Method and device for evaluating wettability of CO2-water-oil-shale multiphase system

Abstract

According to the CO2-water-oil-shale multi-phase system wettability evaluation method and device, a traditional contact angle measurement method and the nuclear magnetic resonance technology are combined, the defect that micro-nano scale pore wettability cannot be quantitatively studied through the contact angle measurement method is overcome, and the accuracy of the shale pore scale wettability through the nuclear magnetic resonance technology is enhanced; the method comprises the following steps: simulating a high-temperature and high-pressure environment of a shale reservoir, establishing a CO2-water-oil-shale multiphase coexistence system, realizing comprehensive evaluation of the wettability of the shale reservoir by combining a macro scale and a micro scale, and realizing fine characterization of the wettability from the macro scale to the micro scale; and the method for accurately evaluating the wettability of the shale reservoir in the CO2-enhanced shale oil and gas reservoir development and geological burying process is created. The scheme is simple, convenient, efficient, accurate, comprehensive and high in applicability, lays a solid foundation for CO2 large-scale shale oil and gas reservoir development and CO2 long-term storage, and has a wide application prospect.

Description

Technical Field

[0001] This application relates to the field of oil and gas exploration and development technology, and in particular to a method and apparatus for evaluating the wettability of CO2-water-oil-shale multiphase systems. Background Technology

[0002] Compared to conventional reservoirs, shale reservoirs exhibit well-developed micro- and nano-pores, complex mineral composition, and significant capillary effects, making their development more challenging. CO2 has been widely proven to be an effective carrier for the efficient development of shale oil and gas resources. During long-term development, the injection of CO2 into shale reservoirs not only creates a complex phase environment where CO2, water, oil, and shale coexist, but also leads to a series of interactions between reservoir rocks and fluids. These changes directly affect the wettability of shale reservoirs. Wettability is the macroscopic manifestation of the interfacial interaction between formation fluids and reservoir rocks, and a key factor controlling fluid flow, displacement mechanisms, and spatial distribution characteristics. It directly determines the effectiveness of CO2-enhanced shale oil and gas reservoir development and CO2 geological sequestration.

[0003] Extensive research has revealed that the main methods for evaluating interfacial wetting characteristics include contact angle measurement, Amott method, USBM method, Amott / USBM combined method, and spontaneous percolation method. Due to its intuitiveness and convenience, contact angle measurement is one of the most commonly used methods for characterizing shale wettability. The contact angle measurement methods for shale after CO2 treatment can be mainly divided into two categories: (1) Indirect method: CO2 is continuously injected into a reaction vessel containing a sufficient amount of solution, and then flaky or powdered shale samples are immersed under high temperature and high pressure conditions. After removal, the contact angle is measured at room temperature and pressure; (2) Direct method: The contact angle is directly tested in a CO2 gas environment, and the wettability of the rock is studied by changing the temperature and pressure.

[0004] However, unlike conventional oil and gas reservoirs, shale, as a source rock, is rich in organic matter and has a complex mineral composition. It also develops oleophilic organic matter pores and hydrophilic inorganic mineral pores. Therefore, shale exhibits strong wetting heterogeneity at the microscale.

[0005] While indirect contact angle measurement of shale after CO2 exposure can simulate the high-temperature and high-pressure environment of the formation, it cannot directly establish a CO2-water-oil-rock multiphase system, resulting in discrepancies with actual reservoir conditions. Direct contact angle measurement, although capable of establishing a multiphase coexistence system, does not consider the changes in physicochemical properties such as reservoir mineral composition caused by long-term interaction between shale and CO2. Furthermore, contact angle measurement characterizes the macroscopic wettability of the shale surface and cannot provide quantitative statistical studies on the wettability of micro- and nano-scale pores. While nuclear magnetic resonance (NMR) technology can obtain the distribution characteristics of pore wettability in rock samples, its results are also affected by pore characteristics, fluid properties, and the interaction between pores and fluids, increasing the difficulty of characterizing shale pore-scale wettability.

[0006] Nuclear magnetic resonance (NMR), as a highly efficient, non-destructive, and rapid technique for measuring fluids and their distribution, can provide information on the distribution of fluids in nanoscale pores at the microscopic level, and the test results are unaffected by sample heterogeneity. In recent years, NMR has also been explored as an efficient method for evaluating the wettability distribution characteristics of shale pores after CO2 exposure. However, due to limitations in its testing conditions, a CO2-water-oil-rock multiphase system cannot be formed during NMR testing, and the application of NMR in wettability characterization during CO2-enhanced oil and gas extraction and geological storage remains incomplete.

[0007] Currently, there are relatively few methods applicable to measuring the wettability of shale reservoirs, and each method has its own limitations. The complex distribution and phase changes of reservoir fluids after CO2 injection in shale oil and gas reservoirs further increase the difficulty of comprehensive wettability assessment, thereby affecting the effectiveness of CO2-enhanced shale oil and gas reservoir development and CO2 geological sequestration. Summary of the Invention

[0008] This specification provides a method and apparatus for evaluating the wettability of CO2-water-oil-shale multiphase systems, providing a method applicable to evaluating the wettability of CO2-water-oil-shale multiphase systems with heterogeneous wettability and micro / nano-scale pores.

[0009] To address the aforementioned technical problems, the first aspect of this specification provides a method for evaluating the wettability of a CO2-water-oil-shale multiphase system, comprising: continuously monitoring the pressure, temperature, and density of the fluid mixture within the high-pressure unit during the construction of a high-temperature, high-pressure CO2-water-oil-shale multiphase system based on a first shale sample and conducting a high-temperature, high-pressure multiphase contact angle experiment, and continuously capturing images using a high-resolution optical camera; calculating the water wetting angle and oil wetting angle based on the monitoring results and captured images, and further calculating contact angle wettability parameters based on the water wetting angle and oil wetting angle; calculating contact angle correction parameters, and using the contact angle... The contact angle wettability parameters were corrected using the following methods: During the NMR experiment on the second shale sample, the mass of the second shale sample was obtained after each operational step; based on the mass of the second shale sample after each operation, the water and oil absorption of the second shale sample after CO2 treatment during the NMR experiment were calculated, and the NMR wettability parameters were calculated based on the water and oil absorption; the NMR correction index was calculated and used to correct the NMR wettability parameters; the wettability of the CO2-water-oil-shale multiphase system was evaluated based on the corrected contact angle wettability parameters and the corrected NMR wettability parameters.

[0010] In some embodiments, constructing a high-temperature, high-pressure multiphase system of CO2-water-oil-shale for the first shale sample and conducting a high-temperature, high-pressure multiphase contact angle experiment includes: cleaning all components of the apparatus with ethanol and distilled water; polishing the first shale sample with diamond abrasive and cleaning it with ethanol; placing the sheet-like first shale sample into a molecular vacuum pump to saturate formation water under high pressure and high temperature; placing the first shale sample on a movable magnetic device and placing it inside a high-temperature, high-pressure model, while simultaneously raising the temperature to the required value; opening the water injection valve and using the first injection pump to inject reservoir brine into the high-temperature, high-pressure model until the container is full, then closing the water injection valve; opening the gas injection valve, and through the first injection pump... A constant-pressure / constant-flow pump is used to slowly inject CO2 gas into a high-temperature, high-pressure model filled with brine. The model is then pressurized to a predetermined pressure at a constant temperature. After the pressure stabilizes, the oil injection valve is opened, and a drop of crude oil is dispensed onto the surface of the first shale sample via an injection needle. This completes the construction of the CO2-water-oil-shale high-temperature, high-pressure multiphase system. During this process, the pressure, temperature, and density of the fluid mixture within the high-temperature, high-pressure model are continuously monitored to calculate the interfacial tension between the phases. A high-resolution optical camera is used to continuously capture images, and axisymmetric droplet shape analysis technology is employed to evaluate droplet volume and contact angle by detecting the droplet profile and multiphase contact points.

[0011] In some embodiments, the contact angle wettability parameter is further calculated based on the water wetting angle and the oil wetting angle, including calculating the contact angle wettability parameter using the following formula: I CA =(90-θ CW ) / 90-(90-θ CO The contact angle wettability parameter is calculated by 1 / 90, where I CA θ represents the contact angle wettability parameter. CW θ represents the wetting angle of water after the action of CO2. CO Indicates the oil wetting angle after CO2 action; and / or, calculates the contact angle correction parameter, including calculating the contact angle correction parameter according to the following formula: C CA =A d / A s Calculate the contact angle correction parameters, where C CA Indicates the contact angle correction parameter, A d A represents the projected area of ​​the target fluid during the image capture process. s This represents the projected area of ​​the first shale sample during the image capture process.

[0012] In some embodiments, nuclear magnetic resonance (NMR) experiments are performed on the second shale sample, and the mass of the second shale sample after each operation step is obtained as follows: The second shale sample is subjected to a vacuum pressurization test to saturate with formation water. After saturation, the first mass m1 of the second shale sample is measured, and the NMR T2 spectrum curve of the saturated formation water second shale is obtained simultaneously. The saturated formation water second shale is loaded into a core holder, the displacement process is connected, and the saturated water second shale sample is displaced with heavy water. The NMR T2 spectrum curve is monitored during the displacement process. When the NMR T2 spectrum curve shows no signal response, the displacement is stopped, and the second mass m2 of the second shale sample is measured. The saturated heavy water second shale sample is displaced with formation crude oil to establish bound water saturation, and the amount of water displaced from the second shale sample is measured. The third mass m3 of the displaced heavy water was measured; the second shale sample was aged at the formation temperature for a predetermined time, and the nuclear magnetic resonance T2 spectrum curve of the aged second shale sample was measured, as well as the fourth mass m4 of the second shale sample; CO2 was injected into the second shale sample using a high-pressure pump, and the temperature and pressure of the second shale sample were kept the same as those in the high-temperature and high-pressure multiphase contact angle experiment. The inlet and outlet valves of the experimental device were closed to keep the second shale sample in a simmering state, and the environmental pressure of the second shale sample was recorded during the simmering process; the outlet valve was opened, and the pressure was gradually reduced to atmospheric pressure until the second shale sample no longer produced oil. Then the fifth mass m5 of the displaced heavy water and the sixth mass m6 of the displaced crude oil were measured, and the nuclear magnetic resonance T2 spectrum curve after CO2 treatment was measured.

[0013] In some embodiments, the water and oil absorption of the second shale sample after CO2 treatment during the nuclear magnetic resonance (NMR) experiment are calculated based on the mass of the second shale sample after each operation, and the NMR wettability parameters are calculated based on the water and oil absorption, including: calculating the water absorption of the second shale sample after CO2 treatment during the NMR experiment. CW =m2-m3-m5, and calculate the oil absorption of the second shale sample after CO2 treatment during the NMR experiment. CO =m4-(m2-m3)-m6; Calculate the NMR wettability parameter according to the following formula: , Where j is NMR CW ×10 j and NMR CO ×10 j The minimum value of an integer; And / or, Calculate the NMR correction index, including calculating the NMR correction index according to the following formula: , Among them, C NMRNMR correction index, TOC is the total organic carbon content of the second shale sample, M w Percentage of hydrophilic minerals, Let be the porosity of the second shale sample, and j be the value that makes C... NMR It is the smallest integer that is a pure decimal.

[0014] In some embodiments, the wettability of the CO2-water-oil-shale multiphase system is evaluated based on the modified contact angle wettability parameter and the modified nuclear magnetic resonance wettability parameter, including: calculating the comprehensive wettability parameter according to the following formula: I w =I CA ×C CA +I NMR ×C NMR , among which, I w I represents the overall wettability parameter. CA C represents the contact angle wettability parameter. CA For contact angle correction parameters, I NMR C is the NMR wettability parameter. NMR The nuclear magnetic resonance correction index is used to evaluate the wettability of the CO2-water-oil-shale multiphase system based on comprehensive wettability parameters.

[0015] In some embodiments, the wettability of the CO2-water-oil-shale multiphase system is evaluated based on the comprehensive wettability parameter, including: determining the oleophilicity and hydrophilicity of the shale reservoir based on the positive or negative sign of the comprehensive wettability parameter, including: determining the shale reservoir as hydrophilic wettability when the comprehensive wettability parameter is greater than 0; and determining the shale reservoir as oleophilic wettability when the comprehensive wettability parameter is less than 0.

[0016] In some embodiments, the wettability of the CO2-water-oil-shale multiphase system is evaluated based on a comprehensive wettability parameter, including: determining the wettability of the shale reservoir based on the absolute value of the comprehensive wettability parameter, including: determining the shale reservoir as having basic weak wettability when the absolute value of the comprehensive wettability parameter is less than the wettability threshold; and determining the shale reservoir as having strong wettability when the absolute value of the comprehensive wettability parameter is greater than or equal to the wettability threshold.

[0017] The second aspect of this specification provides a device for evaluating the wettability of a CO2-water-oil-shale multiphase system, comprising: a first experimental unit for continuously monitoring the pressure, temperature, and density of the fluid mixture within the high-pressure unit during the construction of a high-temperature, high-pressure multiphase system of CO2-water-oil-shale on a first shale sample and conducting a high-temperature, high-pressure multiphase contact angle experiment, and continuously capturing images using a high-resolution optical camera; a first calculation unit for calculating the water wetting angle and oil wetting angle based on the monitoring results and captured images, and further calculating contact angle wettability parameters based on the water wetting angle and oil wetting angle; and a second calculation unit for calculating contact angle correction parameters, and applying the contact angle correction parameters to the contact angle... The system comprises four main units: a first unit for correcting wettability parameters; a second experimental unit for obtaining the mass of the second shale sample after each operation step during the NMR experiment; a third calculation unit for calculating the water and oil absorption of the second shale sample after CO2 action during the NMR experiment based on the mass of the second shale sample after each operation, and calculating the NMR wettability parameters based on the water and oil absorption; a fourth calculation unit for calculating the NMR correction index and using the NMR correction index to correct the NMR wettability parameters; and an evaluation unit for evaluating the wettability of the CO2-water-oil-shale multiphase system based on the corrected contact angle wettability parameters and the corrected NMR wettability parameters.

[0018] In some embodiments, constructing a high-temperature, high-pressure multiphase system of CO2-water-oil-shale for the first shale sample and conducting a high-temperature, high-pressure multiphase contact angle experiment includes: cleaning all components of the apparatus with ethanol and distilled water; polishing the first shale sample with diamond abrasive and cleaning it with ethanol; placing the sheet-like first shale sample into a molecular vacuum pump to saturate formation water under high pressure and high temperature; placing the first shale sample on a movable magnetic device and placing it inside a high-temperature, high-pressure model, while simultaneously raising the temperature to the required value; opening the water injection valve and using the first injection pump to inject reservoir brine into the high-temperature, high-pressure model until the container is full, then closing the water injection valve; opening the gas injection valve, and through the first injection pump... A constant-pressure / constant-flow pump is used to slowly inject CO2 gas into a high-temperature, high-pressure model filled with brine. The model is then pressurized to a predetermined pressure at a constant temperature. After the pressure stabilizes, the oil injection valve is opened, and a drop of crude oil is dispensed onto the surface of the first shale sample via an injection needle. This completes the construction of the CO2-water-oil-shale high-temperature, high-pressure multiphase system. During this process, the pressure, temperature, and density of the fluid mixture within the high-temperature, high-pressure model are continuously monitored to calculate the interfacial tension between the phases. A high-resolution optical camera is used to continuously capture images, and axisymmetric droplet shape analysis technology is employed to evaluate droplet volume and contact angle by detecting the droplet profile and multiphase contact points.

[0019] In some embodiments, the contact angle wettability parameter is further calculated based on the water wetting angle and the oil wetting angle, including calculating the contact angle wettability parameter using the following formula: I CA =(90-θ CW ) / 90-(90-θ CO The contact angle wettability parameter is calculated by 1 / 90, where I CA θ represents the contact angle wettability parameter. CW θ represents the wetting angle of water after the action of CO2. CO Indicates the oil wetting angle after CO2 action; and / or, calculates the contact angle correction parameter, including calculating the contact angle correction parameter according to the following formula: C CA =A d / A s Calculate the contact angle correction parameters, where C CA Indicates the contact angle correction parameter, A d A represents the projected area of ​​the target fluid during the image capture process. s This represents the projected area of ​​the first shale sample during the image capture process.

[0020] In some embodiments, nuclear magnetic resonance (NMR) experiments are performed on the second shale sample, and the mass of the second shale sample after each operation step is obtained as follows: The second shale sample is subjected to a vacuum pressurization test to saturate with formation water. After saturation, the first mass m1 of the second shale sample is measured, and the NMR T2 spectrum curve of the saturated formation water second shale is obtained simultaneously. The saturated formation water second shale is loaded into a core holder, the displacement process is connected, and the saturated water second shale sample is displaced with heavy water. The NMR T2 spectrum curve is monitored during the displacement process. When the NMR T2 spectrum curve shows no signal response, the displacement is stopped, and the second mass m2 of the second shale sample is measured. The saturated heavy water second shale sample is displaced with formation crude oil to establish bound water saturation, and the amount of water displaced from the second shale sample is measured. The third mass m3 of the displaced heavy water was measured; the second shale sample was aged at the formation temperature for a predetermined time, and the nuclear magnetic resonance T2 spectrum curve of the aged second shale sample was measured, as well as the fourth mass m4 of the second shale sample; CO2 was injected into the second shale sample using a high-pressure pump, and the temperature and pressure of the second shale sample were kept the same as those in the high-temperature and high-pressure multiphase contact angle experiment. The inlet and outlet valves of the experimental device were closed to keep the second shale sample in a simmering state, and the environmental pressure of the second shale sample was recorded during the simmering process; the outlet valve was opened, and the pressure was gradually reduced to atmospheric pressure until the second shale sample no longer produced oil. Then the fifth mass m5 of the displaced heavy water and the sixth mass m6 of the displaced crude oil were measured, and the nuclear magnetic resonance T2 spectrum curve after CO2 treatment was measured.

[0021] In some embodiments, the third calculation unit includes: a first calculation subunit, used to calculate the water absorption of the second shale sample after CO2 exposure during the nuclear magnetic resonance (NMR) experiment. CW =m2-m3-m5, and calculate the oil absorption of the second shale sample after CO2 treatment during the NMR experiment. CO =m4-(m2-m3)-m6; The second calculation subunit is used to calculate the NMR wettability parameter according to the following formula: , Where j is NMR CW ×10 j and NMR CO ×10 j The minimum value of an integer; And / or, The third calculation subunit is used to calculate the NMR correction index, including calculating the NMR correction index according to the following formula: , Among them, C NMR NMR correction index, TOC is the total organic carbon content of the second shale sample, M w Percentage of hydrophilic minerals, Let be the porosity of the second shale sample, and j be the value that makes C... NMR It is the smallest integer that is a pure decimal.

[0022] In some embodiments, the evaluation unit includes: a fourth calculation subunit, configured to calculate a comprehensive wettability parameter according to the following formula: I w =I CA ×C CA +I NMR ×C NMR , among which, I w Indicates the overall wettability parameter, I CA C represents the contact angle wettability parameter. CA For contact angle correction parameters, I NMR C is the NMR wettability parameter. NMR The first evaluation subunit is the NMR correction index, used to evaluate the wettability of the CO2-water-oil-shale multiphase system based on comprehensive wettability parameters.

[0023] In some embodiments, the first evaluation subunit includes a second evaluation subunit, used to determine the oleophilicity and hydrophilicity of the shale reservoir based on the positive or negative sign of the comprehensive wettability parameter, including: determining that the shale reservoir is hydrophilic wettability when the comprehensive wettability parameter is greater than 0; and determining that the shale reservoir is oleophilic wettability when the comprehensive wettability parameter is less than 0.

[0024] In some embodiments, the first evaluation subunit includes a third evaluation subunit, used to determine the wettability of the shale reservoir based on the magnitude of the absolute value of the comprehensive wettability parameter, including: determining that the shale reservoir has basically weak wettability when the absolute value of the comprehensive wettability parameter is less than the wettability threshold; and determining that the shale reservoir has strong wettability when the absolute value of the comprehensive wettability parameter is greater than or equal to the wettability threshold.

[0025] A third aspect of this specification provides an electronic device, comprising: a memory and a processor, wherein the processor and the memory are communicatively connected to each other, the memory stores computer instructions, and the processor executes the computer instructions to implement the method for evaluating the wettability of the CO2-water-oil-shale multiphase system as described in the first aspect.

[0026] A fourth aspect of this specification provides a computer storage medium storing computer program instructions, which, when executed, implement the steps of the method for evaluating the wettability of a CO2-water-oil-shale multiphase system as described in any one aspect of the first aspect.

[0027] The fifth aspect of this specification provides a computer program product comprising a computer program that, when executed by a processor, implements the steps of the method for evaluating the wettability of a CO2-water-oil-shale multiphase system as described in the first aspect.

[0028] The method and apparatus for evaluating the wettability of CO2-water-oil-shale multiphase systems provided in this specification combine traditional contact angle measurement with nuclear magnetic resonance (NMR) technology. This overcomes the limitations of contact angle measurement in quantitatively studying micro- and nano-scale pore wettability, enhancing the accuracy of NMR technology in assessing shale pore-scale wettability. By simulating the high-temperature and high-pressure environment of shale reservoirs, a CO2-water-oil-shale multiphase coexistence system is established, enabling a comprehensive evaluation of shale reservoir wettability from both macroscopic and microscopic scales, achieving refined wettability characterization from macroscopic to microscopic levels. This establishes an accurate method for evaluating shale reservoir wettability during CO2-enhanced shale oil and gas reservoir development and geological storage. This scheme is simple, efficient, accurate, comprehensive, and highly applicable, laying a solid foundation for large-scale CO2 development of shale oil and gas reservoirs and long-term CO2 storage, and has broad application prospects. Attached Figure Description

[0029] To more clearly illustrate the technical solutions in the embodiments of this application or the prior art, the drawings used in the description of the embodiments or the prior art will be briefly introduced below. Obviously, the drawings described below are only some embodiments recorded in this application. For those skilled in the art, other drawings can be obtained from these drawings without creative effort.

[0030] Figure 1 This document presents a flowchart illustrating a method for evaluating the wettability of a CO2-water-oil-shale multiphase system. Figure 2 This is a schematic diagram of a high-temperature and high-pressure interface analysis device. Figure 3 A schematic diagram of the process for constructing a high-temperature and high-pressure multiphase system of CO2-water-oil-shale and conducting a high-temperature and high-pressure multiphase contact angle experiment on the first shale sample; Figure 4 This is a schematic diagram of a CO2-water-oil-shale multiphase system. Figure 5 This is a schematic diagram of the nuclear magnetic resonance experimental setup. Figure 6 This is a schematic diagram of the process for conducting nuclear magnetic resonance experiments on the second shale sample; Figure 7 This is a schematic diagram of the CO2-water-oil-shale multiphase system on different core surfaces in one embodiment; Figure 8 This specification provides a schematic diagram of a device for evaluating the wettability of a CO2-water-oil-shale multiphase system. Figure 9 This is a structural block diagram of an electronic device provided in this specification. Detailed Implementation

[0031] To enable those skilled in the art to better understand the technical solutions in this application, the technical solutions in the embodiments of this application will be clearly and completely described below with reference to the accompanying drawings. Obviously, the described embodiments are only a part of the embodiments of this application, and not all of the embodiments. Based on the embodiments in this application, all other embodiments obtained by those skilled in the art without creative effort should fall within the scope of protection of this application.

[0032] The wetting heterogeneity of shale refers to the significant differences in the affinity of different regions of shale for oil and water at the microscopic scale, rather than the shale exhibiting a uniform hydrophilic or oleophilic property as a whole. This heterogeneity is mainly determined by the microscopic composition and porosity characteristics of shale, and can be understood from the following three aspects: 1. Pore type determines local wettability: Shale contains two types of core pores: oleophilic organic matter pores and hydrophilic inorganic mineral pores. The former, due to the properties of the organic matter itself, is more likely to adsorb the oil phase; the latter, due to the charged properties of the mineral surface, is more likely to adsorb the water phase.

[0033] 2. Microscopic regional preferences: Under a microscope, the organic matter patches and inorganic mineral grains in shale are interspersed. This results in adjacent micro-regions having different wettability, with one region being hydrophilic and the other oleophilic.

[0034] 3. Lack of overall properties: Conventional oil and gas reservoirs may be generally hydrophilic or oleophilic, but shale, due to the interweaving of the two types of pores and components mentioned above, cannot be defined as "generally hydrophilic" or "generally oleophilic". It can only be said that the wettability varies significantly at different locations on a microscopic scale.

[0035] Existing conventional wettability evaluation methods are mainly based on conventional oil and gas reservoir design, and are difficult to fully adapt to the strong microscopic heterogeneity, nanoscale porosity, and C content of shale. The complex environment under its influence. The following is a detailed analysis of why existing conventional wettability evaluation methods are not applicable to shale.

[0036] I. Contact Angle Measurement Method: "Accuracy Deviation" in Microscopic Characterization.

[0037] 1. Although the contact angle measurement method (including indirect and direct methods) is intuitive, it has two core limitations in shale evaluation: (1) Indirect method: environmental distortion leads to inaccurate results. Specifically, the indirect method requires the contact angle under high temperature and high pressure to be compared with C The reacted sample was removed and its contact angle was measured at room temperature and pressure. During this process, the sudden drop in temperature and pressure caused the carbon adsorbed on the shale surface to... Desorption, intrapore fluids (such as dissolved C) (1) Changes in the state of the aqueous solution can even cause micro-dissolution or precipitation of minerals on the shale surface, directly altering the original wettability of the rock and causing a large deviation between the measured values ​​and the actual underground state. (2) Direct method: technical bottlenecks and insufficient simulation. Specifically, although the direct method can perform in-situ testing, high temperature and high pressure (such as pressure above 10MPa and temperature above 100℃ under formation conditions) can increase the risk of test equipment failure. For example, the observation lens is easily damaged by C. Impurities generated from the reaction with shale contaminate the contact angle readings; meanwhile, it is difficult to completely reproduce the underground "C" formation in the laboratory. The multiphase coexistence state of "crude oil-formation water-shale" is often simplified to "C The "single liquid-shale" system ignores the true impact of formation water ion composition and crude oil composition on wettability.

[0038] II. Amott Method and USBM Method: "Lack of Representativeness" in Macroscopic Testing.

[0039] The Amott method (based on permeation) and the USBM method (based on capillary pressure curve) are classic methods for evaluating the wettability of conventional cores, but they have obvious limitations when used for shale: (1) They cannot reflect microscopic heterogeneity. Specifically, shale has an intermingled distribution of oleophilic organic matter pores and hydrophilic inorganic mineral pores, while the Amott / USBM method measures the overall "average wettability" of the core, which will mask the true wettability differences of local pores. For example, a shale may appear "leaning towards oleophilic" due to its high organic matter content, but a large number of inorganic mineral pores are actually hydrophilic. This microscopic difference is not conducive to development (such as C Oil displacement efficiency is crucial, but it cannot be captured by macroscopic methods. (2) Sample processing and testing conditions are mismatched. Specifically, shale is brittle and prone to microcracks. If microcracks are formed during the sampling process, the liquid in the Amott method may preferentially seep along the cracks rather than enter the target pores, resulting in the "seepage amount" not being able to truly reflect the pore wettability; the USBM method relies on the permeability data of the core, but the permeability of shale is extremely low (usually <0.1mD), and the capillary pressure curve test cycle is long and the error is large, which further affects the accuracy of wettability evaluation.

[0040] III. Spontaneous Immersion Method: A “Double Shortcoming” in Efficiency and Representativeness.

[0041] The spontaneous percolation method determines wettability by the rate at which a liquid is spontaneously absorbed into a rock. However, it has two major problems when applied to shale: (1) The test cycle is too long, resulting in low applicability. Specifically, shale is mainly composed of nanoscale pores, and the rate at which a liquid percolates in these pores is extremely slow (it may take several weeks or even months to reach a stable state), much longer than that of conventional sandstone (several days). In actual experiments, it is difficult to wait for the complete percolation process, and the results are often biased due to "premature termination of the test." (2) It is easily affected by impurities and mineral reactions. Specifically, organic matter in shale is easily dissolved during the percolation process (such as light components being extracted by water), changing the properties of the liquid and the state of the rock surface; at the same time, C Under the influence of the environment, clay minerals (such as montmorillonite) in shale may expand, blocking some pores and causing a decrease in permeability. This is misjudged as "weakened wettability" rather than the effect of pore blockage.

[0042] The above analysis shows that the fundamental reason why existing conventional wettability evaluation methods are unsuitable for shale is the mismatch between the evaluation logic of conventional oil and gas reservoirs and the unique properties of shale. Specifically, conventional wettability evaluation methods assume that the rock is homogeneous, has large porosity, and has uniform wettability overall, while shale has "microscopic heterogeneity + nanopores + C..." "Chemical action" breaks these assumptions, affecting the accuracy, representativeness, and efficiency of conventional wettability evaluation methods.

[0043] Nuclear magnetic resonance (NMR), as a highly efficient, non-destructive, and rapid technique for measuring fluids and their distribution, can provide information on the distribution of fluids in nanoscale pores at the microscopic level, and the test results are unaffected by sample heterogeneity. In recent years, NMR has also been attempted as an efficient method for evaluating the wettability distribution characteristics of shale pores after CO2 exposure. However, due to the following six limitations, a CO2-water-oil-rock multiphase system cannot be formed during NMR testing, thus NMR technology remains imperfect in characterizing wettability during CO2-enhanced oil and gas extraction and geological storage. These six limitations are described below: 1. Nanopores cause signal analysis failure, making it impossible to distinguish between oil and water signals.

[0044] Shale is predominantly composed of nanoscale pores (<100nm), while NMR signal resolution depends on the "difference in relaxation time between oil and water," and nanopores directly disrupt this resolution basis. This is mainly manifested in the fact that within nanopores, the contact area between the fluid (oil / water) and the pore walls is extremely large, and the longitudinal ( ), horizontal ( The relaxation time will be significantly shortened (far shorter than that of micron-sized pores in conventional sandstone), causing the relaxation peaks of oil and water to completely overlap, making it impossible to distinguish between "water in hydrophilic pores" and "oil in oleophilic pores" through signals, thus losing the core basis for wettability judgment.

[0045] The reason for this problem is that the signal resolution of NMR (spatial resolution is usually at the micrometer level) cannot be adapted to the nanopore scale of shale, and the "strong surface relaxation effect" of nanopores smooths out the relaxation differences between oil and water.

[0046] 2. Interference from organic matter hydrogen nuclei signals leads to misjudgment of oil phase distribution.

[0047] Shale is rich in organic matter (such as kerogen), and the hydrogen nuclei it contains can overlap with those in the oil phase, directly interfering with the determination of oil phase wettability. This is mainly manifested in the following way: when NMR calculates oil phase saturation using "hydrogen nuclei signal intensity," alkyl hydrogens and adsorbed hydrogens in the organic matter produce signals similar to those in crude oil. The signal peaks caused the calculated "oil phase content" to actually include contributions from organic matter, mistakenly attributing the "organic matter signal" to "oil in oleophilic pores" and overestimating the oleophilicity of shale.

[0048] The root cause of this problem is that the organic matter in shale and crude oil have similar hydrogen nuclei chemical environments and very little difference in relaxation characteristics, so NMR cannot directly distinguish between the two signals.

[0049] 3. It has a weak ability to distinguish the fluid's state of occurrence, which confuses the nature of wettability.

[0050] Fluids in shale exist in both "bound state (bound water, adsorbed oil)" and "free state (free water, free oil)," which NMR cannot directly distinguish, leading to biases in wettability assessment. The main manifestations are: ① "Bound water" on the surface of clay minerals (due to charge adsorption, unrelated to wettability) is misjudged as "free water in hydrophilic pores," overestimating hydrophilicity; ② "Adsorbed oil" in the micropores of organic matter (due to wettability adsorption, it is key to oleophilicity) is misjudged as "non-flowing bound oil," underestimating oleophilicity.

[0051] The root cause of this problem is that NMR can only distinguish fluid flowability by the length of relaxation time, but cannot correlate the causal relationship between flowability and wettability (e.g., "fast relaxation = bound state", but cannot determine whether it is adsorption caused by wettability or retention caused by pore size).

[0052] 4. Experimental operation interference amplifies errors and exacerbates misjudgment of wettability.

[0053] The unique pore structure of shale amplifies interference from NMR experimental procedures, causing the signal to deviate from the true wettability. This manifests primarily as follows: if the conventional procedure of "saturating with water first, then with oil" is followed, the hydrophilic pores of shale preferentially absorb water, forming a water film that encapsulates the oleophilic pores. This prevents the oleophilic pores from fully adsorbing crude oil—resulting in a lower-than-normal "oil absorption" reading measured by NMR, which can lead to a misinterpretation of increased hydrophilicity in shale (in reality, this is due to pore encapsulation caused by the experimental procedure, not a fundamental change in wettability).

[0054] The root cause of this problem is that the heterogeneity of shale, with its alternating distribution of hydrophilic and oleophilic pores, means that the order in which fluids are injected during the experiment directly affects the distribution of fluids in the pores. The original NMR did not consider this interference and directly used the signal results to infer wettability.

[0055] 5. High temperature and high pressure and C Poor environmental adaptability and insufficient signal stability.

[0056] If simulating underground C In the high-temperature and high-pressure environment of displacement / geological burial, the original NMR equipment stability and environmental adaptability defects will be significantly amplified. Specifically, this manifests as follows: (1) High temperature and high pressure (such as 20MPa, 80-150℃) will cause the NMR probe coil stability to decrease, signal noise to increase, relaxation time measurement error to rise from the usual 5% to more than 15%, and it will be impossible to compare C Changes in wettability before and after application; (2) C It dissolves in water to form carbonic acid, altering the ion concentration of water (accelerating relaxation), and C Carbonate mineral deposits formed by reaction with shale alter the pore structure—NMR signal changes cannot distinguish between "changes in wettability" and "changes in fluid properties / pore structure".

[0057] The root cause of this problem is that most original NMR schemes are designed for normal temperature and pressure environments, lacking equipment protection (such as temperature and pressure resistant coils) and environmental compensation algorithms adapted to high temperature and high pressure, and failing to consider C. Interference of signals caused by chemical interactions with shale.

[0058] 6. The quantitative evaluation and calibration system is lacking, making it impossible to relate to engineering requirements.

[0059] Shale composition (organic matter, minerals) and pore structure vary greatly, and primitive NMR lacks a unified wettability calibration standard, making quantitative evaluation impossible. Specifically, this manifests as: (1) No unified standard: Conventional oil and gas reservoirs use "homogeneous sandstone standard" to calibrate NMR signals, but the organic matter content and mineral composition of shale vary greatly, making it impossible to prepare "shale standard with uniform composition", and test results from different laboratories cannot be compared; (2) No quantitative correlation: Primitive NMR can only qualitatively determine "oil-loving / hydrophilic" through "oil / water signal intensity ratio", and cannot establish a quantitative correlation between "signal and wettability parameters (such as contact angle, capillary force)", thus failing to meet the C The quantitative requirements for "wetting strength" in engineering projects such as drive development.

[0060] The root cause of this problem is that the factors affecting the wettability of shale (porosity, organic matter, minerals) are far more complex than those of conventional rocks, and NMR has not established a dedicated quantitative model for "signal-wettability" for shale.

[0061] The analysis of the above six aspects shows that the core contradiction of the original NMR evaluation of shale wettability is that the technology "designed for homogeneous, micron-sized, low-organic-matter rocks" cannot be adapted to the characteristics of shale "heterogeneous, nano-sized, high-organic-matter". It is also easily affected by experimental operation and complex environment, resulting in difficulty in signal interpretation, large error and difficulty in quantification.

[0062] Based on the above analysis, it can be seen that the conventional reservoir wettability measurement methods are not applicable to shale reservoirs. The complex distribution and phase changes of reservoir fluids after CO2 injection in shale oil and gas reservoirs further increase the difficulty of comprehensive wettability evaluation.

[0063] This specification provides a method for evaluating the wettability of CO2-water-oil-shale multiphase systems. This method is applicable to evaluating the wettability of CO2-water-oil-shale multiphase systems with heterogeneous wetting characteristics and micro / nano-scale pores. Figure 1 As shown, the method includes the following steps S10 to S70.

[0064] S10: During the construction of a high-temperature and high-pressure multiphase system of CO2-water-oil-shale for the first shale sample and the high-temperature and high-pressure multiphase contact angle experiment, the pressure, temperature and density of the fluid mixture in the high-pressure unit were continuously monitored, and images were continuously captured with the help of a high-resolution camera.

[0065] Such as Figure 2 The high-temperature and high-pressure interface analysis device shown was used to conduct a high-temperature and high-pressure multiphase contact angle experiment on the first shale sample. Figure 2 11 is the high-temperature and high-pressure model. Both sides of the model have high-temperature, high-pressure, and high-transparency optical sapphire glass windows. One window faces the light source to illuminate the back of the measurement chamber inside the model, while the other window is located in front of the camera for capturing the contact angle. 12 is the high-resolution optical camera; 13 is the light source; 14 is the water bath constant temperature control module; 15 is the pressure monitoring and control module; 16 is the CO2 cylinder; 17 is the first constant pressure / constant flow pump for controlling CO2 injection; 18 is the first intermediate container for holding crude oil, brine, and formation water respectively; 19 is the first injection pump for controlling the injection of crude oil, brine, and formation water; and 110 is the first computer. This high-temperature and high-pressure interface analysis device combines high-resolution optical technology, precise liquid metering, and a precise sample positioning system, enabling simultaneous and accurate measurement of the contact angle of the CO2-water-oil-shale system under high temperature and high pressure conditions.

[0066] Constructing a high-temperature, high-pressure multiphase system of CO2-water-oil-shale from the first shale sample and conducting high-temperature, high-pressure multiphase contact angle experiments may include... Figure 3 The following steps SA1 to SA7 are shown.

[0067] SA1: Clean all components of the apparatus with ethanol and distilled water to remove any possible impurities. To minimize the impact of surface roughness on the contact angle, the first shale sample can be polished with diamond abrasive and then cleaned with ethanol.

[0068] Operating SA1 can improve the accuracy of contact angle measurements and avoid reading errors caused by surface roughness. This operation is not required for contact angle measurements of conventional rocks.

[0069] SA2: Place the sheet-like first shale sample into a molecular vacuum pump and evacuate it for a period of time (e.g., 72 hours) to fully saturate the formation water under high pressure (e.g., 20 MPa) and high temperature.

[0070] SA3: Place the first shale sample on a movable magnetic device and place it inside a high-temperature, high-pressure model, while simultaneously raising the temperature to the desired value.

[0071] SA4: Open the water injection valve and use the first injection pump to inject reservoir brine into the high-temperature and high-pressure model until the container is full. Then close the water injection valve.

[0072] SA5: Open the gas injection valve and slowly inject CO2 gas into the high-temperature and high-pressure model that is first filled with brine through the first constant pressure / constant flow pump. Pressurize the high-temperature and high-pressure model to the predetermined pressure at a constant temperature.

[0073] SA6: After the pressure in the high-temperature and high-pressure model stabilizes, the oil injection valve is opened, and a drop (e.g., about 5 μL) of crude oil is distributed onto the surface of the first shale sample through the injection needle, thus completing the construction of the CO2-water-oil-shale high-temperature and high-pressure multiphase system; during this process, the pressure, temperature and density of the fluid mixture in the high-temperature and high-pressure model are continuously monitored to calculate the interfacial tension between each phase.

[0074] SA7: Employs a high-resolution optical camera to continuously capture images and uses axisymmetric droplet shape analysis technology to evaluate droplet volume and contact angle by detecting droplet profiles and multiphase contact points.

[0075] The purpose of evaluating droplet volume is to ensure the consistency of the test. Because droplets of different volumes can affect the contact angle measurement results, contact angle measurement experiments need to use a fixed volume (e.g., 5 μL) to facilitate data comparison.

[0076] Through the operations described in SA1 to SA7 above, the shale reservoir environment under CO2 action can be completely reproduced, avoiding the wettability deviation between "normal temperature and pressure test" and the real formation; it can ensure that the contact angle measurement is based on "real multiphase state", thus making the test data more valuable for engineering reference.

[0077] S20: Calculate the water wetting angle and oil wetting angle based on the monitoring results and captured images, and further calculate the contact angle wettability parameters based on the water wetting angle and oil wetting angle.

[0078] Figure 4 This is a schematic diagram of a CO2-water-oil-shale multiphase system, where A represents crude oil, B represents formation water, C represents shale, and D represents CO2. CO，S σ represents the interfacial tension between crude oil and shale after CO2 treatment, and σ represents the interfacial tension between CO2-saturated formation water and shale. CW，CO This represents the interfacial tension between formation water saturated with CO2 and crude oil.

[0079] The interfacial tensions have the following relationship: σ CO，S =σ CW，S +σ CW，CO × cosθ, where θ represents the contact angle between shale and crude oil. Solving this relationship, we get: cosθ = (σ CO，S -σ CW，S ) / σ CW，CO .

[0080] The contact angle reflects the degree of wettability of shale in a CO2-water-oil-shale multiphase system. Specifically, when the contact angle is 0°, crude oil is completely spread on the shale surface, and the shale is completely oil-wet; when the contact angle is greater than 0° but less than 90°, the shale exhibits oleophilicity; when the contact angle is greater than or equal to 90° but less than 180°, the shale exhibits hydrophilicity; and when the contact angle is equal to 180°, the shale is completely water-wet.

[0081] Formula I can be used CA =(90-θ CW ) / 90-(90-θ CO The contact angle wettability parameter is calculated by 1 / 90, where I CA θ represents the contact angle wettability parameter. CW θ represents the wetting angle of water after the action of CO2. CO This indicates the oil wetting angle after CO2 treatment.

[0082] By calculating I CA This converts the qualitative contact angle into a quantitative parameter, enabling a quantifiable comparison of macroscopic wettability.

[0083] S30: Calculate the contact angle correction parameter and use the contact angle correction parameter to correct the contact angle wettability parameter.

[0084] The contact angle wettability parameters obtained through high-temperature, high-pressure multiphase contact angle experiments often represent the wettability of local areas in shale reservoirs. However, in reality, shale reservoir wettability is heterogeneous. Directly using these contact angle wettability parameters to evaluate shale reservoir wettability would lack accuracy. Therefore, it is necessary to use contact angle correction parameters to adjust the contact angle wettability parameters.

[0085] In some embodiments, it can be based on formula: C CA =A d / A s The contact angle correction parameters are calculated using the following formulas: water wetting angle and oil wetting angle. In these formulas, C... CA Indicates the contact angle correction parameter, A d A represents the projected area of ​​the target fluid (water when correcting for the water wetting angle; oil when correcting for the oil wetting angle) during the image capture process. s This represents the projected area of ​​the first shale sample during image capture. Here, "projected area" refers to the area projected onto the rear of the droplet; based on image analysis, the orthogonal projected area perpendicular to the surface of the first shale sample is calculated.

[0086] After obtaining the contact angle correction index C CAThis can then be corrected when evaluating the wettability of shale reservoirs to obtain more accurate evaluation results.

[0087] In some embodiments, the contact angle wettability parameter obtained from the high-temperature and high-pressure multiphase contact angle experiment can be directly multiplied by the contact angle correction parameter to obtain the corrected contact angle wettability parameter.

[0088] By calculating the contact angle correction parameter, the problem that "local contact angles cannot represent the reservoir as a whole" caused by shale heterogeneity is solved, and the evaluation of macro wettability is changed from "single-point random" to "overall objective".

[0089] S40: During the nuclear magnetic resonance experiment on the second shale sample, obtain the mass of the second shale sample after each operation step.

[0090] Such as Figure 5 The nuclear magnetic resonance experimental setup shown was used to conduct nuclear magnetic resonance experiments on the second shale sample. Figure 5 21 is a core holder for holding the second shale sample; 22 is a constant temperature chamber; 23 is a nuclear magnetic resonance instrument; 24 is a fluid measuring instrument; 25 is a second constant pressure / constant flow pump; 26 is a second intermediate container for holding crude oil, heavy water, and CO2 respectively; 27 is a second constant pressure / constant flow pump; 28 is a second injection pump; 29 is a CO2 cylinder; 210 is a pressure gauge; 210 is a second computer.

[0091] Nuclear magnetic resonance experiments on the second shale sample may include Figure 6 The following steps SB1 to SB6 are shown.

[0092] SB1: A vacuum pressurization test was conducted on the second shale sample to saturate it with formation water. After saturation, the first mass m1 of the second shale sample was measured, and the nuclear magnetic resonance T2 spectrum curve of the second shale sample saturated with formation water was obtained.

[0093] SB2: The second shale saturated with formation water is loaded into the core holder, the displacement process is connected, and the second shale sample saturated with water is displaced with heavy water. The nuclear magnetic resonance T2 spectrum curve is monitored during the displacement process. When the nuclear magnetic resonance T2 spectrum curve shows no signal response, the displacement is stopped, and the second mass m2 of the second shale sample is measured.

[0094] SB3: The second shale sample, saturated with heavy water, was used to displace the heavy water from the formation crude oil to establish bound water saturation. The third mass m3 of the heavy water displaced from the second shale sample was measured.

[0095] SB4: The displaced second shale sample is aged at the formation temperature for a predetermined time (e.g., one week), the nuclear magnetic resonance T2 spectrum curve of the aged second shale sample is measured, and the fourth mass m4 of the second shale sample is measured.

[0096] SB5: Inject CO2 into the second shale sample using a high-pressure pump. Maintain the temperature and pressure of the second shale sample at the same level as in the high-temperature and high-pressure multiphase contact angle experiment. Close the inlet and outlet valves of the experimental setup to keep the second shale sample in a simmering state. Record the environmental pressure of the second shale sample during the simmering process.

[0097] SB6: Open the outlet valve and gradually reduce the pressure to atmospheric pressure until no oil is produced from the second shale sample. Then measure the fifth mass m5 of the displaced heavy water and the sixth mass m6 of the displaced crude oil, and measure the nuclear magnetic resonance T2 spectrum curve after CO2 treatment.

[0098] Through the operations described in SB1 to SB6 above, the shale reservoir environment under CO2 action can be completely reproduced, avoiding the wettability deviation between "normal temperature and pressure test" and the real formation; it can ensure that NMR tests are based on "real multiphase state", thus making the test data more valuable for engineering reference.

[0099] S50: Calculate the water and oil absorption of the second shale sample during the nuclear magnetic resonance experiment based on the mass of the second shale sample after each operation, and calculate the nuclear magnetic wettability parameters based on the water and oil absorption.

[0100] The water and oil absorption of the second shale sample after CO2 treatment during the nuclear magnetic resonance experiment can be calculated based on the second, third, and fifth masses mentioned above. Specifically, the water absorption is calculated using NMR. CW =m2-m3-m5, oil absorption NMR CO =m4-(m2-m3)-m6.

[0101] The NMR wettability parameter can be calculated using the following formula: , Where j is NMR CW ×10 j and NMR CO ×10 j It is the minimum value of an integer.

[0102] S60: Calculate the NMR correction index and use it to correct the NMR wettability parameter.

[0103] In the aforementioned NMR experiment, the second shale sample was first treated with saturated water before being treated with saturated oil. This treatment sequence may have caused the hydrophilic pores in the second shale sample to absorb water, thereby surrounding the oleophilic pores. This situation prevents the surrounded oleophilic pores from absorbing oil, thus affecting the experimental results. Therefore, after obtaining the NMR wettability parameters, a correction index needs to be calculated to compensate for this factor.

[0104] In some embodiments, the NMR correction index can be calculated according to the following formula: , Among them, C NMR NMR correction index; TOC is the total organic carbon content of the second shale sample, which can be obtained through rock pyrolysis analysis; M w The percentage of hydrophilic minerals can be obtained through X-ray diffraction whole-rock mineral analysis experiments. The porosity of the second shale sample is denoted by ; j represents the porosity of C. NMR It is the smallest integer that is a pure decimal.

[0105] In some embodiments, the NMR wettability parameter obtained from the NMR experiment can be directly multiplied by the NMR correction index to obtain the corrected NMR wettability parameter.

[0106] Please provide other methods for calculating the NMR correction index.

[0107] S70: The wettability of the CO2-water-oil-shale multiphase system is evaluated based on the corrected contact angle wettability parameters and the corrected nuclear magnetic resonance wettability parameters.

[0108] In some embodiments, the comprehensive wettability parameter can be calculated according to the following formula: I w =I CA ×C CA +I NMR ×C NMR , among which, I w Indicates the overall wettability parameter, I CA C represents the contact angle wettability parameter. CA For contact angle correction parameters, I NMR C is the NMR wettability parameter. NMR The NMR correction index is used. Then, the wettability of the CO2-water-oil-shale multiphase system is evaluated based on this comprehensive wettability parameter.

[0109] The comprehensive wettability parameters can be used to evaluate the wettability of shale reservoirs, rather than just the wettability of a single shale sample.

[0110] This specification provides a method for evaluating the wettability of a CO2-water-oil-shale multiphase system based on comprehensive wettability parameters. In one embodiment, either of these two evaluation methods can be used.

[0111] Evaluation Method 1: Determine the oleophilicity and hydrophilicity of shale reservoirs based on the positive or negative value of the comprehensive wettability parameter, including: if the comprehensive wettability parameter is greater than 0, the shale reservoir is determined to be hydrophilic wettable; if the comprehensive wettability parameter is less than 0, the shale reservoir is determined to be oleophilic wettable.

[0112] Evaluation Method 2: Determine the wettability of shale reservoirs based on the absolute value of the comprehensive wettability parameter, including: when the absolute value of the comprehensive wettability parameter is less than the wettability threshold, the shale reservoir is determined to have basically weak wettability; when the absolute value of the comprehensive wettability parameter is greater than or equal to the wettability threshold, the shale reservoir is determined to have strong wettability. This wettability threshold can be set according to the specific circumstances of the actual application.

[0113] "Basic weak wettability" refers to the fact that shale (or rock) has a "weak selective affinity" for both oil and water fluids, showing neither a significant preference for hydrophilicity nor for oleophilicity, and its wettability is in a "neutral or weakly biased" state.

[0114] The evaluation method 1 and evaluation method 2 mentioned above can exist separately in different embodiments, or they can exist simultaneously in the same embodiment.

[0115] For example, the parameters calculated using the above method for cores A, B, and C are shown in Table 1 below. Images of the CO2-water-oil-shale multiphase system on the surfaces of cores A, B, and C are shown below. Figure 7 As shown.

[0116]

[0117] Based on the data in Table 1, the parameters shown in Table 2 below can be further calculated using the methods described above:

[0118] The evaluation results according to the above evaluation method 1 are as follows: the shale reservoirs containing cores A and B are hydrophilic shale reservoirs, while the shale reservoir containing core C is an oleophilic shale reservoir. Assuming the wettability threshold is set to 0.5 and the wettability strength threshold is 1.0, then the shale reservoirs containing cores A, B, and C are all weakly hydrophilic shale reservoirs, and the hydrophilicity of the reservoir containing core A is greater than that of the reservoir containing core B, which in turn is greater than that of the reservoir containing core C.

[0119] The method for evaluating the wettability of the CO2-water-oil-shale multiphase system provided in this specification combines traditional contact angle measurement with nuclear magnetic resonance (NMR) technology. This overcomes the limitations of contact angle measurement in quantitatively studying micro- and nano-scale pore wettability, enhancing the accuracy of NMR in assessing shale pore-scale wettability. By simulating the high-temperature and high-pressure environment of shale reservoirs, a CO2-water-oil-shale multiphase coexistence system is established, enabling a comprehensive evaluation of shale reservoir wettability from both macroscopic and microscopic scales. This allows for refined characterization of wettability from macroscopic to microscopic scales. Furthermore, it establishes an accurate method for evaluating shale reservoir wettability during CO2-enhanced shale oil and gas reservoir development and geological storage. This method is simple, efficient, accurate, comprehensive, and highly applicable, laying a solid foundation for large-scale CO2 development of shale oil and gas reservoirs and long-term CO2 storage, and has broad application prospects.

[0120] This specification also provides a device for evaluating the wettability of a CO2-water-oil-shale multiphase system, which can be used to implement the aforementioned method for evaluating the wettability of a CO2-water-oil-shale multiphase system. Figure 8 As shown, the device includes a first experimental unit 10, a first calculation unit 20, a second calculation unit 30, a second experimental unit 40, a third calculation unit 50, a fourth calculation unit 60, and an evaluation unit 70.

[0121] The first experimental unit 10 is used to continuously monitor the pressure, temperature and density of the fluid mixture within the high-pressure unit during the construction of a high-temperature and high-pressure multiphase system of CO2-water-oil-shale and the high-temperature and high-pressure multiphase contact angle experiment on the first shale sample, and to continuously capture images using a high-resolution optical camera.

[0122] The first calculation unit 20 is used to calculate the water wetting angle and the oil wetting angle based on the monitoring results and the captured images, and further calculate the contact angle wettability parameters based on the water wetting angle and the oil wetting angle.

[0123] The second calculation unit 30 is used to calculate the contact angle correction parameters, and the contact angle wettability parameters are corrected using the contact angle correction parameters.

[0124] The second experimental unit 40 is used to obtain the mass of the second shale sample after each operation step during the nuclear magnetic resonance experiment on the second shale sample.

[0125] The third calculation unit 50 is used to calculate the water and oil absorption of the second shale sample after CO2 action during the nuclear magnetic resonance experiment based on the mass of the second shale sample after each operation, and to calculate the nuclear magnetic wettability parameters based on the water and oil absorption.

[0126] The fourth calculation unit 60 is used to calculate the NMR correction index, which is used to correct the NMR wettability parameter.

[0127] Evaluation unit 70 is used to evaluate the wettability of the CO2-water-oil-shale multiphase system based on the corrected contact angle wettability parameter and the corrected nuclear magnetic resonance wettability parameter.

[0128] In some embodiments, constructing a high-temperature, high-pressure multiphase system of CO2-water-oil-shale for the first shale sample and conducting a high-temperature, high-pressure multiphase contact angle experiment includes: cleaning all components of the apparatus with ethanol and distilled water; polishing the first shale sample with diamond abrasive and cleaning it with ethanol; placing the sheet-like first shale sample into a molecular vacuum pump and evacuating it for a period of time to fully saturate the formation water under high pressure and high temperature; placing the first shale sample on a movable magnetic device and placing it inside a high-temperature, high-pressure model, while simultaneously raising the temperature to the required value; opening the water injection valve and using the first injection pump to inject reservoir brine into the high-temperature, high-pressure model until the container is full, then closing the water injection valve; opening the gas injection valve and allowing gas to pass through. CO2 gas was slowly injected into a high-temperature, high-pressure model that was first filled with brine using a constant-pressure / constant-flow pump. The model was then pressurized to a predetermined pressure at a constant temperature. After the pressure in the high-temperature, high-pressure model stabilized, the oil injection valve was opened, and a drop of crude oil was dispensed onto the surface of the first shale sample through an injection needle. This completed the construction of the CO2-water-oil-shale high-temperature, high-pressure multiphase system. During this process, the pressure, temperature, and density of the fluid mixture within the high-temperature, high-pressure model were continuously monitored to calculate the interfacial tension between the phases. A high-resolution optical camera was used to continuously capture images, and axisymmetric droplet shape analysis technology was employed to evaluate the droplet volume and contact angle by detecting the droplet profile and multiphase contact points.

[0129] In some embodiments, the contact angle wettability parameter is further calculated based on the water wetting angle and the oil wetting angle, including calculating the contact angle wettability parameter using the following formula: I CA =(90-θ CW ) / 90-(90-θ CO The contact angle wettability parameter is calculated by 1 / 90, where I CA θ represents the contact angle wettability parameter. CW θ represents the wetting angle of water after the action of CO2. CO This indicates the oil wetting angle after CO2 treatment.

[0130] In some embodiments, calculating the contact angle correction parameter includes calculating the contact angle correction parameter according to the following formula: C CA =A d / A s Calculate the contact angle correction parameters, where C CA Indicates the contact angle correction parameter, A d A represents the projected area of ​​the target fluid during the image capture process. s This represents the projected area of ​​the first shale sample during the image capture process.

[0131] In some embodiments, nuclear magnetic resonance (NMR) experiments are performed on the second shale sample, and the mass of the second shale sample after each operation step is obtained as follows: The second shale sample is subjected to a vacuum pressurization test to saturate with formation water. After saturation, the first mass m1 of the second shale sample is measured, and the NMR T2 spectrum curve of the saturated formation water second shale is obtained simultaneously. The saturated formation water second shale is loaded into a core holder, the displacement process is connected, and the saturated water second shale sample is displaced with heavy water. The NMR T2 spectrum curve is monitored during the displacement process. When the NMR T2 spectrum curve shows no signal response, the displacement is stopped, and the second mass m2 of the second shale sample is measured. The saturated heavy water second shale sample is displaced with formation crude oil to establish bound water saturation, and the amount of water displaced from the second shale sample is measured. The third mass m3 of the displaced heavy water was measured; the second shale sample was aged at the formation temperature for a predetermined time, and the nuclear magnetic resonance T2 spectrum curve of the aged second shale sample was measured, as well as the fourth mass m4 of the second shale sample; CO2 was injected into the second shale sample using a high-pressure pump, and the temperature and pressure of the second shale sample were kept the same as those in the high-temperature and high-pressure multiphase contact angle experiment. The inlet and outlet valves of the experimental device were closed to keep the second shale sample in a simmering state, and the environmental pressure of the second shale sample was recorded during the simmering process; the outlet valve was opened, and the pressure was gradually reduced to atmospheric pressure until the second shale sample no longer produced oil. Then the fifth mass m5 of the displaced heavy water and the sixth mass m6 of the displaced crude oil were measured, and the nuclear magnetic resonance T2 spectrum curve after CO2 treatment was measured.

[0132] In some embodiments, the third computing unit includes a first computing subunit and a second computing subunit.

[0133] The first calculation subunit is used to calculate the water absorption of the second shale sample after CO2 exposure during the NMR experiment. CW =m2-m3-m5, and calculate the oil absorption of the second shale sample after CO2 treatment during the NMR experiment. CO =m4-(m2-m3)-m6.

[0134] The second calculation subunit is used to calculate the NMR wettability parameter according to the following formula: , Where j is NMR CW ×10 j and NMR CO ×10 j The minimum value of an integer; In some embodiments, the third calculation unit includes a third calculation subunit for calculating the NMR correction index, including calculating the NMR correction index according to the following formula: , Among them, C NMR NMR correction index, TOC is the total organic carbon content of the second shale sample, M w Percentage of hydrophilic minerals, Let be the porosity of the second shale sample, and j be the value that makes C... NMR It is the smallest integer that is a pure decimal.

[0135] In some embodiments, the evaluation unit includes a fourth calculation subunit and a first evaluation subunit.

[0136] The fourth calculation subunit is used to calculate the comprehensive wettability parameter according to the following formula: I w =I CA ×C CA +I NMR ×C NMR , among which, I w Indicates the overall wettability parameter, I CA C represents the contact angle wettability parameter. CA For contact angle correction parameters, I NMR C is the NMR wettability parameter. NMR This is the NMR correction index.

[0137] The first evaluation subunit is used to evaluate the wettability of the CO2-water-oil-shale multiphase system based on comprehensive wettability parameters.

[0138] In some embodiments, the first evaluation subunit includes a second evaluation subunit, used to determine the oleophilicity and hydrophilicity of the shale reservoir based on the positive or negative sign of the comprehensive wettability parameter, including: determining that the shale reservoir is hydrophilic wettability when the comprehensive wettability parameter is greater than 0; and determining that the shale reservoir is oleophilic wettability when the comprehensive wettability parameter is less than 0.

[0139] In some embodiments, the first evaluation subunit includes a third evaluation subunit, used to determine the wettability of the shale reservoir based on the magnitude of the absolute value of the comprehensive wettability parameter, including: determining that the shale reservoir has basically weak wettability when the absolute value of the comprehensive wettability parameter is less than the wettability threshold; and determining that the shale reservoir has strong wettability when the absolute value of the comprehensive wettability parameter is greater than or equal to the wettability threshold.

[0140] The descriptions and functions of the above devices can be understood by referring to the section on wettability evaluation methods for CO2-water-oil-shale multiphase systems, and will not be repeated here.

[0141] This invention also provides an electronic device, such as... Figure 9As shown, the electronic device may include a processor 901 and a memory 902, wherein the processor 901 and the memory 902 may be connected via a bus or other means. Figure 9 Taking the example of a connection between China and Israel via a bus.

[0142] Processor 901 can be a central processing unit (CPU). Processor 901 can also be other general-purpose processors, digital signal processors (DSPs), application-specific integrated circuits (ASICs), field-programmable gate arrays (FPGAs), or other programmable logic devices, discrete gate or transistor logic devices, discrete hardware components, or combinations of the above types of chips.

[0143] Memory 902, as a non-transitory computer-readable storage medium, can be used to store non-transitory software programs, non-transitory computer-executable programs, and modules, such as the program instructions / modules corresponding to the CO2-water-oil-shale multiphase system wettability evaluation method in this embodiment of the invention (e.g., Figure 8 The first experimental unit 10, first calculation unit 20, second calculation unit 30, second experimental unit 40, third calculation unit 50, fourth calculation unit 60, and evaluation unit 70 are shown. The processor 901 executes various functional applications and data processing by running non-transitory software programs, instructions, and modules stored in the memory 902, thereby realizing the wettability evaluation method for the CO2-water-oil-shale multiphase system in the above method embodiments.

[0144] The memory 902 may include a program storage area and a data storage area. The program storage area may store the operating system and applications required for at least one function; the data storage area may store data created by the processor 901, etc. Furthermore, the memory 902 may include high-speed random access memory and may also include non-transitory memory, such as at least one disk storage device, flash memory device, or other non-transitory solid-state storage device. In some embodiments, the memory 902 may optionally include memory remotely located relative to the processor 901, and these remote memories may be connected to the processor 901 via a network. Examples of such networks include, but are not limited to, the Internet, corporate intranets, local area networks, mobile communication networks, and combinations thereof.

[0145] The one or more modules are stored in the memory 902, and when executed by the processor 901, they perform the following: Figure 1The wettability evaluation method of the CO2-water-oil-shale multiphase system in the illustrated embodiment.

[0146] The specific details of the aforementioned electronic device can be understood by referring to the relevant descriptions and effects in the method embodiments, and will not be repeated here.

[0147] This specification also provides a computer storage medium storing computer program instructions, which, when executed by a processor, implement the steps of the above-described method for evaluating the wettability of a CO2-water-oil-shale multiphase system.

[0148] This specification also provides a computer program product comprising a computer program that, when executed by a processor, implements the steps of the above-described method for evaluating the wettability of a CO2-water-oil-shale multiphase system.

[0149] Those skilled in the art will understand that all or part of the processes in the methods of the above embodiments can be implemented by a computer program instructing related hardware. The program can be stored in a computer-readable storage medium, and when executed, it can include the processes of the embodiments of the above methods. The storage medium can be a magnetic disk, optical disk, read-only memory (ROM), random access memory (RAM), flash memory, hard disk drive (HDD), or solid-state drive (SSD), etc.; the storage medium can also include combinations of the above types of memory.

[0150] The various embodiments in this specification are described in a progressive manner. For the same or similar parts between the various embodiments, please refer to each other. The focus of each embodiment is to describe the differences from other embodiments.

[0151] The systems, devices, modules, or units described in the above embodiments can be implemented by computer chips or entities, or by products with certain functions.

[0152] For ease of description, the above devices are described separately by function as various units. Of course, in implementing this application, the functions of each unit can be implemented in one or more software and / or hardware.

[0153] As can be seen from the above description of the embodiments, those skilled in the art can clearly understand that this application can be implemented by means of software plus necessary general-purpose hardware platforms. Based on this understanding, the technical solution of this application, in essence, or the part that contributes to the prior art, can be embodied in the form of a software product. This computer software product can be stored in a storage medium, such as ROM / RAM, magnetic disk, optical disk, etc., and includes several instructions to cause a computer device (which may be a personal computer, server, or network device, etc.) to execute certain parts of the methods of various embodiments of this application.

[0154] This application can be used in a wide variety of general-purpose or special-purpose computer system environments or configurations. For example: personal computers, server computers, handheld or portable devices, tablet devices, multiprocessor systems, microprocessor-based systems, set-top boxes, programmable consumer electronics devices, network PCs, minicomputers, mainframe computers, distributed computing environments including any of the above systems or devices, etc.

[0155] This application can be described in the general context of computer-executable instructions, such as program modules, that are executed by a computer. Generally, program modules include routines, programs, objects, components, data structures, etc., that perform a specific task or implement a specific abstract data type. This application can also be practiced in distributed computing environments where tasks are performed by remote processing devices connected via a communication network. In distributed computing environments, program modules can reside in local and remote computer storage media, including storage devices.

[0156] Although this application has been described through embodiments, those skilled in the art will know that this application has many modifications and variations without departing from the spirit of this application, and it is intended that the appended claims cover such modifications and variations without departing from the spirit of this application.

Claims

1. A method for evaluating the wettability of a CO2-water-oil-shale multiphase system, characterized in that, include: During the construction of a high-temperature and high-pressure multiphase system of CO2-water-oil-shale for the first shale sample and the high-temperature and high-pressure multiphase contact angle experiment, the pressure, temperature and density of the fluid mixture in the high-pressure unit were continuously monitored, and images were continuously captured with the help of a high-resolution optical camera. The water wetting angle and oil wetting angle are calculated based on the monitoring results and captured images, and the contact angle wettability parameters are further calculated based on the water wetting angle and oil wetting angle. Calculate the contact angle correction parameter and use the contact angle correction parameter to correct the contact angle wettability parameter; During the nuclear magnetic resonance experiment on the second shale sample, the mass of the second shale sample after each operation step was obtained. The water and oil absorption of the second shale sample after CO2 treatment during the nuclear magnetic resonance experiment were calculated based on the mass of the second shale sample after each operation, and the nuclear magnetic wettability parameters were calculated based on the water and oil absorption. Calculate the NMR correction index and use it to correct the NMR wettability parameter; The wettability of the CO2-water-oil-shale multiphase system was evaluated based on the corrected contact angle wettability parameters and the corrected nuclear magnetic resonance wettability parameters.

2. The method according to claim 1, characterized in that, A high-temperature, high-pressure multiphase system of CO2-water-oil-shale was constructed for the first shale sample, and high-temperature, high-pressure multiphase contact angle experiments were conducted, including: All components of the apparatus were cleaned with ethanol and distilled water. The first shale sample was polished with diamond abrasive and then cleaned with ethanol. The sheet-like first shale sample was placed in a molecular vacuum pump to evacuate the formation water under high pressure and high temperature. The first shale sample was placed on a movable magnetic device and then placed inside a high-temperature, high-pressure model, while the temperature was raised to the required value. Open the water injection valve and use the first injection pump to inject reservoir brine into the high-temperature and high-pressure model until the container is full, then close the water injection valve. Open the gas injection valve and slowly inject CO2 gas into the high-temperature and high-pressure model that is first filled with brine through the first constant pressure / constant flow pump. Pressurize the high-temperature and high-pressure model to the predetermined pressure at a constant temperature. After the pressure in the high-temperature and high-pressure model stabilizes, the oil injection valve is opened, and a drop of crude oil is distributed onto the surface of the first shale sample through the injection needle, thus completing the construction of the CO2-water-oil-shale high-temperature and high-pressure multiphase system. During this process, the pressure, temperature, and density of the fluid mixture in the high-temperature and high-pressure model are continuously monitored to calculate the interfacial tension between each phase. High-resolution optical cameras are used to continuously capture images, and axisymmetric droplet shape analysis technology is used to evaluate droplet volume and contact angle by detecting droplet profiles and multiphase contact points.

3. The method according to claim 1, characterized in that, Based on the water wetting angle and oil wetting angle, the contact angle wettability parameters are further calculated, including the contact angle wettability parameters calculated using the following formula: I CA =(90-θ CW ) / 90-(90-θ CO The contact angle wettability parameter is calculated by 1 / 90, where I CA θ represents the contact angle wettability parameter. CW θ represents the wetting angle of water after the action of CO2. CO Indicates the oil wetting angle after CO2 treatment; And / or, Calculate the contact angle correction parameters, including calculating the contact angle correction parameters according to the following formula: C CA =A d / A s Calculate the contact angle correction parameters, where C CA Indicates the contact angle correction parameter, A d A represents the projected area of ​​the target fluid during the image capture process. s This represents the projected area of ​​the first shale sample during the image capture process.

4. The method according to claim 1, characterized in that, The second shale sample was subjected to nuclear magnetic resonance experiments in the following manner, and the mass of the second shale sample after each operation step was obtained: The second shale sample was subjected to a vacuum pressurization saturation test on formation water. After saturation, the first mass m1 of the second shale sample was measured, and the nuclear magnetic resonance T2 spectrum curve of the second shale saturated with formation water was obtained. The second shale saturated with formation water was loaded into the core holder, the displacement process was connected, and the second shale sample saturated with water was displaced with heavy water. The nuclear magnetic resonance T2 spectrum curve was monitored during the displacement process. When the nuclear magnetic resonance T2 spectrum curve showed no signal response, the displacement was stopped, and the second mass m2 of the second shale sample was measured. The second shale sample, saturated with heavy water, was used to displace the heavy water from the formation crude oil to establish bound water saturation. The third mass m3 of the heavy water displaced from the second shale sample was measured. The second shale sample after displacement was aged at the formation temperature for a predetermined time. The nuclear magnetic resonance T2 spectrum curve of the second shale sample after aging was measured, and the fourth mass m4 of the second shale sample was measured. CO2 was injected into the second shale sample using a high-pressure pump. The temperature and pressure of the second shale sample were kept the same as those in the high-temperature and high-pressure multiphase contact angle experiment. The inlet valve and outlet valve of the experimental device were closed to keep the second shale sample in a simmering state. The environmental pressure of the second shale sample was recorded during the simmering process. Open the outlet valve and gradually reduce the pressure to atmospheric pressure until no oil is produced from the second shale sample. Then measure the fifth mass m5 of the displaced heavy water and the sixth mass m6 of the displaced crude oil, and measure the nuclear magnetic resonance T2 spectrum curve after CO2 treatment.

5. The method according to claim 4, characterized in that, Based on the mass of the second shale sample after each operation, the water and oil absorption of the second shale sample after CO2 treatment during the nuclear magnetic resonance experiment were calculated, and the nuclear magnetic wettability parameters were calculated based on the water and oil absorption, including: Calculation of water absorption in the second shale sample after CO2 exposure during the nuclear magnetic resonance (NMR) experiment CW =m2-m3-m5, and calculate the oil absorption of the second shale sample after CO2 treatment during the NMR experiment. CO =m4-(m2-m3)-m6; The NMR wettability parameter is calculated using the following formula: ， Where j is NMR CW ×10 j and NMR CO ×10 j The minimum value of an integer; And / or, Calculate the NMR correction index, including calculating the NMR correction index according to the following formula: ， Among them, C NMR NMR correction index, TOC is the total organic carbon content of the second shale sample, M w Percentage of hydrophilic minerals, Let be the porosity of the second shale sample, and j be the value that makes C... NMR It is the smallest integer that is a pure decimal.

6. The method according to claim 1, characterized in that, The wettability of the CO2-water-oil-shale multiphase system was evaluated based on the corrected contact angle wettability parameters and the corrected nuclear magnetic resonance wettability parameters, including: The comprehensive wettability parameter is calculated using the following formula: I w =I CA ×C CA +I NMR ×C NMR , among which, I w Indicates the overall wettability parameter, I CA C represents the contact angle wettability parameter. CA For contact angle correction parameters, I NMR C is the NMR wettability parameter. NMR For NMR correction index; The wettability of the CO2-water-oil-shale multiphase system was evaluated based on comprehensive wettability parameters.

7. The method according to claim 6, characterized in that, The wettability of the CO2-water-oil-shale multiphase system was evaluated based on comprehensive wettability parameters, including: The oleophilicity and hydrophilicity of shale reservoirs are determined based on the positive or negative sign of the comprehensive wettability parameter, including: if the comprehensive wettability parameter is greater than 0, the shale reservoir is determined to be hydrophilic wettable; if the comprehensive wettability parameter is less than 0, the shale reservoir is determined to be oleophilic wettable.

8. The method according to claim 6, characterized in that, The wettability of the CO2-water-oil-shale multiphase system was evaluated based on comprehensive wettability parameters, including: The wettability of shale reservoirs is determined based on the absolute value of the comprehensive wettability parameter, including: when the absolute value of the comprehensive wettability parameter is less than the wettability threshold, the shale reservoir is determined to have basically weak wettability; when the absolute value of the comprehensive wettability parameter is greater than or equal to the wettability threshold, the shale reservoir is determined to have strong wettability.

9. A device for evaluating the wettability of a CO2-water-oil-shale multiphase system, characterized in that, include: The first experimental unit is used to continuously monitor the pressure, temperature and density of the fluid mixture in the high-pressure unit during the construction of a high-temperature and high-pressure multiphase system of CO2-water-oil-shale and the high-temperature and high-pressure multiphase contact angle experiment of the first shale sample, and to continuously capture images with the help of a high-resolution optical camera. The first calculation unit is used to calculate the water wetting angle and the oil wetting angle based on the monitoring results and the captured images, and further calculate the contact angle wettability parameters based on the water wetting angle and the oil wetting angle. The second calculation unit is used to calculate the contact angle correction parameters and then use these parameters to correct the contact angle wettability parameters. The second experimental unit is used to obtain the mass of the second shale sample after each operation step during the nuclear magnetic resonance experiment on the second shale sample. The third calculation unit is used to calculate the water and oil absorption of the second shale sample after CO2 action during the nuclear magnetic resonance experiment based on the mass of the second shale sample after each operation, and to calculate the nuclear magnetic wettability parameters based on the water and oil absorption. The fourth calculation unit is used to calculate the NMR correction index, which is used to correct the NMR wettability parameter. The evaluation unit is used to evaluate the wettability of the CO2-water-oil-shale multiphase system based on the corrected contact angle wettability parameter and the corrected nuclear magnetic resonance wettability parameter.

10. An electronic device, characterized in that, include: The system includes a memory and a processor, which are interconnected. The memory stores computer instructions, and the processor executes these computer instructions to implement the method for evaluating the wettability of the CO2-water-oil-shale multiphase system as described in any one of claims 1 to 8.

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