A method and system for determining relative permeability based on CO2-crude oil interaction

Abstract

The application discloses a kind of based on CO2-oil interaction's relative permeability determination method and system, and the application relates to oil and gas development technical field, comprising the following steps: preparation of different carbon dioxide molar fraction oil sample, and by near infrared spectrum establishes the calibration curve of absorption peak area and molar fraction, prepare the core for experimental simulation, inject water to saturation after injecting formation crude oil displacement water to determine irreducible water saturation, carry out carbon dioxide displacement experiment under set pressure, measure the absorption spectrum of produced oil, to identify carbon dioxide breakthrough moment, the displacement process is divided into two stages, and calculate dynamic interaction parameter, introduce these parameters to modify JBN algorithm, determine oil phase and gas phase relative permeability, and combine gas saturation and carbon dioxide molar fraction, draw relative permeability curve, complete permeability determination, the method has higher practicality and accuracy.

Description

Technical Field

[0001] This invention relates to the field of oil and gas development technology, specifically to a method and system for determining relative permeability based on the interaction between CO2 and crude oil. Background Technology

[0002] In the process of oil and gas development, carbon dioxide (CO2) displacement technology is widely used to improve crude oil recovery, especially in deep reservoirs. CO2 injection can effectively reduce the viscosity of oil and improve its fluidity, thereby achieving more efficient oil-water separation. The relative permeability measurement method based on CO2-crude oil interaction can provide oilfield engineers with important data for evaluating and optimizing the CO2 displacement process, helping to achieve more accurate oil and gas resource management and development.

[0003] Currently, existing technologies typically rely on static experimental methods or simple mathematical models to estimate relative permeability, analyzing fluid seepage characteristics under single experimental conditions. While these methods can provide preliminary permeability data, they often fail to fully consider the dynamic characteristics of interactions between different fluids in practical applications. In particular, under different CO2 mole fractions and seepage conditions, existing methods still cannot effectively capture transient changes in permeability during the seepage process.

[0004] The shortcomings of existing technologies lie in the lack of real-time monitoring and dynamic analysis of multiphase flow processes, which often leads to insufficient accuracy in permeability measurements. Furthermore, traditional methods fail to adequately consider the influence of the mole fraction of carbon dioxide on fluid properties when predicting permeability. These deficiencies make it difficult to accurately describe the interaction between CO2 and crude oil in complex reservoir environments.

[0005] The information disclosed in the background section is only intended to enhance the understanding of the background of this disclosure, and therefore may include information that does not constitute prior art known to those skilled in the art. Summary of the Invention

[0006] The purpose of this invention is to provide a method and system for determining relative permeability based on the interaction between CO2 and crude oil, so as to solve the problems mentioned in the background art.

[0007] To achieve the above objectives, the present invention provides the following technical solution: A method for determining relative permeability based on CO2-crude oil interaction, comprising the following steps: Oil samples with different mole fractions of carbon dioxide were prepared under experimental conditions, and the near-infrared absorption spectra of each oil sample were collected to establish a calibration curve of absorption peak area versus carbon dioxide mole fraction. Cores were prepared for experimental simulation. After being saturated with water, formation crude oil was injected into the cores under experimental conditions to displace the internal water until no more water was produced at the outlet and the pressure difference stabilized. The cumulative water production was recorded to calculate the bound water saturation, and the effective permeability of the oil phase under the bound water state was measured as the baseline permeability. At the experimental temperature, the back pressure was set to the experimental pressure, and carbon dioxide was injected into the core at a constant displacement pressure to carry out the displacement experiment. The absorption spectrum of the produced oil at the core outlet was measured, and the carbon dioxide mole fraction-time curve of the produced oil during the displacement experiment was obtained by fitting the calibration curve. The carbon dioxide breakthrough moment was identified from the curve, and the displacement process of the displacement experiment was divided into two stages: before breakthrough and after breakthrough. The dynamic interaction parameters in the two stages were calculated respectively. The JBN algorithm is modified by introducing dynamic interaction parameters. Based on the modified JBN algorithm, the relative permeability of the oil phase and the relative permeability of the gas phase are determined. The relative permeability curve is plotted by combining the gas saturation and the mole fraction of carbon dioxide to complete the permeability measurement.

[0008] Furthermore, the experimental temperature and pressure are set based on the constant temperature chamber to create a high-temperature and high-pressure experimental environment; Under experimental temperature and pressure, oil samples with different carbon dioxide mole fractions were prepared. Each oil sample was injected into a near-infrared flow cell, and the corresponding near-infrared absorption spectra were collected. The Pearson coefficient of carbon dioxide mole fraction and absorption peak area in each band of the near-infrared absorption spectrum was calculated. The sensitive band was determined based on the Pearson coefficient. The specific method is as follows: the near-infrared absorption spectrum is divided into several bands with equal wavelength intervals. The Pearson coefficient of absorption peak area and carbon dioxide mole fraction in each band is calculated. The band with the largest absolute value of Pearson coefficient is taken as the sensitive band. The carbon dioxide mole fraction of each oil sample and its absorption peak area in the sensitive band are extracted and linearly fitted to form a calibration curve of absorption peak area and carbon dioxide mole fraction.

[0009] Furthermore, core samples were prepared for experimental simulation, and their pore volume was measured using a helium porosimeter. The bound water saturation was calculated based on the principle of mass balance. The logic underlying the calculation was as follows: In the formula, To restrict water saturation, For pore volume, For cumulative water production; The method for calculating the effective permeability of the oil phase under bound water conditions as the baseline permeability is as follows: When the core no longer produces water and the pressure differential is stable, the pressure differential at this time is recorded as the stable pressure differential, and the formation crude oil injection rate at this time is recorded as the crude oil phase flow rate. The baseline permeability is calculated based on the stable pressure differential and the crude oil phase flow rate, using the following formula: In the formula, Based on penetration rate, For crude oil phase flow rate, The viscosity of the formation crude oil under experimental conditions. The length of the core sample. The cross-sectional area of ​​the rock core. To stabilize the pressure difference.

[0010] Furthermore, the back pressure is set to the experimental pressure at the experimental temperature, specifically referring to the pressure at the core outlet; The method for fitting the carbon dioxide mole fraction-time curve of the produced oil under the displacement experiment is as follows: During the displacement experiment, the produced oil at the core outlet is collected at a preset sampling frequency, and the absorption spectrum of the produced oil sample at each sampling time is measured. Then, the absorption peak area of ​​the sensitive band in the absorption spectrum at each sampling time is extracted and substituted into the calibration curve to obtain the carbon dioxide mole fraction of the produced oil sample at each sampling time. Linear fitting is then performed to obtain the carbon dioxide mole fraction-time curve of the produced oil sample during the displacement experiment. The logic behind dividing the displacement process into two stages, pre-breakthrough and post-breakthrough, is as follows: From the carbon dioxide mole fraction-time curve, the moment when the carbon dioxide mole fraction first exceeds a preset mole fraction threshold and shows a continuous upward trend within at least two subsequent preset time windows is extracted as the carbon dioxide breakthrough moment. The time period before the carbon dioxide breakthrough moment is recorded as the pre-breakthrough stage, and the time period after the carbon dioxide breakthrough moment is recorded as the post-breakthrough stage.

[0011] Furthermore, the dynamic interaction parameters mentioned in the previous stage include the dynamic volume expansion coefficient and the dynamic effective viscosity of the oil phase, while the dynamic interaction parameters mentioned in the later stage specifically include the dynamic volume expansion coefficient, the dynamic effective viscosity of the oil phase, and the dynamic interfacial tension. The specific formula used to calculate the dynamic volume expansion coefficient based on the carbon dioxide mole fraction is as follows: In the formula, It is the expansion factor. Let be the dynamic volume expansion coefficient at time t. Let be the mole fraction of carbon dioxide at time t, where t is the time variable of the displacement experiment. The specific formula used to calculate the effective viscosity of the dynamic oil phase is as follows: In the formula, Let be the dynamic effective viscosity of the oil phase at time t. The initial oil phase viscosity, The first viscosity reduction coefficient, This is the second viscosity reduction coefficient; The specific formula used to calculate dynamic interfacial tension is as follows: In the formula, for The dynamic interface tension at any given moment. The initial oil-gas interfacial tension, The interfacial tension reduction coefficient. for The mole fraction of carbon dioxide at time 10:00. To overcome the time variable in the later stage, the optimal values ​​of the expansion factor, the first viscosity reduction coefficient, the second viscosity reduction coefficient, and the interfacial tension reduction coefficient were determined through numerical simulation.

[0012] Furthermore, the JBN algorithm is modified based on dynamic interaction parameters. The specific logic behind this modification is as follows: In the pre-breakthrough stage, dynamic volume expansion coefficient and dynamic oil phase effective viscosity are introduced for correction; in the post-breakthrough stage, dynamic interfacial tension is added for correction. Specific methods for determining the relative permeability of the oil phase and the relative permeability of the gas phase based on the modified JBN algorithm include: By calculating the time derivatives of cumulative oil production and cumulative gas production, instantaneous oil production and instantaneous gas production are obtained. Based on these instantaneous oil production and instantaneous gas production, the oil phase fraction is calculated using the following formula: In the formula, Let be the oil phase flow rate at time t. Let be the instantaneous oil production flow rate at time t. Let be the instantaneous gas production flow rate at time t; The flow capacity ratio is calculated based on the baseline permeability, using the following formula: In the formula, The flow capacity ratio at time t; The relative permeability of the oil phase is calculated based on the flow capacity ratio and the oil phase fraction flow rate. The specific formula used is as follows: In the formula, Let be the relative permeability of the oil phase at time t. The corrected cumulative injection factor considering the expansion effect at time t is calculated using the following formula: In the formula, The cumulative injection multiple at time t; In the pre-breakthrough stage, dynamic volumetric expansion coefficient and dynamic effective oil phase viscosity are introduced to correct the relative permeability of the oil phase. For the relative permeability due to the interaction between carbon dioxide and crude oil in the post-breakthrough stage, dynamic interfacial tension is added to correct the relative permeability of the gas phase. The relative permeability of the gas phase is calculated based on the ratio of oil to gas relative permeability, using the following formula: In the formula, Let be the relative permeability of the gas phase at time t; The effective viscosity of the gas phase. This is the capillary effect correction factor. The starting point of the displacement experiment. This marks the breakthrough moment for carbon dioxide emissions. This is the end time of the displacement experiment.

[0013] Furthermore, the specific formula used to calculate gas saturation is as follows: In the formula, Let be the gas saturation at time t. Let be the cumulative oil production volume at time t.

[0014] Furthermore, the expansion factor, the first viscosity reduction coefficient, the second viscosity reduction coefficient, the interfacial tension reduction coefficient, and the capillary effect correction coefficient are used as optimization parameters, and an optimization combination containing each optimization parameter is formed. The relative permeability of the oil phase and the relative permeability of the gas phase under different optimization combinations are determined. Based on the relative permeability of the oil phase and the relative permeability of the gas phase, the CO2 displacement process under the same conditions is simulated by numerical simulation software, and the simulated cumulative oil production and cumulative gas production are output as simulation data. The cumulative oil production and cumulative gas production in the displacement experiment data are used as measured data. With the goal of minimizing the absolute difference between measured and simulated data, the optimal combination is determined by a genetic algorithm. The parameters within the optimal combination are then used as the optimal parameters and filled into the formula to determine the relative permeability of CO2-crude oil interaction.

[0015] This invention also provides a relative permeability measurement system based on CO2-crude oil interaction, wherein the relative permeability measurement system based on CO2-crude oil interaction is used to perform the above-described relative permeability measurement method based on CO2-crude oil interaction, comprising: The sample data preparation module is used to prepare oil samples with different mole fractions of carbon dioxide under experimental conditions and to collect the near-infrared absorption spectra of each oil sample in order to establish a calibration curve of absorption peak area versus carbon dioxide mole fraction. The basic parameter sampling module is used to prepare the core for experimental simulation. After injecting water into it to saturation, formation crude oil is injected into the core under experimental conditions to displace the water inside it until no more water is produced and the pressure difference is stable. The cumulative water production is recorded to calculate the bound water saturation, and the effective permeability of the oil phase under the bound water state is measured as the basic permeability. The displacement analysis module is used to set the back pressure to the experimental pressure at the experimental temperature, inject carbon dioxide into the core at a constant displacement pressure to carry out the displacement experiment, measure the absorption spectrum of the produced oil sample at the core outlet, and combine it with the calibration curve to obtain the carbon dioxide mole fraction-time curve of the produced oil sample during the displacement experiment. From this, the carbon dioxide breakthrough moment is identified, so that the displacement process of the displacement experiment is divided into two stages: before breakthrough and after breakthrough. The dynamic interaction parameters in the two stages are calculated respectively. The permeability analysis module is used to introduce dynamic interaction parameters to correct the JBN algorithm. Based on the corrected JBN algorithm, the relative permeability of the oil phase and the relative permeability of the gas phase are determined. Combined with the gas saturation and carbon dioxide mole fraction, the relative permeability curve is plotted to complete the permeability measurement.

[0016] Compared with the prior art, the beneficial effects of the present invention are: This invention first prepares oil samples with different carbon dioxide molar fractions at experimental temperatures and pressures. Utilizing the sensitivity of near-infrared spectroscopy to CO2, a calibration curve is established between the absorption peak area and the CO2 molar fraction. By setting the back pressure to the experimental pressure and injecting CO2 under constant displacement pressure, the seepage conditions in a real oil reservoir are effectively simulated. By collecting the absorption spectrum of the produced oil sample from the core outlet and combining it with the established calibration curve, the CO2 molar fraction is monitored in real time, and the breakthrough moment of CO2 is identified. The displacement process is divided into two stages: before and after breakthrough, and the dynamic interactions within each stage are analyzed independently. By modifying the characteristic parameters in the traditional JBN algorithm using dynamic interaction parameters, the permeability measurement error caused by the lack of dynamic understanding of multiphase flow processes in previous methods is overcome. The modified JBN algorithm can more accurately determine the relative permeability of the oil phase and the relative permeability of the gas phase, and plot the relative permeability curve. It achieves dynamic tracking and accurate measurement, making up for the shortcomings of existing technologies in real-time monitoring and dynamic analysis, and has higher practicality and accuracy. Attached Figure Description

[0017] Figure 1 This is a schematic diagram of the overall method flow of the present invention; Figure 2 The curves show the relative permeability of the oil phase and the relative permeability of the gas phase. Figure 3 This is a schematic diagram of the overall system structure of the present invention. Detailed Implementation

[0018] To make the objectives, technical solutions, and advantages of this invention clearer, the invention will be further described in detail below with reference to specific embodiments.

[0019] It should be noted that, unless otherwise defined, the technical or scientific terms used in this invention should have the ordinary meaning understood by one of ordinary skill in the art to which this invention pertains. The terms "first," "second," and similar terms used in this invention do not indicate any order, quantity, or importance, but are merely used to distinguish different components. Terms such as "comprising" or "including" mean that the element or object preceding the word encompasses the elements or objects listed following the word and their equivalents, without excluding other elements or objects. Terms such as "connected" or "linked" are not limited to physical or mechanical connections, but can include electrical connections, whether direct or indirect. Terms such as "upper," "lower," "left," and "right" are used only to indicate relative positional relationships; when the absolute position of the described object changes, the relative positional relationship may also change accordingly.

[0020] Example: Please see Figures 1-2 The present invention provides a technical solution: A method for determining relative permeability based on CO2-crude oil interaction, comprising the following steps: Step 1: Prepare oil samples with different mole fractions of carbon dioxide under experimental conditions, and collect the near-infrared absorption spectra of each oil sample to establish a calibration curve of absorption peak area versus carbon dioxide mole fraction.

[0021] The constant temperature chamber is used to set the experimental temperature and pressure to create a high-temperature and high-pressure experimental environment. In the oil and gas industry, the behavior and properties of carbon dioxide are usually significantly affected by temperature and pressure. High-temperature and high-pressure conditions are closer to actual application scenarios, such as the exploitation and processing of oil and gas fields, ensuring the scientific validity and applicability of the experimental results. The constant temperature chamber is set up to maintain a stable experimental temperature and pressure, so that the experimental results are repeatable and reliable.

[0022] Under experimental temperature and pressure, oil samples with different carbon dioxide mole fractions were prepared. Each oil sample was injected into a near-infrared flow cell, and the corresponding near-infrared absorption spectra were collected. The Pearson coefficient of carbon dioxide mole fraction and absorption peak area in each band of the near-infrared absorption spectrum was calculated. The sensitive band was determined based on the Pearson coefficient. The specific method is as follows: the near-infrared absorption spectrum is divided into several bands with equal wavelength intervals. The Pearson coefficient of absorption peak area and carbon dioxide mole fraction in each band is calculated. The band with the largest absolute value of Pearson coefficient is taken as the sensitive band. The carbon dioxide mole fraction of each oil sample and its absorption peak area in the sensitive band are extracted and linearly fitted to form a calibration curve of absorption peak area and carbon dioxide mole fraction.

[0023] In the oil and gas industry, the behavior and properties of carbon dioxide are usually significantly affected by temperature and pressure; high temperature and high pressure conditions are closer to actual application scenarios, such as the exploitation and processing of oil and gas fields, ensuring the scientific validity and applicability of experimental results; setting up a constant temperature chamber to maintain stable experimental temperature and pressure makes the experimental results repeatable and reliable.

[0024] By preparing oil samples with different mole fractions, a wide range of carbon dioxide concentrations in practical applications can be covered. Different carbon dioxide contents help explore their impact on near-infrared spectroscopy and provide a data basis for subsequent quantitative analysis. The multi-sample design can improve the accuracy and stability of the model and effectively evaluate the impact of carbon dioxide mole fraction on the near-infrared absorption characteristics of oil samples. Near-infrared spectroscopy has the advantages of being fast and non-destructive, and can effectively obtain molecular information of samples. By collecting absorption spectra at different mole fractions, characteristic absorption peaks related to carbon dioxide concentration can be identified. The Pearson coefficient quantifies the linear relationship between two variables, ranging from -1 to 1. A value closer to 1 or -1 indicates a stronger linear correlation between the variables. By calculating the Pearson coefficient for the absorption peak area and carbon dioxide mole fraction at different wavelengths, bands sensitive to changes in carbon dioxide mole fraction can be effectively identified, focusing on the most important spectral features, thereby simplifying the model and improving the accuracy of the analysis. Selecting the band with the largest absolute value of the Pearson coefficient as the sensitive band ensures that the chosen band is most responsive to changes in carbon dioxide.

[0025] Step 2: Prepare a core for experimental simulation. After injecting water into the core until it is saturated, inject formation crude oil into the core under experimental conditions to displace the internal water until no more water is produced and the pressure difference is stable. Record the cumulative water production to calculate the bound water saturation and measure the effective permeability of the oil phase under the bound water state as the base permeability.

[0026] Core samples for experimental simulation were prepared, and their pore volume was measured using a helium porosimeter. The specific method for preparing the simulated core samples was as follows: Suitable rock materials, such as sandstone or limestone, were selected as the base for the simulated core. The selected rock materials should be representative and able to reflect the actual characteristics of the strata. Necessary binders and additives were prepared to enhance the strength and stability of the simulated core during preparation. A mold was made using metal or plastic. The mixed rock material was placed into the mold and compacted. Compaction could be performed using pneumatic or hydraulic equipment to ensure the density and uniformity of the core. The mold should be customized according to the required size and shape of the core to ensure compatibility with practical applications and subsequent experiments. The formed core was placed in a suitable environment for curing. The curing time was adjusted according to the characteristics of the binder used. Typically, the curing time ranges from 24 hours to several days. After curing, the core was removed and surface-treated to remove excess binder and impurities.

[0027] The specific method for determining the pore volume is as follows: The dried core is placed into the measuring chamber of a helium porosimeter, ensuring a secure seal. The helium porosimeter is then activated, and helium gas is injected into the measuring chamber. The helium gas enters the measuring chamber through the pores of the core. The instrument records the gas pressure changes. Based on these pressure changes, the pore volume of the core is calculated using the gas law. Helium has excellent permeability, effectively penetrating every pore of the core. After measurement, the pore volume data is recorded, analyzed, and processed. Porosity is calculated, specifically expressed as the ratio of pore volume to the total core volume, to obtain the porosity result of the simulated core.

[0028] The calculation of bound water saturation is based on the principle of mass balance, and the logic behind the calculation is as follows: In the formula, To restrict water saturation, For pore volume, This represents the cumulative water production. It should be noted that, Bound water saturation indicates the proportion of bound water in the pores of a rock core. Bound water refers to water that cannot be displaced, typically fixed in the pores due to capillary forces or surface adsorption. Its presence is closely related to pore structure, fluid properties, and capillary forces. Displacement experiments can measure the volume of water that can be displaced in the rock core. The remaining water volume is the volume of bound water; the specific formula is set based on the theory of pore fluid distribution.

[0029] The method for calculating the effective permeability of the oil phase under bound water conditions as the baseline permeability is as follows: When water production ceases at the core outlet and the pressure differential stabilizes, the pressure differential at this point is recorded as the stable pressure differential, and the formation crude oil injection rate at this point is recorded as the crude oil phase flow rate. The baseline permeability is calculated based on the stable pressure differential and the crude oil phase flow rate, using the following formula: In the formula, Based on penetration rate, For crude oil phase flow rate, The viscosity of the formation crude oil under experimental conditions. The length of the core sample. The cross-sectional area of ​​the rock core. To stabilize the pressure difference.

[0030] It should be noted that the formula is based on fluid mechanics principles, especially Darcy's law, which can describe the flow behavior of the oil phase in the core under specific conditions. When the core no longer produces water and the pressure difference is stable, the stability of the experiment is ensured, and the flow characteristics of the oil phase in the core can be accurately reflected. At this time, the recorded pressure difference and oil flow rate can truly reflect the permeability of the core and reduce experimental errors. Viscosity Viscosity is an important parameter for fluid flow, affecting the flow resistance of the fluid. Introducing the viscosity of the oil phase when calculating permeability makes the calculation more accurate. The higher the viscosity of the fluid, the more difficult the flow. Therefore, the viscosity of the fluid must be considered in the calculation of permeability. Core length refers to the vertical distance from the top to the bottom of the core. The steps to obtain the core length are as follows: During the core sampling process, the length of the core is usually measured directly on site; using a tape measure or other measuring tools, the length is measured from the starting point of the core, usually the top of the borehole, to the ending point, i.e., the bottom of the core. Use measuring tools such as calipers to accurately measure the diameter or length and width of the rock core, and then apply the conventional area formula to calculate the cross-sectional area.

[0031] Step 3: Set the back pressure to the experimental pressure at the experimental temperature, inject carbon dioxide into the core at a constant displacement pressure to conduct the displacement experiment, measure the absorption spectrum of the produced oil sample at the core outlet, and combine it with the calibration curve to obtain the carbon dioxide mole fraction-time curve of the produced oil sample during the displacement experiment. Identify the carbon dioxide breakthrough moment from it, so as to divide the displacement process of the displacement experiment into two stages: before breakthrough and after breakthrough, and calculate the dynamic interaction parameters in the two stages respectively.

[0032] At the experimental temperature, the back pressure is set to the experimental pressure, where the back pressure specifically refers to the pressure at the core outlet. The method for fitting the carbon dioxide mole fraction-time curve of the produced oil sample under the displacement experiment is as follows: During the displacement experiment, the produced oil sample at the core outlet is collected at a preset sampling frequency, and the absorption spectrum of the produced oil sample at each sampling time is measured. Then, the absorption peak area of ​​the sensitive band in the absorption spectrum at each sampling time is extracted and substituted into the calibration curve to obtain the carbon dioxide mole fraction of the produced oil sample at each sampling time. Linear fitting is then performed to obtain the carbon dioxide mole fraction-time curve of the effluent during the displacement experiment. The logic behind dividing the displacement process into two stages, pre-breakthrough and post-breakthrough, is as follows: From the carbon dioxide mole fraction-time curve, the moment when the carbon dioxide mole fraction first exceeds a preset mole fraction threshold and shows a continuous upward trend within at least two subsequent preset time windows is extracted as the carbon dioxide breakthrough moment. The time period before the carbon dioxide breakthrough moment is recorded as the pre-breakthrough stage, and the time period after the carbon dioxide breakthrough moment is recorded as the post-breakthrough stage.

[0033] It should be noted that unsteady-state displacement experiments are an important method for studying fluid flow in porous media. In this process, carbon dioxide is injected into the core as a displacing agent to drive the crude oil fluid out; as carbon dioxide is injected, its flow characteristics and displacement effect in the core will change over time. The displacement process is divided into two stages: before and after the breakthrough. In the pre-breakthrough stage, the flow of carbon dioxide is mainly through capillary action and fluid interface phenomena to expel the original fluid. At this time, the fluid interaction is relatively complex. In the post-breakthrough stage, carbon dioxide flows out at a higher mole fraction, and the flow state tends to be stable, which allows for a clearer analysis of the dynamic characteristics of the fluid. Determining the carbon dioxide breakthrough moment is crucial for evaluating the displacement effect. The breakthrough moment typically indicates that the interaction between the displacing fluid and the original fluid reaches a critical point, thus affecting subsequent flow behavior. By setting a preset mole fraction threshold and time window, the breakthrough moment can be identified, providing a basis for subsequent analysis.

[0034] The specific method for setting the preset mole fraction threshold is as follows: The preset mole fraction threshold should be set based on fluid flow theory, experimental data analysis, and statistical results. Specifically, it involves analyzing the physicochemical properties of carbon dioxide and its interaction with the displaced fluid, understanding the possible concentration range of carbon dioxide during the flow process, collecting data on the change of carbon dioxide mole fraction over time through preliminary experimental operations, observing the change of carbon dioxide mole fraction in the extracted oil sample, and identifying the trend and fluctuation range of the mole fraction change. Typically, the mole fraction threshold is set between 0.1% and 5%.

[0035] The dynamic interaction parameters mentioned in the pre-breakthrough stage include the dynamic volume expansion coefficient and the dynamic effective viscosity of the oil phase, while the dynamic interaction parameters mentioned in the post-breakthrough stage specifically include the dynamic volume expansion coefficient, the dynamic effective viscosity of the oil phase, and the dynamic interfacial tension. It should be noted that in the pre-breakthrough stage, carbon dioxide gradually infiltrates the core as a displacement agent, and its volume expansion behavior is closely related to the displacement efficiency. The dynamic volume expansion coefficient can reflect the pressure response and fluid performance changes of carbon dioxide during the injection process. Understanding its expansion characteristics helps to assess whether it can effectively drive the original fluid out. The dynamic effective viscosity of the oil phase is the viscous characteristic exhibited by the fluid during the flow process. In the pre-breakthrough stage, the interaction between the oil phase and carbon dioxide is mainly manifested through viscosity. The injection of carbon dioxide may change the flow characteristics of the oil phase. The dynamic effective viscosity of the oil phase helps to understand the resistance and fluidity of the fluid during the flow process. Dynamic interfacial tension refers to the tension at the interface between two fluids, such as oil and carbon dioxide. In the post-breakthrough stage, carbon dioxide has already broken through in the core and formed a new flow state with the oil phase. At this time, the change in interfacial tension has a significant impact on the flow and distribution of the fluid. The increase or decrease of dynamic interfacial tension may affect the stratification, dispersion and discharge efficiency of the fluid, thus having a significant impact on the displacement effect.

[0036] The specific formula used to calculate the dynamic volume expansion coefficient based on the carbon dioxide mole fraction is as follows: In the formula, It is the expansion factor. Let be the dynamic volume expansion coefficient at time t. Let be the mole fraction of carbon dioxide at time t, where t is the time variable of the displacement experiment. It should be noted that, Indicates at time The dynamic volume expansion coefficient is used to describe the volume change characteristics of a fluid under specific conditions; it is also known as the expansion factor. The setting is intended to quantify the effect of carbon dioxide mole fraction on volume, reflecting how the properties of carbon dioxide affect the expansion behavior of the mixed fluid; This formula assumes a linear relationship between the dynamic volume expansion coefficient and the mole fraction of carbon dioxide, by expressing the dynamic volume expansion coefficient as a simple linear function of the mole fraction of carbon dioxide.

[0037] The specific formula used to calculate the effective viscosity of the dynamic oil phase is as follows: In the formula, Let be the dynamic effective viscosity of the oil phase at time t. The initial oil phase viscosity, The first viscosity reduction coefficient, This is the second viscosity reduction coefficient; It should be noted that the dynamic effective viscosity of the oil phase is the apparent viscosity of the fluid during flow, which is affected by the fluid composition, including the molar coefficient of carbon dioxide. An exponential decay model is used to describe the change in oil phase viscosity, emphasizing that as the molar fraction of carbon dioxide increases, the oil phase viscosity decreases exponentially. With increasing carbon dioxide concentration, the oil phase viscosity decreases non-linearly, and exponential decay effectively captures this characteristic. Through the use of... and Two adjustment coefficients are used to optimize the formula based on the characteristics of different oil phases and experimental conditions.

[0038] The specific formula used to calculate dynamic interfacial tension is as follows: In the formula, for The dynamic interface tension at any given moment The initial oil-gas interfacial tension, The interfacial tension reduction coefficient. for The mole fraction of carbon dioxide at time 10:00. To break through the time variables in the later stage; It should be noted that in the post-breakthrough stage, carbon dioxide has successfully permeated into the oil phase and formed an interface with it. At this point, the oil-gas interface characteristics become particularly important because interfacial tension affects the fluid's flow pattern, dispersion, and displacement capacity. The interaction between carbon dioxide and the oil phase alters the flow characteristics of the oil phase, especially in the flow channels, where the fluid distribution and flow direction are significantly influenced by interfacial tension, which directly affects the fluid's flow resistance. When the interfacial tension decreases, the flow resistance between the oil and carbon dioxide decreases, promoting fluid flow and thus improving displacement efficiency. As the molar fraction of carbon dioxide increases, the interfacial tension typically decreases linearly. Introducing this parameter provides more accurate measurement. During carbon dioxide displacement, the injection of carbon dioxide alters the molecular interactions at the oil-gas interface, typically leading to a decrease in interfacial tension. This formula adjusts the interfacial tension decrease coefficient accordingly. The value quantifies the degree of influence of carbon dioxide on interfacial tension; the optimal values ​​of the expansion factor, the first viscosity reduction coefficient, the second viscosity reduction coefficient, and the interfacial tension reduction coefficient are determined through numerical simulation.

[0039] Step 4: Introduce dynamic interaction parameters to modify the JBN algorithm. Based on the modified JBN algorithm, determine the relative permeability of the oil phase and the relative permeability of the gas phase. Combine the gas saturation and carbon dioxide mole fraction to plot the relative permeability curve to complete the permeability measurement.

[0040] The JBN algorithm is modified based on dynamic interaction parameters. The specific logic behind this modification is as follows: In the pre-breakthrough stage, dynamic volume expansion coefficient and dynamic oil phase effective viscosity are introduced for correction; in the post-breakthrough stage, dynamic interfacial tension is added for correction. Specific methods for determining the relative permeability of the oil phase and the relative permeability of the gas phase based on the modified JBN algorithm include: By calculating the time derivatives of cumulative oil production and cumulative gas production, instantaneous oil production and instantaneous gas production are obtained. Based on these instantaneous oil production and instantaneous gas production, the oil phase fraction is calculated using the following formula: In the formula, Let be the oil phase flow rate at time t. Let be the instantaneous oil production at time t. Let be the instantaneous gas production at time t; The flow capacity ratio is calculated based on the baseline permeability, using the following formula: In the formula, The flow capacity ratio at time t; It should be noted that the flow capacity ratio It is an important indicator used to compare flow capacity under different fluid conditions. It reflects the relative flow capacity of the oil phase at a specific water saturation level and is commonly used to assess the production performance of oil reservoirs; Basic penetration rate It is an important parameter affecting fluid flow. A medium with high permeability allows fluid to pass through more easily; therefore, its flow capacity should be inversely proportional to its permeability, as stated in the formula. Some studies introduce the base permeability as an important factor in the flow capacity ratio, emphasizing the significant impact of permeability on flow capacity. Higher permeability results in a higher flow capacity ratio. Dynamic oil phase effective viscosity viscosity with initial oil phase The introduction of the ratio can reflect the impact of fluid viscosity changes under different conditions on flowability. The lower the effective viscosity of the oil phase, the larger the flowability ratio, indicating that the fluid flows more easily. Using the ratio... It can quantitatively describe the dynamic changes of fluids, allowing for direct comparison of flow capacity at different time points during multiphase flow analysis, thus enabling more flexible assessment of changes in flow state.

[0041] The relative permeability of the oil phase is calculated based on the flow capacity ratio and the oil phase fraction flow rate. The specific formula used is as follows: In the formula, Let be the relative permeability of the oil phase at time t; The corrected cumulative injection factor considering the expansion effect at time t is calculated using the following formula: In the formula, The cumulative injection multiple at time t; It should be noted that the relative permeability of the oil phase This refers to the contribution of the oil phase to the total permeability under certain saturation and flow conditions, reflecting the permeability of the oil phase. Oil phase flow rate This indicates the proportion of oil phase flow rate in the total fluid flow rate, reflecting the proportion of the oil phase in multiphase flow. It is achieved by introducing... It can correlate oil phase permeability with actual flow distribution, ensuring that the calculation results closely approximate the actual fluid flow process.

[0042] In multiphase flow processes, the behavior of the injected fluid is significantly affected by the volume expansion effect. This can be addressed by correcting the cumulative injection factor. This method can more accurately describe the dynamic contribution of the injected fluid to the oil phase permeability. Expansion not only changes the volume and flow behavior of the fluid, but also affects the effective permeability of the fluid. By correcting the introduction of the cumulative injection factor, the formula can better fit the complexity of unsteady flow, making the calculation of the oil phase relative permeability more accurate.

[0043] Flow capacity ratio This reflects the dynamic changes in the flowability of the oil phase. Calculating its derivative with the reciprocal of the corrected injection ratio allows us to capture the dynamic coupling between the two, including the dynamic effective viscosity of the oil phase. and initial viscosity The ratio reflects the effect of fluid viscosity changes on permeability. Changes in oil phase viscosity directly affect the fluid's flowability. By introducing this ratio, the corrective effect of viscosity on oil phase permeability can be described more accurately.

[0044] The formula simultaneously considers key dynamic factors such as oil phase flow rate, flow capacity ratio, viscosity change, and expansion effect, and can comprehensively reflect the oil phase flow characteristics under complex conditions. The cumulative effect and expansion behavior of the injected fluid are important characteristics of the unsteady displacement process. By correcting the cumulative injection ratio... and dynamic volume expansion coefficient To capture these characteristics and reflect their impact on oil phase permeability.

[0045] In the pre-breakthrough stage, dynamic volume expansion coefficient and dynamic effective oil phase viscosity are introduced to correct the relative permeability of the oil phase. For the relative permeability of the carbon dioxide-crude oil interaction in the post-breakthrough stage, dynamic interfacial tension is added to correct the relative permeability of the gas phase. The relative permeability of the gas phase is calculated based on the ratio of oil to gas relative permeability, using the following formula: In the formula, Let be the relative permeability of the gas phase at time t; The effective viscosity of the gas phase. This is the capillary effect correction factor. The starting point of the displacement experiment. This marks the breakthrough moment for carbon dioxide emissions. This is the end time of the displacement experiment.

[0046] It should be noted that the calculation of gas phase relative permeability depends on the oil phase relative permeability. The ratio is used to reflect the mutual influence between the gas phase and the oil phase. The paper introduces the ratio of dynamic viscosity of the gas phase to that of the oil phase, emphasizing the influence of fluid viscosity on permeability; The term indicates the separation relationship between the oil phase and the gas phase at this stage, ensuring that the flow capacity under gas-liquid interaction is appropriately corrected; With the breakthrough in carbon dioxide emissions, the interfacial tension between oil and gas has become even more important. Following this breakthrough, the dynamic changes in interfacial tension affect the flow characteristics of the gas phase, which can be addressed through correction factors. A correction is made to account for the effect of capillary effect on the relative permeability of the gas phase; the capillary effect correction factor is... This method is used to quantify the effect of interfacial tension on gas phase flowability, ensuring that the gas phase permeability can be appropriately adjusted when the interfacial tension changes.

[0047] The specific formula used to calculate gas saturation is as follows: In the formula, Let be the gas saturation at time t. Let t be the cumulative oil production at time t.

[0048] The expansion factor, first viscosity reduction coefficient, second viscosity reduction coefficient, interfacial tension reduction coefficient, and capillary effect correction coefficient are used as optimization parameters to form an optimized combination that includes each optimization parameter. The relative permeability of the oil phase and gas phase under different optimization combinations is determined. Based on the relative permeability of the oil phase and gas phase, a CO2 displacement process under identical conditions is simulated using numerical simulation software. The simulated cumulative oil production and cumulative gas production are output as simulation data. The cumulative oil production and cumulative gas production from the unsteady-state displacement experimental data are used as measured data. Specifically, the numerical simulation software can be CMG, a professional oil and gas reservoir simulation software widely used in oil and gas development. It has powerful multiphase flow simulation capabilities and can effectively simulate the CO2 displacement process, the influence of relative oil and gas permeability, and other optimization parameters. Alternatively, TOUGH2, an open-source software for simulating multiphase flow and heat transfer, is commonly used in geothermal and CO2 geological storage fields. TOUGH2 is suitable for handling complex fluid interactions and heat transfer problems and can simulate the displacement behavior of CO2 in oil fields.

[0049] The optimization objective is to minimize the absolute difference between measured and simulated data. A genetic algorithm is used to determine the optimal combination, and the parameters within this optimal combination are used as the optimal parameters in the formula to determine the relative permeability of CO2-crude oil interaction. Specific steps include: treating each optimization parameter as a gene, constructing individuals including each gene type, forming several individuals, randomly selecting several individuals to construct an initial population, and performing iterative selection, crossover, and mutation operations on the individuals in the initial population based on a fitness function until a preset number of iterations is reached. The individual with the smallest fitness function during the iterative optimization process is determined as the optimal combination. The genetic algorithm is a conventional existing technology, and its specific operation steps are not detailed here. The fitness function is specifically set according to the optimization objective, and its expression is as follows: In the formula, For the fitness function value, To measure the cumulative oil production, To simulate cumulative oil production, To measure the cumulative gas production, To simulate cumulative gas production; By combining gas saturation with the mole fraction of carbon dioxide, a relative permeability curve is plotted to complete the permeability determination. The relative permeability curves of the oil phase and the gas phase are plotted on the same graph, with the horizontal axis representing gas saturation or mole fraction of carbon dioxide and the vertical axis representing relative permeability. Experimental data points and fitted curves are marked on the graph to observe trends and changes, analyze the shape, trend and characteristics of the relative permeability curve, and explain the influence of different mole fractions of carbon dioxide and gas saturation on flow behavior.

[0050] Please see Figure 3 The present invention also provides a relative permeability measurement system based on CO2-crude oil interaction, wherein the relative permeability measurement system based on CO2-crude oil interaction is used to perform the above-described relative permeability measurement method based on CO2-crude oil interaction, comprising: The sample data preparation module is used to prepare oil samples with different mole fractions of carbon dioxide under experimental conditions and to collect the near-infrared absorption spectra of each oil sample in order to establish a calibration curve of absorption peak area versus carbon dioxide mole fraction. The basic parameter sampling module is used to prepare core samples for experimental simulation. After injecting water into the core sample until it is saturated, formation crude oil is injected into the core sample under experimental conditions to displace the water inside until no more water is produced and the pressure difference is stable. The cumulative water production is recorded to calculate the bound water saturation, and the effective permeability of the oil phase under the bound water state is measured as the basic permeability. The displacement analysis module is used to set the back pressure to the experimental pressure at the experimental temperature, inject carbon dioxide into the core at a constant displacement pressure to carry out the displacement experiment, measure the absorption spectrum of the produced oil sample at the core outlet, and combine it with the calibration curve to obtain the carbon dioxide mole fraction-time curve of the produced oil sample during the displacement experiment. From this, the carbon dioxide breakthrough moment is identified, so that the displacement process of the displacement experiment is divided into two stages: before breakthrough and after breakthrough. The dynamic interaction parameters in the two stages are calculated respectively. The permeability analysis module is used to modify the JBN algorithm by introducing dynamic interaction parameters. Based on the modified JBN algorithm, the relative permeability of the oil phase and the relative permeability of the gas phase are determined. Combined with the gas saturation, the relative permeability is correlated with the mole fraction of carbon dioxide to plot the relative permeability curve, thus completing the permeability measurement.

[0051] The above formulas are all dimensionless calculations. The formulas are derived from software simulations using a large amount of data to obtain the most recent real-world results. The preset parameters in the formulas are set by those skilled in the art according to the actual situation.

[0052] The above embodiments can be implemented, in whole or in part, by software, hardware, firmware, or any other combination thereof. When implemented in software, the above embodiments can be implemented, in whole or in part, as a computer program product. Those skilled in the art will recognize that the units and algorithm steps of the various examples described in conjunction with the embodiments disclosed herein can be implemented by electronic hardware, or a combination of computer software and electronic hardware. These functions are performed in hardware or software methods, depending on the specific application and design constraints of the technical solution.

[0053] The units described as separate components may or may not be physically separate. The components shown as units may or may not be physical units; they may be located in one place or distributed across multiple network units. Some or all of the units can be selected to achieve the purpose of this embodiment, depending on actual needs.

[0054] The above description is merely a specific embodiment of this application, but the scope of protection of this application is not limited thereto. Any changes or substitutions that can be easily conceived by those skilled in the art within the scope of the technology disclosed in this application should be included within the scope of protection of this application.

Claims

1. A method for determining relative permeability based on the interaction between CO2 and crude oil, characterized in that, The specific steps include: Oil samples with different mole fractions of carbon dioxide were prepared under experimental conditions, and the near-infrared absorption spectra of each oil sample were collected to establish a calibration curve of absorption peak area versus carbon dioxide mole fraction. Cores were prepared for experimental simulation. After water was injected into the cores until they were saturated, formation crude oil was injected into the cores under experimental conditions to displace the water inside them until no more water was produced and the pressure difference was stable. The cumulative water production was recorded to calculate the bound water saturation, and the effective permeability of the oil phase under the bound water state was measured as the baseline permeability. At the experimental temperature, the back pressure was set to the experimental pressure, and carbon dioxide was injected into the core at a constant displacement pressure to carry out the displacement experiment. The absorption spectrum of the produced oil at the core outlet was measured, and the carbon dioxide mole fraction-time curve of the produced oil during the displacement experiment was obtained by fitting the calibration curve. The carbon dioxide breakthrough moment was identified from the curve, and the displacement process of the displacement experiment was divided into two stages: before breakthrough and after breakthrough. The dynamic interaction parameters in the two stages were calculated respectively. The JBN algorithm is modified by introducing dynamic interaction parameters. Based on the modified JBN algorithm, the relative permeability of the oil phase and the relative permeability of the gas phase are determined. Combined with the gas saturation, they are correlated with the mole fraction of carbon dioxide to plot the relative permeability curve, thus completing the permeability measurement.

2. The method for determining relative permeability based on CO2-crude oil interaction according to claim 1, characterized in that, The experimental environment is created by setting the experimental temperature and pressure in a constant temperature chamber. Under experimental temperature and pressure, oil samples with different carbon dioxide mole fractions were prepared. Each oil sample was injected into a near-infrared flow cell, and the corresponding near-infrared absorption spectra were collected. The Pearson coefficient of carbon dioxide mole fraction and absorption peak area in each band of the near-infrared absorption spectrum was calculated. The sensitive band was determined based on the Pearson coefficient. The specific method is as follows: the near-infrared absorption spectrum is divided into several bands with equal wavelength intervals. The Pearson coefficient of absorption peak area and carbon dioxide mole fraction in each band is calculated. The band with the largest absolute value of Pearson coefficient is taken as the sensitive band. The carbon dioxide mole fraction of each oil sample and its absorption peak area in the sensitive band are extracted and linearly fitted to form a calibration curve of absorption peak area and carbon dioxide mole fraction.

3. The method for determining relative permeability based on CO2-crude oil interaction according to claim 2, characterized in that, Core samples were prepared for experimental simulation, and their pore volume was measured using a helium porosimeter. The bound water saturation was calculated based on the principle of mass balance. The logic underlying the calculation was as follows: In the formula, To restrict water saturation, For pore volume, For cumulative water production; The method for calculating the effective permeability of the oil phase under bound water conditions as the baseline permeability is as follows: When the core no longer produces water and the pressure differential is stable, the pressure differential at this time is recorded as the stable pressure differential, and the formation crude oil injection rate at this time is recorded as the crude oil phase flow rate. The baseline permeability is calculated based on the stable pressure differential and the crude oil phase flow rate, using the following formula: In the formula, Based on penetration rate, For crude oil phase flow rate, The viscosity of the formation crude oil under experimental conditions. The length of the core sample. The cross-sectional area of ​​the rock core. To stabilize the pressure difference.

4. The method for determining relative permeability based on CO2-crude oil interaction according to claim 1, characterized in that, At the experimental temperature, the back pressure is set to the experimental pressure, where the back pressure specifically refers to the pressure at the core outlet. The method for fitting the carbon dioxide mole fraction-time curve of the produced oil under the displacement experiment is as follows: During the displacement experiment, oil samples are collected at the core outlet at a preset sampling frequency, and the absorption spectrum of the effluent at each sampling time is measured. Then, the absorption peak area of ​​the sensitive band in the absorption spectrum at each sampling time is extracted and substituted into the calibration curve to obtain the carbon dioxide mole fraction of the produced oil at each sampling time. Linear fitting is then performed to obtain the carbon dioxide mole fraction-time curve of the produced oil during the displacement experiment. The logic behind dividing the displacement process into two stages, pre-breakthrough and post-breakthrough, is as follows: From the carbon dioxide mole fraction-time curve, the moment when the carbon dioxide mole fraction first exceeds a preset mole fraction threshold and shows a continuous upward trend within at least two subsequent preset time windows is extracted as the carbon dioxide breakthrough moment. The time period before the carbon dioxide breakthrough moment is recorded as the pre-breakthrough stage, and the time period after the carbon dioxide breakthrough moment is recorded as the post-breakthrough stage.

5. The method for determining relative permeability based on CO2-crude oil interaction according to claim 3, characterized in that, The dynamic interaction parameters mentioned in the pre-breakthrough stage include the dynamic volume expansion coefficient and the dynamic effective viscosity of the oil phase, while the dynamic interaction parameters mentioned in the post-breakthrough stage specifically include the dynamic volume expansion coefficient, the dynamic effective viscosity of the oil phase, and the dynamic interfacial tension. The specific formula used to calculate the dynamic volume expansion coefficient based on the carbon dioxide mole fraction is as follows: In the formula, It is the expansion factor. Let be the dynamic volume expansion coefficient at time t. Let be the mole fraction of carbon dioxide at time t, where t is the time variable of the displacement experiment. The specific formula used to calculate the effective viscosity of the dynamic oil phase is as follows: In the formula, Let be the dynamic effective viscosity of the oil phase at time t. The initial oil phase viscosity, The first viscosity reduction coefficient, This is the second viscosity reduction coefficient; The specific formula used to calculate dynamic interfacial tension is as follows: In the formula, for The dynamic interface tension at any given moment The initial oil-gas interfacial tension, The interfacial tension reduction coefficient. for The mole fraction of carbon dioxide at time 10:

00. To overcome the time variable in the later stage, the optimal values ​​of the expansion factor, the first viscosity reduction coefficient, the second viscosity reduction coefficient, and the interfacial tension reduction coefficient were determined through numerical simulation.

6. The method for determining relative permeability based on CO2-crude oil interaction according to claim 5, characterized in that, The JBN algorithm is modified based on dynamic interaction parameters. The specific logic behind this modification is as follows: In the pre-breakthrough stage, dynamic volume expansion coefficient and dynamic oil phase effective viscosity are introduced for correction; in the post-breakthrough stage, dynamic interfacial tension is added for correction. Specific methods for determining the relative permeability of the oil phase and the relative permeability of the gas phase based on the modified JBN algorithm include: By calculating the time derivatives of cumulative oil production and cumulative gas production, the instantaneous oil production flow rate and instantaneous gas production flow rate are obtained. Based on the instantaneous oil production and instantaneous gas production, the oil phase flow rate is calculated. The specific formula used is as follows: In the formula, Let be the oil phase flow rate at time t. Let be the instantaneous oil production at time t. Let be the instantaneous gas production at time t; The flow capacity ratio is calculated based on the baseline permeability, using the following formula: In the formula, The flow capacity ratio at time t; The relative permeability of the oil phase is calculated based on the flow capacity ratio and the oil phase fraction flow rate. The specific formula used is as follows: In the formula, Let be the relative permeability of the oil phase at time t. The corrected cumulative injection factor considering the expansion effect at time t is calculated using the following formula: In the formula, The cumulative injection multiple at time t; In the pre-breakthrough stage, dynamic volumetric expansion coefficient and dynamic effective oil phase viscosity are introduced to correct the relative permeability of the oil phase. For the relative permeability of the gas phase due to the interaction between carbon dioxide and crude oil in the post-breakthrough stage, dynamic interfacial tension is added to correct the relative permeability of the gas phase. The relative permeability of the gas phase is calculated based on the ratio of oil to gas relative permeability, using the following formula: In the formula, Let be the relative permeability of the gas phase at time t; The effective viscosity of the gas phase. This is the capillary effect correction factor. The starting point of the displacement experiment. This marks the breakthrough moment for carbon dioxide emissions. This is the end time of the displacement experiment.

7. The method for determining relative permeability based on CO2-crude oil interaction according to claim 6, characterized in that, The specific formula used to calculate gas saturation is as follows: In the formula, Let be the gas saturation at time t. Let t be the cumulative oil production at time t.

8. The method for determining relative permeability based on CO2-crude oil interaction according to claim 7, characterized in that, The expansion factor, first viscosity reduction coefficient, second viscosity reduction coefficient, interfacial tension reduction coefficient, and capillary effect correction coefficient are used as optimization parameters, and an optimization combination containing each optimization parameter is formed. The relative permeability of the oil phase and the relative permeability of the gas phase under different optimization combinations are determined. Based on the relative permeability of the oil phase and the relative permeability of the gas phase, the CO2 displacement process under the same conditions is simulated by numerical simulation software. The simulated cumulative oil production and cumulative gas production are output as simulation data, and the cumulative oil production and cumulative gas production in the experimental data are used as measured data. With the goal of minimizing the absolute difference between measured and simulated data, a genetic algorithm is used to determine the optimal combination. The parameters within the optimal combination are then used as the optimal parameters and filled into the formula to determine the relative permeability of CO2-crude oil interaction.

9. A relative permeability determination system based on CO2-crude oil interaction, used to perform the relative permeability determination method based on CO2-crude oil interaction as described in any one of claims 1-8, characterized in that, include: The sample data preparation module is used to prepare oil samples with different mole fractions of carbon dioxide under experimental conditions and to collect the near-infrared absorption spectra of each oil sample in order to establish a calibration curve of absorption peak area versus carbon dioxide mole fraction. The basic parameter sampling module is used to prepare the core for experimental simulation. After injecting water into it to saturation, formation crude oil is injected into the core under experimental conditions to displace the water inside it until no more water is produced and the pressure difference is stable. The cumulative water production is recorded to calculate the bound water saturation, and the effective permeability of the oil phase under the bound water state is measured as the basic permeability. The displacement analysis module is used to set the back pressure to the experimental pressure at the experimental temperature, inject carbon dioxide into the core at a constant displacement pressure to carry out the displacement experiment, measure the absorption spectrum of the fluid produced at the core outlet, and combine it with the calibration curve to obtain the carbon dioxide mole fraction-time curve of the oil sample produced during the displacement experiment. From this, the carbon dioxide breakthrough moment is identified, so that the displacement process of the displacement experiment is divided into two stages: before breakthrough and after breakthrough. The dynamic interaction parameters in the two stages are calculated respectively. The permeability analysis module is used to introduce dynamic interaction parameters to correct the JBN algorithm. Based on the corrected JBN algorithm, the relative permeability of the oil phase and the relative permeability of the gas phase are determined. Combined with the gas saturation and carbon dioxide mole fraction, the relative permeability curve is plotted to complete the permeability measurement.

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