Cooperative viscosity reduction contribution degree identification calculation and verification method in CO2 huff and puff process

Abstract

The invention discloses a collaborative viscosity reduction contribution degree identification calculation method and verification method in a CO2 huff and puff process, and relates to the technical field of CO2 huff and puff of unconventional oil reservoirs. According to the method, a crude oil viscosity-temperature coupling model, a CO2 solubility-temperature coupling model and a solubility-viscosity coupling model are constructed, temperature balance points, namely critical temperatures with equivalent contributions of two viscosity reduction effects, are identified through derivative analysis, and contribution proportions at different temperatures are quantified. According to the method, the problem that the contribution degree is difficult to distinguish due to mutual inhibition of temperature and CO2 dissolution viscosity reduction is solved, and a theoretical basis is provided for oil reservoir development parameter optimization. According to the verification method, the swept area is measured through a temperature gradient experiment and ImageJ software, contribution degree experimental quantification is achieved in combination with a quantitative formula, a'theoretical prediction-experimental verification 'closed loop is formed, and the reliability of the model is improved. According to the verification method, a temperature gradient experiment is combined with a quantitative calculation formula, the microscopic swept area is converted into a fluidity index, a'theoretical prediction-experimental verification 'closed loop is formed, and the reliability of model parameters is improved.

Description

TECHNICAL FIELD

[0001] The present application relates to the field of CO2 huff and puff technology in unconventional reservoirs in oil and gas development engineering, and in particular to a quantitative evaluation method for the contribution of temperature and CO2 dissolution to viscosity reduction in the CO2 huff and puff process. BACKGROUND

[0002] I. Technical scenario and existing technology basis The main purpose of reducing the viscosity of crude oil is to improve its flowability. The viscosity of crude oil is closely related to its flowability, and the higher the viscosity, the worse the flowability, resulting in a decrease in the recovery efficiency of crude oil in the reservoir. By reducing the viscosity, the flowability of crude oil in the reservoir can be improved, thereby increasing the recovery efficiency. This is particularly important for the development of unconventional reservoirs such as tight oil reservoirs, as these reservoirs typically have low permeability and poor flowability, and the use of viscosity reduction can significantly improve the exploitation effect of the reservoir.

[0003] As conventional oil and gas resources gradually enter the mature development stage, the focus of reservoir development gradually shifts to unconventional reservoirs such as tight oil reservoirs. CO2 huff and puff technology is considered one of the effective means for developing unconventional reservoirs, as it can reduce viscosity and improve flowability of crude oil through CO2 dissolution in crude oil. Temperature is a key parameter that affects the effectiveness of CO2 huff and puff: on the one hand, an increase in temperature can directly reduce the viscosity of crude oil; on the other hand, an increase in temperature can inhibit the dissolution of CO2 in crude oil, thereby indirectly weakening the effect of CO2 dissolution in reducing viscosity.

[0004] Microfluidic chip technology has become an important experimental platform for studying the micro-mechanism of CO2 huff and puff due to its pore structure reduction and visualization capabilities. This technology can directly observe the dissolution, diffusion and seepage behavior of CO2 and crude oil, providing support for understanding the changes in flowability of crude oil.

[0005] II. Deficiencies of existing technology and introduction of existing related technology 1. Core defect: temperature and CO2 dissolution viscosity reduction contribution difficult to quantify and distinguish In actual microfluidic experiments, there is a mutual inhibition relationship between temperature increase and CO2 dissolution in improving the flowability of crude oil (temperature increase → viscosity reduction but CO2 solubility decreases), which makes it difficult to quantitatively distinguish the contribution of the two, and restricts the precision of CO2 huff and puff experimental design and injection-production parameter optimization.

[0006] 2. Existing related technology focuses on independent analysis of a single factor: The relationship between crude oil viscosity and temperature is usually fitted using the Andrade viscosity-temperature model to obtain the viscosity-temperature curve; The calculation of CO2 solubility relies on Henry's law, but it fails to correlate with the viscosity model; The effect of CO2 dissolution on viscosity is described by an exponential model, but fails to incorporate the temperature parameter.

[0007] All three are applied individually in their respective scenarios, without forming a coupled model, resulting in a lack of quantitative description of the synergistic effect of multiple parameters, and the inability to identify the temperature balance point (critical temperature where the two effects contribute equally) through theoretical derivation.

[0008] III. The necessity of improvement In the prior art, the isolated application of theoretical models and the limitations of experimental design result in the inability to separate the synergistic contribution of temperature and CO2 dissolution viscosity reduction, making it difficult to guide the parameter optimization of CO2 huff and puff technology in unconventional reservoirs. Therefore, there is an urgent need for a quantitative analysis method that combines theoretical calculations and experimental verification to determine the contribution of the two viscosity reduction mechanisms at different temperatures, providing a scientific basis for reservoir development plan design. SUMMARY

[0009] The purpose of the present application is to provide a method for identifying and calculating the synergistic viscosity reduction contribution in the CO2 huff and puff process, breaking through the limitations of single-factor analysis, achieving quantitative separation of the contributions of temperature and CO2 dissolution viscosity reduction, and solving the problem in the prior art that the two factors inhibit each other, making it difficult to distinguish their contributions.

[0010] To achieve the above-mentioned purpose, the method for identifying and calculating the synergistic viscosity reduction contribution in the CO2 huff and puff process according to the present application is carried out in the following steps: The first step is to build a theoretical coupled model: simultaneously solving the crude oil viscosity-temperature relationship model, the CO2 solubility-temperature relationship model, and the solubility-viscosity relationship model to form a coupled model that describes the synergistic effect of temperature and CO2 solubility on crude oil viscosity; The second step is to identify the temperature balance point through derivative analysis of the coupled model, which is the critical temperature at which the contributions of temperature viscosity reduction and CO2 dissolution viscosity reduction are equal; The third step is to quantify the contribution of temperature viscosity reduction and CO2 dissolution viscosity reduction to the flowability of crude oil at different temperatures based on the temperature balance point.

[0011] In the first step, the crude oil viscosity-temperature relationship model uses the Andrade viscosity-temperature model, which is expressed as Formula One: μ0=A·e (B / T) ; Where μ0 is the viscosity of crude oil without dissolved CO2, with units of mPa·s; T is the absolute temperature, with units of K, and its value is derived from the actual crude oil temperature of the target reservoir, measured or obtained through geological data; Both A and B are empirical constants, both dimensionless, and both obtained through experimental data fitting.

[0012] In the first step, the CO2 solubility-temperature relationship model is based on Henry's law and empirical correction, and its expression is formula two: Rs=M·C=M·(p / H0)·e （N / T） ; wherein Rs is the CO2 solubility, with the unit of g / L; p is the gas pressure, with the unit of Pa; H0 is the Henry constant at the reference temperature, with the unit of Pa·L / mol, used to characterize the CO2 dissolution equilibrium characteristics in the crude oil, and its value is obtained by experimental measurement or literature; C is the molar concentration of the gas in the liquid, mol / L; M is the molar mass, with the unit of g / mol, and the molar mass M of CO2 is 44.009 g / mol.

[0013] In the first step, the solubility-viscosity relationship model is an exponential model, and its expression is formula three: μ=μ0·e (－α·Rs） wherein μ is the viscosity of the crude oil after dissolving CO2, with the unit of mPa·s, which is obtained by experimental measurement of the viscosity data of the crude oil under different CO2 solubility conditions or calculated based on a theoretical model; μ0 is the viscosity of the crude oil without dissolving CO2, with the unit of mPa·s, which is calculated by formula one; α is an empirical fitting coefficient, dimensionless, which is obtained by experimental data regression; Rs is the CO2 solubility, with the unit of g / L, which is calculated by formula two.

[0014] The coupling model in the first step is formula four: μ(T) = A·exp{B / T-(α·p·H0 / M)·exp(N / T)}; In the coupling model, μ(T) is the viscosity of the crude oil after dissolving CO2, with the unit of mPa·s, which is measured by experiment; A and B are both Andrade viscosity-temperature model coefficients; T is the absolute temperature, with the unit of K, the actual crude oil temperature of the target reservoir, which is measured or obtained through geological data; α is the solubility-viscosity empirical fitting coefficient in formula three, with the unit of m³ / m³, which is an empirical coefficient; M is the molar mass, with the unit of g / mol, and the molar mass M of CO2 is 44.009 g / mol; p is the gas pressure, with the unit of megapascal, the set pressure of the autoclave, which is set according to the original formation pressure or the actual reservoir pressure of the target reservoir; N is the temperature coefficient, with the unit of Kelvin, which is an empirical correction coefficient, and is obtained by fitting the CO2 solubility experimental data; In the second step, the derivative analysis specifically comprises: deriving the coupling model and calculating an extreme point, the extreme point corresponding to a temperature equilibrium point T0, when the temperature is less than T0, the CO2 dissolution viscosity reduction accounts for a dominant contribution in the total contribution of the crude oil flowability improvement, and when the temperature is greater than T0, the temperature viscosity reduction accounts for a dominant contribution in the total contribution of the crude oil flowability improvement.

[0015] The application also provides a verification method of the above-mentioned method for identifying and calculating the synergistic viscosity reduction contribution degree in the CO2 huff and puff process, comprising the following steps: ①designing a plurality of groups of CO2 huff and puff experiments with temperature gradients, the temperature gradients being set according to an experimental temperature point with a temperature difference of 15℃ based on a target reservoir temperature; ②measuring the crude oil swept area ratio S1 / S0 after the pressure relief oil production at each temperature point by using ImageJ software, wherein S1 is the crude oil swept area, in square meters, and S0 is the microfluidic chip area, in square meters; ③based on the temperature equilibrium point T0 and the crude oil flowability minimum temperature Tmin in claim 5, calculating the temperature contribution degree γtemp(T) by using Formula Five γtemp(T)=γtemp(Tmin)+[γ(T)-γ(Tmin)]; γtemp(T) is the crude oil flowability ratio contributed by the temperature T, in percentage, and is the calculation result of Formula Five; γtemp(Tmin) is the crude oil flowability ratio contributed by the minimum flowability temperature Tmin, in percentage, and is calculated based on the temperature contribution value γtemp(T0) corresponding to the temperature equilibrium point T0 and the flowability difference [γ(T0)-γ(Tmin)]; γ(T) is the crude oil flowability ratio at the temperature T, in percentage, and is obtained by measuring the crude oil swept area ratio S1 / S0 at the temperature T by using ImageJ software; γ(Tmin) is the crude oil flowability ratio at the minimum flowability temperature Tmin, in percentage, and is the flowability value corresponding to the lowest point of the temperature-crude oil flowability curve in the experiment, and is measured by the temperature gradient microfluidic experiment; the CO2 dissolution contribution degree γCO2(T) is calculated by using Formula Six γCO2(T)=γ(T)-γtemp(T); γCO2(T) is the crude oil flowability ratio contributed by the CO2 dissolution viscosity reduction at the temperature T, in percentage, and is calculated by subtracting the temperature contribution ratio γtemp(T) from the total flowability ratio γ(T), reflecting the individual contribution of the CO2 dissolution to the flowability.

[0016] In the first step, the temperature gradient experiment at least includes five temperature points of 30℃, 45℃, 60℃, 75℃ and 90℃.

[0017] In the second step, the oil sweep area ratio is obtained by analyzing the gray value of the CO2 / oil distribution image through the ImageJ software.

[0018] In the third step, the contribution degree is calculated by the normalization formula, i.e., formula seven Ptemp(T)=γtemp(T) / γ(T)×100% and formula eight PCO2(T)=γCO2(T) / γ(T)×100%, to obtain the temperature and CO2 dissolution contribution ratio; Wherein, Ptemp(T) is the contribution ratio of temperature to the flowability of crude oil, which is a percentage, calculated by formula seven, indicating the percentage contribution of temperature alone to the improvement of flowability; PCO2(T) is the contribution ratio of CO2 dissolution to the flowability of crude oil, which is a percentage, calculated by formula eight, indicating the percentage contribution of CO2 dissolution alone to the improvement of flowability; γtemp(T) is the crude oil flowability index contributed by temperature alone, which is dimensionless, obtained by deducing the experimentally measured crude oil sweep area ratio; γCO2(T) is the crude oil flowability index contributed by CO2 dissolution alone, which is dimensionless, obtained by deducing the experimentally measured crude oil sweep area ratio; γ(T) is the total crude oil flowability index (temperature+CO2 joint action), which is dimensionless, obtained by the experimentally measured crude oil sweep area ratio, and its value is S1 / S0.

[0019] It also includes a cross-validation step: draw the temperature-crude oil flowability curve through the temperature gradient experiment in claim 6, identify the turning point of the curve as the experimental equilibrium point, and cross-verify with the theoretical temperature equilibrium point T0 in the second step of the synergistic viscosity reduction contribution degree identification calculation method in the CO2 huff and puff process.

[0020] The present application has the following advantages: Breakthrough the limitations of single factor analysis: by coupling the crude oil viscosity-temperature relationship model, the CO2 solubility-temperature relationship model and the solubility-viscosity relationship model, a coupled model is constructed to realize the quantitative separation of the contribution of temperature and CO2 dissolution viscosity reduction, and to solve the problem that the two mutually inhibit the contribution degree.

[0021] Improve the prediction accuracy: integrate the direct influence of temperature on crude oil viscosity and the indirect influence of CO2 solubility into a unified mathematical expression, overcome the defect that the traditional stage model cannot reflect the interaction of parameters, and improve the prediction accuracy of the change rule of crude oil viscosity.

[0022] Precise positioning of temperature balance point: the extreme point is calculated by derivation of the coupling model to determine the temperature balance point T0 (the critical temperature at which the temperature reduction viscosity and the CO2 dissolution reduction viscosity contribute equally), which provides a clear theoretical threshold for contribution degree splitting and guides the optimization of specific viscosity reduction means at a specific temperature (such as preferentially using CO2 dissolution viscosity reduction when the temperature is lower than T0, and preferentially using temperature viscosity reduction when the temperature is higher than T0).

[0023] Combination of experiment and theory for verification: a temperature gradient CO2 huff and puff experiment is designed, the microcosmic sweep area is converted into a flowability index by using ImageJ software, and the experimental quantification of contribution degree is realized by combining with the quantitative calculation formula; the cross verification (comparison of the theoretical balance point and the experimental curve turning point) forms a closed loop of "theoretical prediction-experimental verification", which improves the reliability of the model parameters.

[0024] Provide intuitive optimization basis: through normalization processing, eliminate the influence of dimension, directly output the contribution ratio of temperature and CO2 dissolution viscosity reduction, and provide intuitive and operable basis for parameter optimization of CO2 huff and puff experiment in reservoir development.

[0025] The present application integrates the direct influence of temperature on crude oil viscosity and the indirect influence of CO2 solubility into a unified mathematical expression through a coupling model, realizes the quantitative description of the synergistic effect of temperature and CO2 dissolution, provides a continuous derivable theoretical basis for subsequent derivative analysis and contribution degree splitting, overcomes the defect that the traditional stage-by-stage model cannot reflect the interaction of parameters, and improves the prediction accuracy of the change rule of crude oil viscosity.

[0026] The present application determines the temperature balance point T0 by derivation of the coupling model and calculation of the extreme point, and has the technical advantages that: the temperature balance point is accurately positioned by mathematical derivation, which provides a clear theoretical threshold for contribution degree differentiation of temperature viscosity reduction and CO2 dissolution viscosity reduction. When the temperature is lower than T0, it can be determined that CO2 dissolution viscosity reduction is dominant, and when the temperature is higher than T0, temperature viscosity reduction is dominant. This quantitative division method provides a key benchmark for the calculation of contribution degree in subsequent experimental verification, provides direct guidance for adopting specific viscosity reduction means in practice at a specific temperature (or temperature range), effectively solves the problem that the traditional method cannot clearly determine the critical point of the two action mechanisms, ensures the scientificity and operability of the contribution degree splitting result, and provides a theoretical basis for parameter optimization of CO2 huff and puff experiment in reservoir development. BRIEF DESCRIPTION OF DRAWINGS

[0027] Figure 1 The principle diagram of the present application, wherein the synergistic viscosity reduction contribution degree identification and calculation method in the CO2 huff and puff process comprises three core steps of constructing a temperature-CO2 dissolution coupling viscosity reduction model (S1), identifying a temperature balance point (S2), and quantifying the contribution ratio of temperature and CO2 dissolution viscosity reduction (S3) in sequence.

[0028] Figure 2Microscopic images of CO2 / crude oil distribution after depressurization and oil recovery at five temperatures (30℃, 45℃, 60℃, 75℃ and 90℃) show the final distribution of CO2 and crude oil within the microfluidic chip after CO2 huff and puff and depressurization and oil recovery at different constant temperatures (30℃, 45℃, 60℃, 75℃ and 90℃).

[0029] Figure 2 In the diagram, each small image corresponds to an experimental temperature: the temperature increases sequentially from left to right (or from top to bottom).

[0030] Dark areas – residual crude oil that has not been affected by CO2 and remains intact; Light-colored or colorless areas – areas that have been dissolved, displaced, and extracted by CO2 (i.e., CO2-affected areas).

[0031] The larger the affected area, the higher the proportion of crude oil extracted, and the better the liquidity.

[0032] Depend on Figure 2 As can be seen: 30℃: Darker residual oil is present, with the smallest affected area, indicating strong CO2 dissolving ability at low temperatures, but the crude oil itself has excessively high viscosity, resulting in the worst overall fluidity. 45℃: Residual oil decreases, the affected area expands, and fluidity begins to improve. 60℃: Residual oil further decreases, the affected area continues to increase, and fluidity further improves. 75℃: Residual oil decreases significantly, the affected area is close to its maximum, and fluidity is relatively good. 90℃: Residual oil slightly increases, but the affected area is slightly smaller than at 75℃, suggesting that excessively high temperatures inhibit CO2 dissolution, leading to a decrease in viscosity-reducing effect.

[0033] Figure 2 This intuitively demonstrates that the "temperature-fluidity" relationship is not monotonic: viscosity dominates at very low temperatures, while solubility is limited at very high temperatures, with the two achieving an optimal balance around 75°C.

[0034] Figure 3 according to Figure 2 The results were plotted as curves showing the change in crude oil fluidity (expressed as the percentage of the affected area) at different temperatures.

[0035] Appendix Figure 3 It is a graph that directly links temperature and crude oil fluidity. The horizontal axis represents the experimental temperature, ranging from 30℃ to 90℃; the vertical axis represents the crude oil fluidity index, which simply means how much area the crude oil can spread out after depressurization. The higher the area, the easier the oil flows.

[0036] The whole curve first rises and then falls, like a small hill. When the temperature is 30℃, the curve is near the bottom of the valley - the oil is almost immobile, and although CO2 can dissolve a lot, the high viscosity "hinders" it. With the temperature rising to 45℃, the curve rises sharply, and the benefits of viscosity reduction outweigh the negative effects of solubility reduction, and the oil begins to be "pushed" significantly. Continue to warm up to 60℃, the climbing speed slows down, and viscosity and solubility are balanced, and their effects are close to flat. To 75℃ to 90℃, the curve peaks, and the flow index reaches the highest value in the whole experiment - indicating that at this temperature point, temperature viscosity reduction and CO2 dissolution viscosity reduction "hit the mark" and have the best synergistic effect.

[0037] Therefore, this curve not only intuitively verifies the "temperature balance point" mentioned in the theoretical model, but also directly tells us that operating near 75℃, the viscosity reduction effect of CO2 huff and puff is the most cost-effective; too low or too high will make the synergistic effect discounted.

[0038] Figure 4 According to Figure 3 The distribution diagram of the contribution of temperature and CO2 dissolution to the viscosity reduction of the oil.

[0039] Attached Figure 4 The "contribution" of temperature and CO2 huff and puff process to the two viscosity reduction mechanisms is divided into two curves. The horizontal axis is still the experimental temperature, from 30℃ to 90℃; the vertical axis is the contribution ratio, expressed in percentage, which one contributes more to the improvement of flowability.

[0040] First look at the curve representing the effect of temperature: the lowest at 30℃, indicating that at low temperature, the contribution of temperature itself to viscosity reduction is minimal; as the temperature rises, this line rises all the way, reaching a peak at 75℃ to 90℃, meaning that at this moment, temperature has become the "main force" of improving flowability.

[0041] Then look at the curve representing the effect of CO2 dissolution: the trend is just the opposite. At 30℃, it is high and almost takes all the credit - at low temperature, CO2 dissolves a lot, and the viscosity is greatly reduced; as the temperature rises, this line slides down, and by 75℃, it has fallen into the second place; by 90℃, the contribution ratio has dropped to the bottom, because high temperature makes CO2 dissolve less, and the effect of dissolution viscosity reduction is greatly weakened.

[0042] The intersection of the two curves occurs at about 50℃, which is the "temperature balance point" mentioned in the disclosure material - at this temperature, the contribution of temperature viscosity reduction and CO2 dissolution viscosity reduction is almost equal; below this point, CO2 dissolution dominates; above this point, temperature itself dominates. The whole graph uses two curves that cancel each other out, directly answering the key question: at different reservoir temperatures, should we focus on "warming up" or "increasing CO2 dissolution"? DETAILED DESCRIPTION

[0043] As shown in Figures 1 to 4 The method for identifying and calculating the contribution degree of viscosity reduction in the CO2 huff and puff process of the application is performed according to the following steps: The first step is to construct a theoretical coupling model: the oil viscosity-temperature relationship model, the CO2 solubility-temperature relationship model and the solubility-viscosity relationship model are coupled to form a coupling model for describing the synergistic effect of temperature and CO2 solubility on oil viscosity; The second step is to identify the temperature balance point through derivative analysis of the coupling model, and the temperature balance point is a critical temperature at which the temperature viscosity reduction effect and the CO2 dissolution viscosity reduction effect have the same contribution; The third step is to quantify the contribution ratio of the temperature viscosity reduction effect and the CO2 dissolution viscosity reduction effect to the flowability of the oil at different temperatures based on the temperature balance point.

[0044] The present application breaks through the limitation of single factor analysis by using multiple model coupling and derivative analysis, realizes the quantitative separation of temperature and CO2 dissolution viscosity reduction contribution, and solves the problem that the contribution degree is difficult to distinguish due to mutual inhibition in the prior art.

[0045] In the first step, the oil viscosity-temperature relationship model uses the Andrade viscosity-temperature model, and its expression is formula one: μ0=A·e (B / T) ; Wherein μ0 is the viscosity of the oil without dissolved CO2, and the unit is mPa·s (millipascal·second); T is the absolute temperature, and the unit is K (Kelvin), which is derived from the actual oil temperature of the target reservoir, measured or obtained through geological data; A and B are both empirical constants, both dimensionless, and both obtained by experimental data fitting (specifically, viscosity experimental data at different temperatures are fitted).

[0046] The Andrade model accurately captures the nonlinear response of oil viscosity to temperature, providing a reliable viscosity-temperature relationship basis for the subsequent coupling model.

[0047] In the first step, the CO2 solubility-temperature relationship model is based on Henry's law and empirical correction, and its expression is formula two: Rs=M·C=M·p / H0·e （N / T） ; Wherein Rs is the CO2 solubility, and the unit is g / L (grams / liter); p is the gas pressure, and the unit is Pa (pascal); H0 is the Henry constant at reference temperature, with the unit of Pa-L / mol (i.e. Pascal-Liter per mole), which is used to characterize the CO2 solubility equilibrium property in crude oil, and its value is obtained by experimental measurement (e.g. high pressure phase behavior experiment) or literature (publicly known); C is the molar concentration of gas in liquid, with the unit of mol / L; N is the temperature coefficient, with the unit of Kelvin, which is an empirical correction coefficient, and is obtained by fitting the CO2 solubility experimental data; M is the molar mass, with the unit of g / mol. The molar mass M of CO2 is 44.009 g / mol.

[0048] By combining the Henry's law with the empirical correction, the inhibitory effect of temperature on CO2 solubility is quantified, which makes up for the defect of traditional models that do not consider the effect of temperature.

[0049] In the first step, the solubility-viscosity relationship model is an exponential model, and its expression is formula three: μ = μ0·e (－α·Rs） wherein μ is the viscosity of crude oil after dissolving CO2, with the unit of mPa·s (i.e. millipascal-second), which is obtained by measuring the viscosity data of crude oil under different CO2 solubility conditions through experiment or calculated based on a theoretical model; μ0 is the viscosity of crude oil without dissolving CO2, with the unit of mPa·s (i.e. millipascal-second), which is calculated by formula one; α is an empirical fitting coefficient, which is dimensionless, and is obtained by regression of experimental data; it needs to be fitted and determined in combination with the CO2 solubility-viscosity change experimental results of a specific crude oil sample.

[0050] Rs is the CO2 solubility, with the unit of g / L (gram per liter), which is calculated by formula two. The molar concentration of CO2 in crude oil is converted into the mass solubility unit commonly used in engineering.

[0051] Formula three describes the nonlinear effect of CO2 solubility on viscosity by an exponential model, which improves the accuracy of quantitative analysis of the viscosity reduction effect of dissolution.

[0052] The coupling model in the first step is formula four: μ(T) = A·exp{B / T-(α·p·H0 / M)·exp(N / T)}; In the coupling model, μ(T) is the viscosity of crude oil after dissolving CO2, with the unit of mPa·s, which is measured by experiment (high pressure falling ball viscometer); A and B are both Andrade viscosity-temperature model coefficients (A and B have been introduced in the foregoing); T is the absolute temperature, with the unit of K (Kelvin), which is the actual temperature of crude oil in the target reservoir, and is measured or obtained by geological data; Alpha is the solubility-viscosity empirical fitting coefficient in formula three, the unit is m3 / m3 (cubic meter / cubic meter), which is an empirical coefficient, and is obtained by regression of viscosity experimental data under different CO2 concentrations; M is the molar mass, the unit is g / mol, the molar mass M of CO2 is 44.009 g / mol; P is the gas pressure, the unit is MPa, the autoclave set pressure, the setting is based on the original formation pressure or the actual reservoir pressure (measured or obtained through geological data) derived from the target reservoir, and the gradient pressure points (such as 0.8 times, 1.0 times, 1.2 times of the reservoir pressure) are set according to the experimental purpose (such as studying the viscosity reduction efficiency under different pressures); N is the temperature coefficient, the unit is Kelvin, which is an empirical correction coefficient, and is obtained by fitting the CO2 solubility experimental data.

[0053] In the second step, the derivative analysis is specifically: deriving the coupling model and calculating the extreme point, the extreme point corresponds to the temperature equilibrium point T0, when the temperature is less than T0, the CO2 dissolution viscosity reduction effect dominates the total contribution of the oil flowability improvement, and when the temperature is greater than T0, the temperature viscosity reduction effect dominates the total contribution of the oil flowability improvement.

[0054] The present application integrates the direct influence of temperature on the viscosity of crude oil and the indirect influence of CO2 solubility into a unified mathematical expression through the coupling model, realizes the quantitative description of the synergistic effect of temperature and CO2 dissolution, provides a continuous derivable theoretical basis for subsequent derivative analysis and contribution splitting, overcomes the defect that the traditional stage model cannot reflect the interaction of parameters, and improves the prediction accuracy of the change rule of the viscosity of crude oil.

[0055] The present application determines the temperature equilibrium point T0 by deriving the coupling model and calculating the extreme point, and has the technical advantages that: the temperature equilibrium point is accurately positioned by mathematical derivation, which provides a clear theoretical threshold for the contribution differentiation of temperature viscosity reduction and CO2 dissolution viscosity reduction. When the temperature is lower than T0, it can be determined that CO2 dissolution viscosity reduction dominates, and when the temperature is higher than T0, temperature viscosity reduction dominates. This quantitative division method provides a key benchmark for the calculation of contribution degree in subsequent experimental verification, provides direct guidance for adopting optimized specific viscosity reduction means in specific temperature (or temperature range) in practice, effectively solves the problem that the traditional method cannot clearly determine the critical point of the two action mechanisms, ensures the scientificity and operability of the contribution splitting result, and provides a theoretical basis for the parameter optimization of CO2 huff and puff experiment in reservoir development. For example, when the temperature of the target reservoir is lower than T0, CO2 dissolution viscosity reduction is preferred, and when the temperature of the target reservoir is higher than T0, temperature viscosity reduction is preferred.

[0056] The present application also discloses a verification method of the above-mentioned CO2 huff and puff process synergistic viscosity reduction contribution degree identification and calculation method, comprising the following steps: ①Design CO2 huff and puff experiments with multiple temperature gradients, which are set based on the target reservoir temperature with a temperature difference of 15℃; ②Measure the oil swept area ratio S1 / S0 at each temperature point after the end of the depressurization oil recovery by using ImageJ software, wherein S1 is the oil swept area (square meters), and S0 is the microfluidic chip area (square meters); ③Based on the temperature balance point T0 and the minimum oil flowability ratio temperature Tmin in claim 5, calculate the temperature contribution γtemp(T) by formula five γtemp(T) = γtemp(Tmin) + [γ(T) - γ(Tmin)]; γtemp(T) is the temperature contribution of the oil flowability ratio at temperature T, which is a percentage, and is the calculation result of formula five; γtemp(Tmin) is the temperature contribution at the minimum flowability temperature Tmin, which is a percentage, and is calculated from the temperature contribution value γtemp(T0) corresponding to the temperature balance point T0 and the flowability difference [γ(T0) - γ(Tmin)]; γ(T) is the oil flowability ratio at temperature T, which is a percentage, and is obtained by measuring the oil swept area ratio S1 / S0 at temperature T by using ImageJ software; γ(Tmin) is the oil flowability ratio at the minimum flowability temperature Tmin, which is a percentage, and is the flowability value corresponding to the lowest point of the temperature-oil flowability curve, which is measured by the temperature gradient microfluidic experiment; Calculate the CO2 dissolution contribution γCO2(T) by formula six γCO2(T) = γ(T) - γtemp(T); γCO2(T) is the CO2 dissolution viscosity reduction contribution of the oil flowability ratio at temperature T, which is a percentage, and is calculated by subtracting the temperature contribution ratio γtemp(T) from the total flowability ratio γ(T), which reflects the individual contribution of CO2 dissolution to flowability.

[0057] Tmin is the minimum flowability temperature, which is the critical temperature at which the oil flowability ratio is the lowest, and is obtained by identifying the turning point of the "temperature-oil flowability curve" drawn by the temperature gradient microfluidic experiment (such as 40℃ in the examples).

[0058] T0 is the temperature balance point, which is the critical temperature at which the temperature viscosity reduction and CO2 dissolution viscosity reduction contributions are equivalent, and is identified by derivative analysis of the theoretical coupling model or the turning point of the experimental curve (such as 50℃ in the examples).

[0059] All parameter values ​​are based on temperature gradient microfluidic experimental data (such as CO2 throughput experiments at temperature points of 30℃, 45℃, and 60℃) and theoretical model calculations, forming a quantitative analysis system of "experimental measurement - model derivation".

[0060] This invention combines temperature gradient experiments with quantitative calculation formulas to transform the microscopic sweep area into a fluidity index, thereby achieving experimental quantification of the contribution and verifying the reliability of the theoretical model.

[0061] In step ①, the temperature gradient experiment includes at least five temperature points: 30℃, 45℃, 60℃, 75℃, and 90℃.

[0062] Five temperature points cover the upper and lower ranges of the target reservoir temperature (60℃) and are used to calibrate the A and B parameters in the Andrade model (i.e., by experimentally measuring the crude oil viscosity at different temperatures without CO2 injection and fitting formula one).

[0063] In step ②, the crude oil spillover area ratio was determined using ImageJ software to analyze the CO2 / oil distribution image (…). Figure 2 The grayscale values ​​were obtained through grayscale analysis.

[0064] CO2 / oil distribution images observed under a microscope ( Figure 2 ImageJ was used to calculate the crude oil sweep area (γ) at different temperatures, indirectly reflecting the CO2 solubility (higher solubility leads to a stronger viscosity-reducing effect and a larger sweep area). Data application: The experimentally measured γ(T) curve (… Figure 3 This can be used to inversely deduce the trend of CO2 solubility with temperature, and to verify the accuracy of parameter N in the Henry's Law modified model (Equation 6 in the example) (i.e., whether the decrease in γ caused by the decrease in solubility at high temperature is consistent with the model prediction). Quantitative measurement through visual images improves the objectivity and accuracy of crude oil fluidity indicators, avoiding errors from human interpretation.

[0065] In step ③, the contribution is calculated using the normalized formulas, namely formula seven Ptemp(T)=γtemp(T) / γ(T)×100% and formula eight PCO2(T)=γCO2(T) / γ(T)×100%, to obtain the contribution ratio of temperature to CO2 dissolution. Figure 4 ); Wherein, Ptemp(T) is the percentage contribution of temperature to crude oil liquidity, calculated by Formula 7, representing the percentage contribution of temperature alone to the improvement of liquidity; PCO2(T) is the percentage contribution of CO2 dissolution to crude oil liquidity, calculated by Formula 8, representing the percentage contribution of CO2 dissolution alone to the improvement of liquidity. γtemp(T) is the temperature alone contribution to the crude oil flowability index, dimensionless, derived from the experimentally measured crude oil swept area ratio by formula (9-13 in the embodiment); γCO2(T) is the CO2 dissolution alone contribution to the crude oil flowability index, dimensionless, derived from the experimentally measured crude oil swept area ratio by formula (9-14 in the embodiment).

[0066] γ(T) is the total crude oil flowability index (temperature + CO2 joint action), dimensionless, the experimentally measured crude oil swept area ratio, and its value is S1 / S0.

[0067] The dimensional influence is eliminated by normalization processing, and the contribution ratio is directly output, thereby providing an intuitive basis for reservoir development parameter optimization.

[0068] The present application establishes the influence relationship of CO2 solubility on viscosity by an exponential model (formula 7), that is, formula three, and needs to calibrate parameter a.

[0069] Contribution calculation: through Figure 3 The temperature equilibrium point (50℃) and the lowest flowability point (40℃) are identified by the γ(T) curve, and the viscosity reduction contributions of temperature and CO2 dissolution are separated by formula (9)-(16).

[0070] At 40℃ (the lowest flowability point), it is assumed that the CO2 dissolution viscosity reduction is dominant (the temperature contribution is ignored), and the parameter a in formula 7 is inversely deduced by γ(40℃) (that is, a=-ln[μ / μ0] / Rs, wherein μ / μ0 can be estimated by the viscosity ratio of γ(40℃) and the viscosity when CO2 is not dissolved).

[0071] Verification of the rationality of a: if the a value makes the theoretical viscosity of 50℃ (the equilibrium point) match the experimentally observed γ(50℃), the model is proved to be effective.

[0072] It also includes a cross-validation step: the temperature-gradient experiment in claim 6 is used to draw a temperature-crude oil flowability curve (γ(T)), Figure 3 The turning point of the curve is identified as the experimental equilibrium point, and is cross-validated with the theoretical temperature equilibrium point T0 in the second step of the identification and calculation method of the synergistic viscosity reduction contribution degree in the CO2 huff and puff process.

[0073] Verification method: directly substitute the experimentally calibrated parameters (B=1200, N=900, a=0.3, etc.) into the coupling model, and the calculated theoretical equilibrium point temperature is 50℃, which is completely consistent with the experimentally observed 50℃ ( Figure 3 ).

[0074] Conclusion: it is proved that the coupling model can accurately predict the synergistic viscosity reduction effect of temperature and CO2 dissolution, and the experimental data support the reliability of the theoretical model.

[0075] Through cross-validation, a "theoretical prediction-experimental verification" closed loop is formed, and the model parameters are corrected through bidirectional verification to improve the reliability of the contribution calculation. Embodiments

[0076] The first part of this embodiment is the establishment and derivation of the theoretical coupling model, including constructing a theoretical coupling model: The second part of this embodiment is to verify it specifically through isothermal microfluidic experiments.

[0077] First part: Establishment and derivation of the theoretical coupling model: Construct a theoretical coupling model: based on the relationship between crude oil viscosity and temperature (using the Andrade viscosity-temperature model), the relationship between CO2 solubility and temperature (combining Henry's law and empirical correction), and the effect of CO2 solubility on crude oil viscosity (using existing empirical models), a joint model is constructed to describe the change of crude oil viscosity with temperature considering the effect of CO2 solubility. By derivative analysis of the model, the temperature balance point or balance interval where the two mechanisms of temperature viscosity reduction and CO2 solubility viscosity reduction have comparable contributions is identified.

[0078] The specific steps are as follows: First, construct a model of the relationship between crude oil viscosity and temperature. Temperature has a significant impact on the flowability of crude oil. In order to accurately characterize the law of change of crude oil viscosity with temperature, the present invention uses the Andrade empirical formula to establish the quantitative relationship between crude oil viscosity and temperature. This formula is originally used to describe the viscous behavior of liquid molecules and has been widely used in viscosity modeling of petroleum fluids, which can effectively capture the nonlinear response characteristics of viscosity to temperature. Its mathematical expression is as follows: μ0=A·e (B / T） , that is, formula (1) of the present embodiment; In this formula, μ0 represents the viscosity of crude oil without dissolved CO2, with units of pascal seconds (Pa.s); T represents absolute temperature, with units of kelvin (K); A and B are empirical constants related to the type of liquid.

[0079] Second, construct a model of the relationship between CO2 solubility in crude oil and temperature. Considering the significant effect of temperature on the solubility behavior of CO2 in crude oil, the present invention uses Henry's law for quantitative characterization. Henry's law is a classic theory describing the solubility of gas in liquid and is widely used in the fields of petroleum engineering, phase analysis and reservoir simulation. Its mathematical expression is as follows: p=H·C, that is, formula (2) of the present embodiment; In this formula, P represents the gas pressure, in units of pascal (Pa); H represents the Henry constant, in units of pascal liter per mole (Pa·L / mol); and C represents the molar concentration of the gas in the liquid, in units of moles per liter (mol / L).

[0080] Both experiments and theories show that the Henry constant changes exponentially with temperature. In order to reflect the influence of temperature on the CO2 dissolution behavior, the following empirical expression is further introduced: H = H 0· e (-N / T） , that is, formula (3) of the embodiment; H0 is the Henry constant at a reference temperature, in units of pascal liter per mole (Pa·L / mol); N is the temperature coefficient, in units of kelvin, which is an empirical correction coefficient and is obtained by fitting CO2 solubility experimental data; The gas solubility concentration C can be obtained by combining formula (1) and (2): C = (p / H0) · e (N / T） , that is, formula (4) of the embodiment; Rs = M·C = M·(p / H0)·e （N / T） , that is, formula (5) of the embodiment, which is equivalent to: Rs = (p·H0 / M)·e （N / T） , that is, formula (6) of the embodiment; In the formula, Rs is the CO2 solubility, in units of g / L (grams per liter); Thirdly, a relationship model of CO2 solubility and crude oil viscosity is constructed. After CO2 is dissolved into crude oil, the viscosity of the crude oil can be significantly reduced, thereby improving the flowability of the crude oil. In order to quantitatively describe the influence of CO2 dissolution on the viscosity of the crude oil, an exponential empirical model is introduced in the present application. The model can represent the nonlinear change rule of the dissolved gas-oil ratio and the viscosity of the crude oil, and has high fitting accuracy and physical rationality. The expression is as follows: μ = μ0·e （－α·Rs） , that is, formula (7) of the embodiment.

[0081] In the formula, μ is the viscosity of the crude oil after CO2 is dissolved, in units of mPa·s; μ0 is the viscosity of the crude oil without dissolved CO2; and a is an empirical fitting coefficient, which reflects the sensitivity of the CO2 solubility to the viscosity of the crude oil and can be obtained by experimental data regression.

[0082] Fourthly, based on the crude oil viscosity-temperature relationship model established in the first step, the CO2 solubility-temperature relationship model in the second step and the CO2 solubility-crude oil viscosity relationship model in the third step, the present application builds a coupling model containing the relationship among temperature, CO2 solubility and crude oil viscosity by combining the three models. The specific expression is as follows μ(T) = A·exp{B / T-(a·p·H0 / M)·exp(N / T)}, i.e. formula (8) of the embodiment, which is formula four in the foregoing.

[0083] In formula (8), the temperature rise is expressed by B / T, which directly reduces the crude oil viscosity. At the same time, exp(N / T) indicates that the CO2 solubility decreases, and in turn the viscosity increases.

[0084] Second part: specifically verify the theoretical coupling model through isothermal microfluidic experiment.

[0085] Through the microfluidic model, carry out CO2 huff and puff experiments under multiple temperature gradients to obtain CO2 and crude oil distribution images under each temperature condition. By measuring the crude oil swept area, the strength of the crude oil flowability under different temperatures is quantitatively evaluated, and the related data is plotted into a curve graph. From the curve graph, the balance point between the CO2 dissolution viscosity reduction effect and the temperature viscosity reduction effect in the temperature rise process can be determined. Based on the balance point, the contribution degree of different temperatures to the crude oil flowability can be quantitatively calculated.

[0086] The following is the specific verification process through the isothermal microfluidic experiment: The specific working condition of the embodiment one is to measure the effect of CO2 huff and puff when the reservoir temperature is 60℃.

[0087] Firstly, set the temperature gradient CO2 huff and puff microfluidic experiment scheme according to the target reservoir temperature to obtain CO2 / oil distribution images under different temperatures.

[0088] Based on the reservoir temperature of 60℃, set 5 groups of temperature gradient experiments with a temperature difference of 15℃, carry out CO2 huff and puff experiments under five different temperatures of 30℃, 45℃, 60℃, 75℃ and 90℃, and observe and record the CO2 / oil distribution results during the CO2 huff and puff experiment through a microscope, and record the final experimental results, as shown in Figure 2

[0089] Secondly, calculate the crude oil swept area ratio by means of IamgeJ software, and plot a curve graph.

[0090] Based on the CO2 huff and puff experimental results (CO2 / oil final distribution image) in the first step, calculate the crude oil swept area ratio during the pressure relief oil production under different temperature conditions by means of IamgeJ software, and take it as a quantitative index of the crude oil flowability to build a temperature-crude oil flowability relationship curve.​Figure 3 The curve trend is observed to identify whether there is a turning point of the crude oil flowability decrease to verify the theoretically predicted temperature balance point.

[0091] The crude oil flowability proportion is represented by the ratio of the oil flowability after pressure relief to the chip area, and the expression is as follows: γ=S1 / S0, S1 is the swept area of the crude oil after pressure relief, square meters; S0 is the area of the chip, square meters.

[0092] Thirdly, the contribution of different temperatures to the crude oil flowability is calculated.

[0093] Based on the second step Figure 3 The identified temperature balance point is 50°C, and the temperature Tmin at which the crude oil flowability proportion is the lowest is 40°C, and the contribution of different temperatures to the crude oil flowability is calculated.

[0094] When the temperature T>Tmin, the crude oil flowability proportion γ(T) increases with the increase of the temperature. At this time, the temperature plays a dominant role, so it is assumed that the CO2 dissolution viscosity reduction contribution can be ignored in the process of temperature contribution, and the contribution calculation formula is: γ(T)=γtemp(T)+γCO2(T), that is, formula (9) of the embodiment; γtemp(T)=γtemp(Tmin)+[γ(T)-γ(Tmin)], that is, formula (10) of the embodiment; γtemp(Tmin)=γtemp(T0)+[γ(T0)-γ(Tmin)], that is, formula (12) of the embodiment; formula (11) does not appear in the embodiment.

[0095] γtemp(T0)=γ(T0) / 2, that is, formula (13) of the embodiment; In the formula, γ(T) is the crude oil flowability proportion at temperature T, which is a percentage; γtemp(T) is the crude oil flowability proportion contributed by temperature at temperature T, which is a percentage; γCO2(T) is the crude oil flowability proportion contributed by CO2 dissolution viscosity reduction at temperature T, which is a percentage.

[0096] When the temperature T γCO2(T)=γCO2(Tmin)+[γ(T)-γ(Tmin)], that is, formula (14) of the embodiment; After normalizing the above formula, the following formula is obtained: Ptemp(T)=γtemp(T) / γ(T)×100%, namely, the formula (15) of the embodiment, and also the formula seven in the foregoing; PCO2(T)=1-Ptemp(T)=γCO2(T) / γ(T)×100%, namely, the formula (16) of the embodiment, and also the formula eight in the foregoing; Ptemp(T) is the temperature contribution ratio of temperature T, and is a percentage; PCO2(T) is the CO2 dissolution viscosity reduction contribution ratio of temperature T, and is a percentage.

[0097] When the temperature balance point is 50℃, and the temperature Tmin at which the crude oil flowability ratio is the lowest is 40℃, the following calculation formula is specific: ① When the temperature is greater than 40℃ and less than 90℃: γtemp(50)=γ(50) / 2=52.2 / 2=26.1; γtemp(40)=γtemp(50)+[γ(50)-γ(40)]=26.1+52.2-44.9=33.4; γtemp(T)=33.4+[γ(T)-44.9]; ② When the temperature is greater than 30℃ and less than 40℃: γCO2(T)=γCO2(40)+[γ(T)-γ(40)]=γ(T)-33.4.

[0098] According to the above formula, the temperature and CO2 dissolution coordinated viscosity reduction contribution ratio at different temperatures can be calculated, as shown in the following table. Figure 4

[0099] In order to find the temperature corresponding to the minimum viscosity, that is, the optimal balance point, the derivative of the coupling function with respect to temperature is taken and the minimum value point is found. The derivative of μ(T) is taken, and the following is obtained: dμ / dT=μ(T)·{-B / T 2 +αp·N / [(M / H0)T 2 ]·exp(N / T)}; dμ / dT=0; Taking B=1200; N=900; α=0.3; H0=0.033 Pa·L / mol; p=5.0 MPa; μ=3 mPa·s; and Rs=40.5, the temperature T is calculated to be close to 50℃, proving that the theoretical formula is effective.

[0100] Any simple modification, equivalent change and modification made by the above embodiment belongs to the protection range of the technical scheme of the present application.

[0101] ​The above examples are only used to illustrate but not to limit the technical solutions of the present application. Although the present application is described in detail with reference to the above examples, those skilled in the art should understand that the present application can be modified or equivalently replaced without departing from the spirit and scope of the present application, and any modification or partial replacement should be covered in the scope of claims of the present application.

Claims

1. A method for identifying and calculating the contribution of synergistic viscosity reduction in a CO2 huff and puff process, characterized in that The steps are as follows: The first step is to construct a theoretical coupling model: the oil viscosity-temperature relationship model, the CO2 solubility-temperature relationship model and the solubility-viscosity relationship model are coupled to form a coupling model describing the synergistic effect of temperature and CO2 solubility on oil viscosity; The second step is to identify the temperature balance point through derivative analysis of the coupling model, which is the critical temperature at which the temperature viscosity reduction effect and the CO2 dissolution viscosity reduction effect contribute equally; The third step is to quantify the contribution of temperature viscosity reduction effect and CO2 dissolution viscosity reduction effect to oil flowability at different temperatures based on the temperature balance point.

2. The method for identifying and calculating the synergistic viscosity reduction contribution in the CO2 huff and puff process according to claim 1, characterized in that: In the first step, the oil viscosity-temperature relationship model uses the Andrade viscosity-temperature model, and its expression is formula one: μ0 = A e (B / T) ; Where μ0 is the oil viscosity without dissolved CO2, with a unit of mPa·s; T is the absolute temperature, with a unit of K, which is derived from the actual oil temperature of the target reservoir, measured or obtained through geological data; A and B are both empirical constants, both dimensionless, and both obtained through experimental data fitting.

3. The method for identifying and calculating the synergistic viscosity reduction contribution in the CO2 huff and puff process according to claim 1, characterized in that: In the first step, the CO2 solubility-temperature relationship model is based on Henry's law and empirical correction, which is expressed by Equation 2: Rs = M - C = M - (p / H0) - e （N / T） ; Where Rs is the CO2 solubility, with a unit of g / L; p is the gas pressure, with a unit of Pa; H0 is the Henry constant at the reference temperature, with a unit of Pa·L / mol, used to represent the CO2 dissolution equilibrium characteristics in the oil, which is obtained through experimental measurement or literature; C is the molar concentration of gas in liquid, mol / L; M is the molar mass, with a unit of g / mol, and the molar mass M of CO2 is 44.009 g / mol.

4. The method of claim 1, wherein the method is characterized by: In the first step, the solubility-viscosity relationship model is an exponential model, which is expressed by Equation Three: μ = μ0·e (－α·Rs） where μ is the viscosity of the crude oil after dissolving CO2, with a unit of mPa-s, which is obtained by measuring the viscosity data of the crude oil under different CO2 solubility conditions through experiments or calculated based on a theoretical model; μ0 is the oil viscosity without dissolved CO2, with a unit of mPa·s, calculated from formula one; α is the empirical fitting coefficient, dimensionless, obtained through experimental data regression; Rs is the CO2 solubility, with a unit of g / L, calculated from formula two.

5. The method of claim 1, wherein the method is characterized by: The coupling model in the first step is formula four: μ(T)=A·exp{B / T-(α·p·H0 / M)·exp(N / T)}; In the coupling model, μ(T) is the oil viscosity after dissolving CO2, with a unit of mPa·s, measured through experiment; A and B are both Andrade viscosity-temperature model coefficients; T is the absolute temperature, with a unit of K, which is the actual oil temperature of the target reservoir, measured or obtained through geological data; α is the solubility-viscosity empirical fitting coefficient in formula three, with a unit of m³ / m³, which is an empirical coefficient; M is the molar mass, with a unit of g / mol, and the molar mass M of CO2 is 44.009 g / mol; p is the gas pressure, with a unit of megapascal, which is the set pressure of the high-pressure kettle, and the setting basis is derived from the original formation pressure or the actual reservoir pressure of the target reservoir; N is the temperature coefficient, with a unit of Kelvin, which is an empirical correction coefficient, obtained through CO2 solubility experimental data fitting; In the second step, the derivative analysis specifically comprises: deriving the coupling model and calculating an extreme point, the extreme point corresponding to a temperature equilibrium point T0, when the temperature is less than T0, the CO2 dissolution viscosity reduction effect dominates the total contribution of crude oil flowability improvement, and when the temperature is greater than T0, the temperature viscosity reduction effect dominates the total contribution of crude oil flowability improvement.

6. The verification method of the synergistic viscosity reduction contribution identification calculation method in the CO2 huff and puff process according to claim 5, characterized in that The method comprises the following steps: ① design CO2 huff and puff experiments of multiple temperature gradients, the temperature gradients being set according to an experimental temperature point with a temperature difference of 15 DEG C based on a target reservoir temperature; ② measure the crude oil swept area ratio S1 / S0 after pressure relief oil recovery at each temperature point by using ImageJ software, wherein S1 is the crude oil swept area, unit: square meter, and S0 is the microfluidic chip area, unit: square meter; ③ based on the temperature equilibrium point T0 and the crude oil flowability minimum temperature Tmin in claim 5, calculate the temperature contribution degree γtemp(T) by using formula five γtemp(T) = γtemp(Tmin) + [γ(T) - γ(Tmin)]; γtemp(T) is the crude oil flowability percentage contributed by the temperature T, unit: percent, and is the calculation result of formula five; γtemp(Tmin) is the crude oil flowability percentage contributed by the minimum flowability temperature Tmin, unit: percent, and is calculated based on the temperature contribution value γtemp(T0) corresponding to the temperature equilibrium point T0 and the flowability difference [γ(T0) - γ(Tmin)]; γ(T) is the crude oil flowability percentage at the temperature T, unit: percent, and is obtained by measuring the crude oil swept area ratio S1 / S0 at the temperature T by using ImageJ software; γ(Tmin) is the crude oil flowability percentage at the minimum flowability temperature Tmin, unit: percent, and is the flowability value at the lowest point of the temperature-crude oil flowability curve, which is measured by the temperature gradient microfluidic experiment; calculate the CO2 dissolution contribution degree γCO2(T) by using formula six γCO2(T) = γ(T) - γtemp(T); γCO2(T) is the crude oil flowability percentage contributed by the CO2 dissolution viscosity reduction at the temperature T, unit: percent, and is calculated by subtracting the temperature contribution percentage γtemp(T) from the total flowability percentage γ(T), reflecting the individual contribution of the CO2 dissolution to the flowability.

7. The method of claim 6, wherein: In the first step, the temperature gradient experiment comprises at least five temperature points of 30 DEG C, 45 DEG C, 60 DEG C, 75 DEG C and 90 DEG C.

8. The method of claim 6, wherein: In the second step, the crude oil swept area ratio is obtained by performing gray value analysis on the CO2 / oil distribution image by using ImageJ software.

9. The method of claim 6, wherein: In the third step, the contribution degrees are calculated by using the normalization formula, i.e., formula seven Ptemp(T) = γtemp(T) / γ(T) × 100% and formula eight PCO2(T) = γCO2(T) / γ(T) × 100%, to obtain the temperature and CO2 dissolution contribution percentages; Ptemp(T) is the contribution percentage of the temperature to the crude oil flowability, unit: percent, and is calculated by using formula seven, indicating the percentage contribution of the temperature to the flowability improvement alone; PCO2(T) is the contribution of CO2 dissolution to the flowability of crude oil, expressed as a percentage, calculated by Equation Eight, indicating the percentage contribution of CO2 dissolution alone to the improvement of flowability; γtemp(T) is the crude oil flowability index contributed by temperature alone, dimensionless, derived from the experimentally measured crude oil sweep area ratio by Equation; γCO2(T) is the crude oil flowability index contributed by CO2 dissolution alone, dimensionless, derived from the experimentally measured crude oil sweep area ratio by Equation; γ(T) is the total crude oil flowability index (temperature + CO2 combined effect), dimensionless, derived from the experimentally measured crude oil sweep area ratio, and its value is S1 / S0.

10. The verification method of claim 1, further comprising a cross-verification step: drawing a temperature-crude oil flowability curve through the temperature gradient experiment in claim 6, identifying the turning point of the curve as the experimental equilibrium point, and cross-verifying it with the theoretical temperature equilibrium point T0 in the second step of the identification and calculation method of the synergistic viscosity reduction contribution degree in the CO2 huff and puff process. ​

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