores with different initial water saturation, the cores need to be injected according to the oil-water volume flow ratio designed in Table 3. After the pressure difference flow rate stabilizes, the initial water saturation and initial oil saturation of the cores are calculated by weighing.

[0060] During the experiment, once the displacement reaches a point where no more fluid is produced and the pressure differential stabilizes, the residual fluid state of the core is considered reached, and gas injection is stopped. The residual water and oil saturation of the core is then calculated using a weighing method. After the gas drive experiment concludes and the core is washed and oil production is restored, the next round of displacement begins. During the experiment, experimental data such as injection pressure, temperature, injection flow rate, total mass and volume of produced oil and water must be recorded.

[0061] S4. Based on experimental test data, calculate the residual water saturation, residual oil saturation, oil displacement efficiency, and water displacement efficiency after CO2 displacement.

[0062] Based on the total mass and volume of produced oil and water recorded in experiments with different CO2 injection PV numbers, the residual oil saturation was calculated using formulas (4) and (5), respectively. S or ) and residual water saturation ( S wr ), and then the maximum gas saturation of the core at the end of gas drive is calculated using formula (9). S g,max ): (4) (5) In the formula: S or The residual oil saturation after CO2 displacement is % (%). S wr The residual water saturation after CO2 displacement is % (%). m oi Initial water-bearing conditions of the core S wi The oil content below, in grams; m wi Initial water-bearing conditions of the core S wi The water content below, in grams; m o,out The mass of oil produced by CO2 displacement is expressed in grams. m w,out The mass of water produced by CO2 displacement is expressed in grams. A The area of ​​the core end face, in cm² 2 ; L The length of the rock core is in cm. σ The core porosity is %; σ o The density of crude oil at room temperature, in g / cm³ 3 ; σ w Density of formation water at room temperature, in g / cm³ 3 ; r denoted as the core radius, in cm.

[0063] At the end of CO2 displacement of oil and water, the maximum gas saturation in the core is the sum of the initial oil and water saturation losses. The mass of produced oil and water can be determined using the law of conservation of mass. The total mass and volume of produced oil and water can be expressed by the following formula: (6) In the formula: V w,out The volume of water produced is expressed in cm. 3 ; V o,out The volume of oil produced is expressed in cm. 3 ; m ow,out The mass of the total oil and water produced after CO2 displacement is expressed in grams. V ow,out The total volume of oil and water produced after CO2 displacement is expressed in cm³. 3 .

[0064] Furthermore, the formulas for the produced oil and water volumes can be derived from formula (6), as follows: (7) Furthermore, based on the densities of oil and water under surface conditions, and combined with the volumes of produced oil and water, the masses of produced oil and water can be calculated separately, as shown in the following expressions: (8) Therefore, the maximum gas saturation of the core at the end of gas drive ( S g,max The following formula can be used to calculate: (9) In the formula: S g,max This represents the maximum gas saturation of the core at the end of gas drive, in percentages.

[0065] After CO2 displacement is completed, the final oil displacement efficiency achieved by the displacement process E o,CO2 (%) and final water displacement efficiency E w,CO2 (%) can be calculated using the following formula: (10) In the formula: E w,CO2 For water displacement efficiency, % E o,CO2 The oil displacement efficiency is expressed as %, and the oil displacement efficiency and water displacement efficiency at the final moment are recorded as the final oil displacement efficiency of the core at the end of the entire process of CO2 displacement of saturated oil and water core. R fo,lab (%) and final water displacement efficiency of core R fw,lab (%) The above establishes a physical simulation experimental method for CO2 storage in reservoirs during the later stages of water-drive development, as well as a method for processing experimental data.

[0066] S5. Investigate and analyze existing formulas for calculating the solubility of CO2 in crude oil, water, and water-containing crude oil, and select the formula suitable for the target area conditions. The specific steps are as follows: S5-1. The existing formulas for calculating the solubility of CO2 in crude oil, water and water-containing crude oil were investigated and analyzed.

[0067] After CO2 is injected into an oil reservoir, its dissolution behavior must be fully considered. According to the mechanism of CO2 dissolution and sequestration, CO2 partially dissolves in formation water and partially dissolves in crude oil. Previous studies have shown that the amount of CO2 sequestered in dissolved form constitutes a significant portion and is of considerable importance. When calculating this sequestered portion, the two most critical parameters are the solubility of CO2 in water-bearing crude oil and formation water. Therefore, when mathematically modeling the CO2 sequestration problem in oil reservoirs, it is essential to reliably obtain the solubility of CO2 in these two media.

[0068] 1) Solubility of CO2 in crude oil Currently, many scholars have developed formulas for the solubility of CO2 in degassed, light, and heavy crude oils under different temperature and pressure conditions. Only a few scholars have established formulas for the solubility of CO2 in water-bearing crude oil under reservoir conditions. See Table 5 for the applicable conditions of commonly used crude oil solubility calculation formulas.

[0069] Table 5 Applicable Conditions for Commonly Used Crude Oil Solubility Calculation Formulas

[0070] In practical calculations, it is necessary to select an appropriate formula based on the actual temperature and pressure conditions of the reservoir. Table 5 lists the commonly used formulas for calculating crude oil solubility as follows: ① Mehrotra (1982) model In 1982, Mehrotra et al. studied the solubility of CO2 in asphaltene crude oil and established a correlation equation, as shown below: (11) In the formula: R s The solubility of CO2 in crude oil, in cm. 3 / cm 3 ; P Pressure, MPa; T Temperature, K; b 1. b 2. b 3. b 4 represents the model fit coefficient. b 1 = -0.0073508; b 2 = -14.794; b 3 = 6428.5; b 4 = 4871.39.

[0071] ② Frank Chung (1988) model In 1988, Frank Chung et al. studied the solubility of CO2 in heavy oil and established a correlation that considered not only temperature and pressure but also the relative density of the crude oil. The expression is as follows: (12) In the formula: R s m represents the solubility of CO2 in crude oil. 3 / m 3 ; σ The relative density of crude oil; T Temperature, °F; PFor pressure, Psia; a 1. a 2. a 3. a 4. a 5. a 6. a 7 represents the model fit coefficient. a 1 = 0.4934 × 10 -2 ; a 2 = 4.0928; a 3 = 0.571 × 10 -6 ; a 4 = 1.6428; a 5 = 0.6763 × 10 -3 ; a 6 = 781.334; a 7 = -0.2499.

[0072] ③ Taylor Barclay (2016) model In 2016, Taylor Barclay et al. modeled the solubility of CO2 in light crude oil using Emera data. The model expression is as follows: (13) In the formula: R s f represents the solubility of CO2 in crude oil. T Temperature, °C; P The pressure is expressed in Pa; a, b, c, and d are model fitting coefficients. a =0.36913, b =-0.00106, c =0.01280, d =-0.00160 ④ Mehrotra & Svrcek (1982) model In 1982, Mehrotra and Svrcek developed a four-parameter empirical model for predicting CO2 solubility in light degassed crude oil (crude oil without dissolved gases). The model considers the effects of temperature and crude oil saturation pressure on solubility, and the expression is as follows: (14) In the formula: R s m represents the solubility of CO2 in crude oil. 3 / m 3 ; T Temperature, °C; P s The pressure is the saturation pressure of crude oil, in MPa.

[0073] ⑤ Chung (2012) model In 2012, Chung et al. developed a predictive model for CO2 solubility in heavy and degassed crude oils. This model considers the specific gravity of the oil and the effects of crude oil saturation pressure and temperature. The expression is as follows: (15) In the formula: R s m represents the solubility of CO2 in crude oil. 3 / m 3 ; σ The relative density of crude oil; T Temperature, °C; P s The pressure is the saturation pressure of crude oil, in MPa.

[0074] For predicting the CO2 solubility in water-bearing crude oil under reservoir conditions, the current main method is a volume fraction weighted method, as shown in the following expression: (16) or (17) In the formula: R s This represents the solubility of CO2 in water-containing crude oil. R w This represents the solubility of CO2 in water. R o This refers to the solubility of CO2 in oil. X w f represents the volume fraction of water in water-containing crude oil. X o f is the volume fraction of oil in water-containing crude oil; The above formula is applicable to any volume fraction of water-containing crude oil and under any temperature and pressure conditions. The prerequisite for using this formula is that the solubility of CO2 in water and oil under specific temperature and pressure conditions must first be calculated separately. Then, the volume fraction weighted formula (Equation 16 or Equation 17) is used to calculate the solubility of CO2 in water-containing crude oil under the above conditions. The calculation results are as follows: σ , 8 As shown.

[0075] 2) Solubility of CO2 in formation water The solubility of CO2 in water is a function of temperature and pressure. By combining experimental studies, the amount of CO2 dissolved in water can be estimated. The solubility of CO2 in pure water increases with increasing pressure, and exhibits different trends with temperature variations across different temperature ranges. This invention uses the relationship proposed by Sun et al. in 2021 to predict the solubility of CO2 in pure water at different temperatures and pressures. The relationship proposed by the authors can predict the solubility of CO2 in pure water under typical geological conditions with a temperature range of 0–250℃ and a pressure range of 0–200 MPa. The model is an explicit expression with continuous derivatives, facilitating subsequent model applications.

[0076] Equation (18) is the main equation for predicting the solubility of CO2 in pure water. The equation expression is as follows: (18) in: (19) (20) In the formula: m CO2 ρ represents the solubility of CO2 in pure water, in mol / kg; P Pressure, MPa; T Temperature, °C; P sat is the saturated vapor pressure of water (the pressure at which water vapor reaches thermodynamic equilibrium with its condensed or liquid state; if the pressure is higher than this saturated pressure, the water vapor will condense or liquefy), MPa. The saturated vapor pressure of water varies at different temperatures. P 0 represents the pressure, in MPa, at which the trend of CO2 solubility changes abruptly. m C 'The solubility of CO2 in pure water is...' P The derivative at 0; C T1 - C T7 These are the modeling coefficients in the solubility prediction model for pure water.

[0077] The following combination of polynomials and logarithmic functions can be used to estimate the intermediate parameters of formula (18). C T1 - C T7 The expression is as follows: (twenty one) In the formula: x 1. x 2. x 3. x 4. x5 are all undetermined coefficients, see Table 6.

[0078] Table 6 Summary of modeling coefficients in the prediction model for CO2 solubility in pure water

[0079] The calculation steps are as follows: a. First, use equation (21) to estimate the intermediate parameters of equation (20). C T1 - C T7 ; b. Secondly, use equation (19) to calculate the pressure at which the trend of CO2 solubility changes abruptly at a specific temperature. P 0; c. Then, use equation (20) to calculate the solubility of CO2 in pure water. P The derivative at 0; d. Finally, by combining the calculation results of equations (19), (20), and (21), and selecting a suitable pressure range, and correctly substituting it into equation (18), the solubility of CO2 in pure water under specified temperature and pressure conditions can be calculated.

[0080] It should be noted that the saturated vapor pressure of water P sat The saturated vapor pressure of water varies with temperature, exhibiting an exponential growth relationship. It is only 0.61165 kPa at 0°C, but reaches 101.42 kPa at 100°C. The higher the temperature, the easier it is for water molecules to escape from the liquid into the gas phase, leading to a rapid increase in the water phase vapor pressure. P sat The values ​​can be obtained by looking up a table (see Table 7). Alternatively, they can be calculated using the following regression equation, as shown below: (twenty two) Table 7. Values ​​of saturated vapor pressure in the aqueous phase at different temperatures.

[0081] S5-2. Based on the reservoir and fluid characteristics data of the target area, select the most suitable CO2 solubility calculation formula for the target area temperature, pressure and fluid properties.

[0082] The target reservoir temperature is approximately 73℃, and the reservoir pressure is approximately 18 MPa. The crude oil is light crude oil. Therefore, the CO2 solubility model in light crude oil developed by Taylor Barclay et al. in 2016 can be used. This model can meet the requirements of the target area's temperature, pressure, and fluid properties. The results are as follows: σ and 4As shown. The solubility of CO2 in formation water can be calculated using the formula proposed by Sun et al. in 2021, and the results are as follows. σ and 6 As shown. The solubility in water-containing crude oil can be calculated using equation (16) or equation (17), and the results are as follows. σ and 8 As shown.

[0083] σ The solubility of CO2 in crude oil at different temperatures varies with pressure. It is clearly observed that the solubility of CO2 in crude oil continuously increases with increasing pressure. In the low-pressure range (0 to 10 MPa), the solubility increases rapidly, indicating that pressure has a significant effect on solubility. However, in the higher pressure range (above 20 MPa), the rate of increase in solubility begins to slow down. σ As shown, the solubility of CO2 in crude oil exhibits a linear decreasing trend with increasing temperature. This trend is evident under both low and high pressure conditions, indicating that the inhibitory effect of temperature on solubility is universally present.

[0084] σ The changes in CO2 solubility in formation water with pressure at different temperatures are shown. It can be observed that CO2 solubility gradually increases with increasing pressure, especially at lower pressures (less than 5 MPa), where the increase in solubility is more rapid. This indicates that the dissolution behavior of CO2 in water is more sensitive at low pressures. Lower temperatures contribute to increased CO2 solubility in water. σ This shows the variation of CO2 solubility in the formation with temperature under different pressures. It can be observed that different trends occur within different temperature ranges as temperature changes.

[0085] σ and 8 The data shows the change in CO2 solubility in water-containing crude oil with temperature and pressure. At the same temperature, the solubility of CO2 in water-containing crude oil increases with increasing pressure, while at the same pressure, the solubility of CO2 in water-containing crude oil decreases with increasing temperature. The higher the water saturation, the lower the solubility of CO2, especially under low pressure and low water content conditions, this trend is more pronounced.

[0086] S6. Establish a core-scale CO2 sequestration index evaluation model to form a systematic comprehensive evaluation method for CO2 reservoir sequestration effect.

[0087] Furthermore, in step S6, a core-scale CO2 sequestration index evaluation model is established to form a systematic comprehensive evaluation method for CO2 reservoir sequestration effectiveness, evaluating the sequestration effect of the target reservoir. A theoretical calculation model for key CO2 sequestration indices at the core-scale is established, including: physical limit sequestration capacity (PLC). σ c ), construction and storage capabilities ( σ c,1 Dissolution and sealing capabilities ( σ c,2 ), storage efficiency ( σ %), storage efficiency factor ( σ ), Contribution ratio of structural sequestration ( α stru %) and the contribution ratio of dissolution and sealing (%) β diss %).

[0088] Further: In step S6, a theoretical calculation model for key CO2 sequestration indices at the core-scale reservoir is established, including the following steps: S61, Deriving the physical limit of core-scale sequestration capacity ( σ c ).

[0089] The "physical limit of CO2 sequestration" at the core scale is defined as the reservoir's physical limit potential for CO2 sequestration under simulated reservoir conditions in core displacement experiments, taking into account factors such as reservoir characteristics, water cut, oil displacement efficiency, water displacement efficiency, and sequestration mechanisms (structural sequestration, residual sequestration, and dissolution sequestration). This indicator is denoted by the symbol "". σ c "This indicates the physical limit of core-scale sequestration capacity (" σ c The physical limit of core-scale sequestration capacity is calculated using the following formula: σ c ) based on core-scale tectonic sealing capacity ( σ c,1 ) and core-scale dissolution and sequestration capacity ( σ c,2 The above parameters are composed of the following: (twenty three) In the formula: σ c For the physical limit of core-scale sequestration capacity, cm 3 ; σ c,1 For core-scale structural preservation capacity, cm 3 ; σ c,2 For core-scale dissolution and sequestration capacity, cm3 .

[0090] Core-scale structural preservation capacity ( σ c,1 ): (twenty four) Core-scale dissolution and sequestration capacity ( σ c,2 ): (25) In the formula: σ c,1 For core-scale structural preservation capacity, cm 3 ; σ c,2 For core-scale dissolution and sequestration capacity, cm 3 .

[0091] Therefore, the physical limit of core-scale sequestration capacity ( σ c The result can be obtained by the following formula: (26) In the formula: R fo,lab , R fw,lab These represent the final oil displacement efficiency and final water displacement efficiency of the core samples, respectively, % . C CO2-Oil , C CO2-Water These represent the solubility, in mole fraction, of CO2 in crude oil and formation water under simulated formation temperature and pressure conditions.

[0092] S62, Deriving the sealing efficiency factor ( σ ): (27) In the formula: σ This is the storage efficiency factor, dimensionless. This parameter measures the effective utilization of the physical limit of the core's reservoir space by injected CO2, satisfying the condition 0 < 0. σ <1. If ζ is close to 1, it indicates a high level of effective utilization; if it is close to 0, the utilization level is low. This parameter is a dimensionless quantity, a comprehensive index of the dimensionless physical limit of core sequestration capacity, used to characterize the fluid storage capacity in the core, and is a key parameter reflecting the inherent characteristic of the physical limit of core sequestration capacity.

[0093] S63, Deriving the sealing efficiency ( σ %).

[0094] For core scale, storage efficiency ( σThe percentage (%) represents the ratio of the gas-bearing volume in the core pore space to the physical limit of gas sequestration capacity. Therefore, the final sequestration efficiency (%) is the ratio of the gas-bearing volume in the core pore space to the physical limit of gas sequestration capacity. σ %) can be expressed as the ratio of the maximum gas-bearing volume to the physical limit of sequestration capacity, and the expression is: (28) In the formula: σ For the final sealing efficiency, %. When equation (16) is used S g At that time, the storage efficiency at different gas injection stages ( σ %).

[0095] S64. Derive the contribution ratio of different types of core-scale sequestration, including the contribution ratio of tectonic sequestration at the core scale. α stru (%), contribution of core-scale dissolution and sequestration β diss (%).

[0096] Contribution of core-scale structural preservation α stru (%): (29) Contribution of core-scale dissolution and sequestration β diss (%): (30) In the formula: α stru Contribution to core-scale structural preservation, % β diss The proportion of contribution to core-scale structural preservation.

[0097] Furthermore: In step S6, a core-scale CO2 sequestration capacity and sequestration efficiency evaluation model was established. The prerequisite for using this model is the accurate measurement of the produced fluid volume and the calculation of the final oil displacement efficiency of CO2-driven saturated oil and water cores. R fo,lab %) and final water displacement efficiency (%) R fw,lab (%). When CO2 is used to displace saturated simulated crude oil and formation water cores, a breakthrough phenomenon is prone to occur. In the initial displacement stage, the flow rate of the produced fluid is relatively large, but the production gradually decreases as CO2 is continuously injected. It is necessary to wait until the injected gas displaces the oil and water to the produced end and no more crude oil and formation water are produced, and the pressure difference between the inlet and outlet ends reaches a stable state. At this point, the oil and water in the core can be considered to have reached a stable residual state.

[0098] Furthermore, in step S6, a core-scale CO2 sequestration capacity and sequestration efficiency evaluation model is established. When using it, it is necessary to determine the solubility of CO2 in water-bearing crude oil and water under the simulated formation temperature and pressure conditions. The solubility can usually be determined by selecting a commonly used formula that meets the requirements based on the target reservoir temperature, pressure and fluid properties.

[0099] The physical limit of CO2 sequestration capacity and sequestration efficiency factor at the core scale are calculated according to formulas (26) and (27), respectively. The sequestration efficiency is calculated using formula (28).

[0100] Based on the experimental results under different conditions, the established mathematical model is used for calculation and analysis to conduct an in-depth study on the CO2 sequestration mechanism in the reservoir under different conditions.

[0101] Based on the designed oil-water volumetric flow rate ratio in Table 3, oil and water were simultaneously injected into the long core to establish different water saturation states. Then, CO2 displacement of oil and water seepage experiments were conducted. Based on the experimental results, the curves showing the change in gas saturation (sealed gas) with CO2 injection PV number were calculated and plotted, as shown below. σ As shown. The variation of water efficiency with injected PV number in oil displacement of long cores under different initial water saturation conditions, such as... σ As shown.

[0102] Based on the experimental results, the storage index parameters under different initial water saturation were obtained using formulas (23) to (30), such as σ As shown.

[0103] Experiments revealed that under high water cut conditions, cores exhibited higher overall oil-water displacement efficiency and greater gas saturation (or CO2 storage space). Furthermore, cores with good physical properties, under the same initial water cut conditions, showed higher CO2 displacement efficiency and final gas saturation (e.g., ...). σ ,like σ Analysis suggests that when water saturation decreases, i.e., crude oil saturation increases, CO2 seepage is more severely hindered by the viscosity of oil and water, making fingering less likely. The CO2 displacement front is more likely to maintain near-uniform advancement, resulting in higher oil and water displacement efficiency.

[0104] Depend on σ It can be seen that water has a significantly higher flow capacity than crude oil. Therefore, the higher the initial water saturation, the more efficient CO2 can be in displacing water, replacing more storage space. This is more conducive to improving the structural storage contribution rate and physical limit storage capacity. However, a higher initial water saturation will result in a lower oil saturation after CO2 displacement. CO2 has a much higher solubility in crude oil than in brine, which will lead to a certain reduction in the total dissolved storage ratio.

[0105] The curves showing the change in oil displacement efficiency with CO2 injection PV number at different injection rates (0.3 ml / min, 0.7 ml / min, and 1.1 ml / min) are shown below. σ As shown. Based on the experimental results, various storage indices under different initial water saturation levels were obtained using formulas (23) to (30), such as σ As shown.

[0106] Depend on σ It can be observed that higher gas injection rates and better reservoir properties result in higher final oil displacement efficiency and recovery rate. Analysis suggests that higher gas injection rates lead to a larger driving pressure gradient and gas-liquid contact area, improving the oil-water mobility ratio, promoting dissolution and expansion, and reducing oil-water interfacial tension. This, in turn, displaces more residual oil, thereby increasing oil displacement efficiency.

[0107] Depend on σ It is evident that reservoirs with better physical properties or higher gas injection rates exhibit higher CO2 physical limit sequestration capacity and sequestration efficiency. Cores with better physical properties and higher gas injection rates demonstrate higher displacement efficiency, larger usable pore space, and greater effective utilization.

[0108] The curves showing the change in oil displacement efficiency with CO2 injection PV number under different injection pressures (10MPa, 15MPa, and 20MPa) are shown below. σ As shown. Based on the experimental results, various storage index parameters under different initial water saturation were obtained using formulas (23) to (30), such as σ As shown.

[0109] Depend on σ It is evident that the oil displacement efficiency of CO2 significantly improves with increasing injection pressure. Research analysis indicates that this phenomenon is mainly due to the following factors: First, higher injection pressure increases the displacement pressure gradient, making it easier for CO2 to penetrate and displace the tiny pores in the reservoir. This enhanced pressure gradient helps mobilize more crude oil, thereby improving the overall recovery rate. Second, with increasing pressure, both the viscosity and solubility of CO2 significantly increase. This change allows CO2 to diffuse more uniformly in the reservoir and effectively displace crude oil. High viscosity helps improve flow characteristics, while increased solubility promotes the interaction between CO2 and crude oil, further enhancing the oil displacement efficiency. In summary, these factors work together to enable CO2 to more efficiently displace crude oil under high-pressure conditions, thereby improving reservoir development.

[0110] Calculations revealed that higher injection pressure not only significantly improved the physical limit of reservoir sequestration and sequestration efficiency, but also positively impacted the dynamic distribution of fluids within the reservoir (e.g., σSpecifically, under high injection pressure, the fluidity and solubility of CO2 are enhanced, making it easier to penetrate and distribute within complex pore structures. This process significantly improves the displacement efficiency of the core, reduces residual oil retention, and increases the available pore space for CO2. As CO2 more effectively fills reservoir pores, the reservoir's storage capacity is fully utilized, resulting in a substantial increase in storage efficiency. Furthermore, high injection pressure can delay gas breakthrough time, further enhancing storage stability and ultimately achieving superior reservoir storage performance. These results indicate that, in practical operations, rationally controlling the injection pressure is one of the key factors in improving the geological storage effect of CO2.

[0111] The curves showing the change in oil displacement efficiency with CO2 injection PV number at different experimental temperatures (40℃, 60℃, and 80℃) are shown below. σ As shown. Based on the experimental results, various storage index parameters under different initial water saturation were obtained using formulas (23) to (30), such as σ As shown.

[0112] Depend on σ It is evident that under high-temperature conditions, crude oil viscosity decreases significantly, thereby improving the water-oil mobility ratio and enhancing the oil displacement efficiency of CO2. Especially in high-temperature environments, the increased fluidity of crude oil allows CO2 to more effectively displace the crude oil in the reservoir.

[0113] The experimental results show that higher experimental temperatures can improve the physical limit of CO2 sequestration in core samples, the sequestration efficiency factor, and the sequestration efficiency (e.g., ...). σ σ σ σ σ σ σ σ σ σ σ σ σ σ σ σ σ σ σ σ σ σ σ σ σ σ σ σ σ σ σ σ σ σ σ σ σ σ σ σ σ σ σ σ σ σ σ σ σ σ σ σ σ σ σ σ σ σ σ σ σ σ σ σ σ σ σ σ σ σ σ σ σ σ σ σ σ σ σ σ σ σ σ σ σ σ σ σ σ σ σ σ σ σ σ σ σ σ σ σ σ σ σ σ σ σ σ σ σ σ σ σ σ σ σ σ σ σ σ σ σ σ σ σ σ σ σ σ σ σ σ σ σ σ σ σ σ σ σ σ σ σ σ σ σ σ σ σ σ This is because at higher temperatures, the oil-water displacement efficiency within the core is improved, increasing the effective utilization space of the pores and thus improving the utilization rate of the pore space. Therefore, under high-temperature conditions, the core can more effectively seal CO2, exhibiting higher sealing capacity and efficiency.

[0114] In practical field conditions, the impact of temperature on the CO2 sequestration process is multifaceted and complex from the perspective of long-term CO2 sequestration. While higher temperatures reduce the solubility of CO2 in oil and water, they simultaneously accelerate mineralization reactions and promote the formation of stable carbonate minerals. Therefore, under high-temperature conditions, CO2 may be more likely to be sequestered in supercritical and carbon-fixed forms, which is beneficial for the stability of long-term sequestration. However, excessively high temperatures may also trigger some unfavorable mineralization reactions, thereby affecting the effectiveness of sequestration. Furthermore, higher temperatures also lead to a decrease in CO2 density, making its migration and storage in the reservoir more complex. Low-density CO2 is more likely to form plumes in the reservoir, leading to increased uneven distribution and affecting sequestration performance.

[0115] Although the actual temperature of the reservoir is difficult to change, understanding how temperature affects the CO2 sequestration mechanism and behavior helps to better predict and optimize sequestration effectiveness. This is especially true in the near-wellbore zone, where injected fluids can cause small temperature changes, making the effect of temperature particularly critical. In heavy oil or high-viscosity reservoirs, the role of temperature in CO2 displacement and sequestration efficiency is even more significant. Understanding and mastering the importance of temperature is crucial for optimizing CO2 sequestration strategies.

Claims

1. A comprehensive evaluation method for the effectiveness of carbon dioxide reservoir storage, characterized in that, The method is as follows: By conducting carbon dioxide displacement saturated oil-water core experiments, the CO2 sequestration process of actual oil reservoirs was simulated. Based on the experimental test data, the core-scale CO2 sequestration index of the simulated oil reservoir was calculated. The core-scale CO2 sequestration index includes: core-scale physical limit sequestration capacity. σ c Core-scale structural preservation capacity σ c,1 Core-scale dissolution and preservation capacity σ c,2 Core-scale storage efficiency η Core-scale storage efficiency factor ζ Contribution of core-scale structural preservation α stru and the contribution ratio of core-scale dissolution and sequestration β diss ; The above-mentioned core-scale CO2 sequestration indices were used to evaluate the CO2 reservoir sequestration effect of the target reservoir under the corresponding conditions.

2. The comprehensive evaluation method for the carbon dioxide reservoir storage effect according to claim 1, characterized in that, The physical limit of core-scale sequestration capacity σ c The calculation formula is as follows: ； in, σ c For the physical limit of core-scale sequestration capacity, cm 3 ; R fo,lab The final oil displacement efficiency of the core sample is % R fw,lab The final water displacement efficiency of the core sample is % C CO2-Oil The experiment simulated the solubility and mole fraction of CO2 in crude oil under simulated temperature and pressure conditions. C CO2-Water The solubility and mole fraction of CO2 in water were calculated to simulate the temperature and pressure conditions used in the experiment. L Core length ， cm; r Core radius ， cm; ϕ is Core porosity, %.

3. The comprehensive evaluation method for the carbon dioxide reservoir storage effect according to claim 1, characterized in that, The core-scale structural sealing capacity σ c,1 The calculation formula is as follows: ； in, σ c,1 For core-scale structural preservation capacity, cm 3 ; S wi The initial water saturation of the core, %.

4. The comprehensive evaluation method for the carbon dioxide reservoir storage effect according to claim 3, characterized in that, The core-scale dissolution and sequestration capacity σ c,2 The calculation formula is as follows: ； in, σ c,2 For core-scale dissolution and sequestration capacity, cm 3 ; S oi The initial oil saturation of the core is %.

5. The comprehensive evaluation method for the carbon dioxide reservoir storage effect according to claim 1, characterized in that, Core-scale storage efficiency η The calculation formula is as follows: ； in, η' For the final storage efficiency, % V p The pore volume of the rock sample is expressed in cm³. 3 ; S g,max This represents the maximum gas saturation of the core at the end of gas drive, in percentages.

6. The comprehensive evaluation method for the carbon dioxide reservoir storage effect according to claim 1, characterized in that, The core-scale storage efficiency factor ζ The calculation formula is as follows: ； in, ζ The sealing efficiency factor is dimensionless.

7. The comprehensive evaluation method for the carbon dioxide reservoir storage effect according to claim 1, characterized in that, The contribution ratio of core-scale tectonic sealing α stru The calculation formula is as follows: ； in, α stru The proportion of contribution to core-scale structural preservation.

8. The comprehensive evaluation method for the carbon dioxide reservoir storage effect according to claim 1, characterized in that, The contribution ratio of core-scale dissolution and sequestration β diss The calculation formula is as follows: ； in: β diss The proportion of contribution to core-scale structural preservation.

9. The comprehensive evaluation method for the carbon dioxide reservoir storage effect according to claim 2, characterized in that, The final oil displacement efficiency of the core R fo,lab and the final water displacement efficiency of the core R fw,lab The following method is used to obtain it: Based on experimental test data, the residual water saturation, residual oil saturation, oil displacement efficiency, and water displacement efficiency were calculated after CO2 displacement of the core sample. Residual oil saturation S or The expression is as follows: ； Residual water saturation S wr The expression is as follows: ； In the formula: S or The residual oil saturation after CO2 displacement is % (%). S wr The residual water saturation after CO2 displacement is % (%). m oi Initial water-bearing conditions of the core S wi The oil content below, in grams; m wi Initial water-bearing conditions of the core S wi The water content below, in grams; m o,out The mass of oil produced by CO2 displacement is expressed in grams. m w,out The mass of water produced by CO2 displacement is expressed in grams. A The area of ​​the core end face, in cm² 2 ; L The length of the rock core is in cm. ϕ The core porosity is %; ρ o The density of crude oil at room temperature, in g / cm³ 3 ; ρ w Density of formation water at room temperature, in g / cm³ 3 ; r The radius of the core is in cm; At the end of CO2 displacement of oil and water, the maximum gas saturation in the core is the sum of the losses of the initial oil saturation and the initial water saturation. The mass of produced oil and produced water is obtained according to the law of conservation of mass. The total mass and total volume of produced oil and produced water can be expressed by the following formula: ； In the formula: V w,out The volume of water produced is expressed in cm. 3 ; V o,out The volume of oil produced is expressed in cm. 3 ; m ow,out The mass of the total oil and water produced after CO2 displacement is expressed in grams. V ow,out The total volume of oil and water produced after CO2 displacement is expressed in cm³. 3 ; The volumes of produced oil and water are expressed as follows: ； Based on the densities of oil and water under surface conditions, and combined with the volumes of produced oil and water, the masses of produced oil and water can be calculated separately, as shown in the following expressions: ； Therefore, the maximum gas saturation of the core at the end of gas drive S g,max Calculated by the following formula: ； In the formula: S g,max The maximum gas saturation of the core at the end of gas drive, % The CO2 injection process displaces oil and water, achieving an oil displacement efficiency of [missing information]. E o,CO2 (%) and water displacement efficiency E w,CO2 (%) can be calculated using the following formula: ； In the formula, E w,CO2 The water displacement efficiency is expressed as (%). E o,CO2 The oil displacement efficiency (%) is recorded as follows: at the end of injection, the corresponding water displacement efficiency and oil displacement efficiency are recorded as the final water displacement efficiency of the core. R fw,lab and core final oil displacement efficiency R fo,lab It can be calculated from the above formula combined with experimentally measured data.

10. The comprehensive evaluation method for the carbon dioxide reservoir storage effect according to claim 4, characterized in that, Initial water saturation of core S wi Compared with the initial oil saturation of the core S oi The calculation formula is as follows: ； ； In the formula: S wi The initial water saturation of the core, % m i For the first i Oil and water core mass (g) under the oil-water injection volume flow rate ratio; m 0 represents the dry core mass, in grams; ρ o To simulate the density of oil at the measurement temperature, g / cm³ 3 ; ρ w The density of simulated formation water in saturated core samples at the measured temperature, in g / cm³. 3 ; S oi The initial oil saturation of the core is %.

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