A multi-scale co2-oil displacement component migration monitoring device and method

Abstract

The present application belongs to the field of oil and gas field development, and particularly relates to a multi-scale CO2 flooding oil component migration monitoring device and method. The present application sets a long and thin tube variable diameter assembly to build a displacement path with a length of meters or more. Compared with a conventional short core experiment, the present application can carry out displacement experiments on a longer migration scale, thereby being more conducive to characterizing the long-range migration process of CO2 in a porous medium and the formation and evolution characteristics of a miscible phase transition zone. By sequentially setting a matrix pore section, a micro-fracture channel section and a fault blocking section in the device, fluid migration behaviors in different types of seepage channels, including matrix seepage, fracture dominant channel migration and local blocking effect, can be simulated in the same experimental system, thereby improving the adaptability of experimental results to complex reservoir seepage characteristics. By arranging multi-point sampling units along the displacement direction and combining with gas phase component analysis means, dynamic monitoring of CO2 and hydrocarbon components inside the device is realized.

Description

Technical Field

[0001] This invention belongs to the field of oil and gas field development, and specifically relates to a multi-scale CO2 flooding component migration monitoring device and method. Background Technology

[0002] CO2 flooding technology is a reservoir development technology that combines enhanced oil recovery with geological preservation potential. In recent years, it has received widespread attention in the development of low-permeability reservoirs, deep reservoirs, and complex fault-block reservoirs. As the development level of conventional reservoirs continues to increase, some reservoirs are gradually entering a stage of high water cut and high recovery, with more complex distribution of remaining oil. Conventional waterflooding is no longer effective, necessitating the development of efficient displacement technologies suitable for complex reservoir conditions. CO2 has good expansion and viscosity-reducing effects, reduces interfacial tension, and improves crude oil fluidity. Under suitable pressure and temperature conditions, it can undergo miscible or near-miscible displacement with crude oil, thereby improving crude oil utilization and recovery.

[0003] However, implementing CCUS-EOR technology in these reservoirs faces significant challenges. First, the high temperature and pressure environment of deep reservoirs leads to high oil-gas miscibility pressure, and the strong heterogeneity of the reservoirs significantly inhibits the mass transfer efficiency between CO2 and crude oil, increasing the difficulty of miscibility. Second, microfractures and structural fracture zones in complex fault-block reservoirs create highly permeable channels, easily leading to CO2 overlap and gas channeling. The root cause of these problems lies in the insufficient understanding of the migration patterns of CO2 and hydrocarbon components in multi-scale pores, and existing technologies face numerous limitations. Chinese patent document CN116359297A (202310383019.8) discloses a method and device for studying the migration law of CO2 flooding phase front and component front in long cores. The method uses long core experiments and measures the fluid components in the outlet section to determine the migration of each component. However, due to the limited length of artificial / natural long cores, the gas components have short migration paths and short residence times in the core. Existing monitoring technologies are unable to accurately capture their migration trajectory and distribution law. In addition, only the changes in fluid components in the outlet section can be collected, and the migration law of components inside the core cannot be quantitatively characterized. Chinese patent document CN114429086A (202010974303.9) discloses a method, device, electronic equipment and medium for simulating two-phase multi-component flow of oil and gas. The method calculates the molar transport of components at the micro-pore scale through a pore network model. However, the pore network flow model ignores the component hysteresis phenomenon caused by reservoir heterogeneity, and the homogeneous micro-pore throat model ignores the multi-scale pore structure (such as microfractures) in natural reservoirs, which leads to a deviation between the CO2 flooding front advance velocity and the actual value.

[0004] According to existing research, current methods and technologies for quantitative characterization of multi-component transport in multi-scale CO2 flooding have the following problems: ① Inaccurate experimental scale leads to distorted migration paths. Conventional core displacement devices are typically 10 cm long, which cannot simulate the dynamic miscibility of CO2 during long-distance (meter- to ten-meter-scale) transport. The mass transfer rates and residence times of CO2 gas with light, medium, and heavy hydrocarbon components are difficult to predict, seriously affecting the accuracy of the miscibility zone formation mechanism. ② Homogeneous models mask the channeling effect caused by heterogeneity. Currently used standard core experiments are usually filled with uniform quartz sand. This model ignores the multi-scale pore structure (such as microfractures) in natural reservoirs, resulting in deviations between the CO2 flooding front advance velocity and reality. Therefore, there is an urgent need to develop a monitoring device that combines long-range migration simulation and heterogeneous channeling reduction capabilities, capable of accurately capturing the mass transfer trajectories of multiple components, and breaking through the bottlenecks in miscibility control and gas channeling prevention in deep reservoir CCUS-EOR technology. Summary of the Invention

[0005] To address the aforementioned problems in the prior art, this invention provides a multi-scale CO2-driven multi-component migration quantitative monitoring device and method to precisely characterize the mass transfer trajectory and miscibility evolution of CO2-hydrocarbon components in multi-scale porous media, supporting the optimized design of miscibility regulation and gas channeling prevention in the CCUS-EOR process of deep oil reservoirs.

[0006] The technical problem to be solved by the present invention is achieved by the following technical solution: a multi-scale CO2 flooding component migration monitoring device, comprising a long thin tube variable diameter assembly, an injection system, a microscopic visualization sampler, a component analysis unit, a fluid flow pattern monitor and a data processing system; The long, thin tube variable diameter assembly includes a matrix porosity simulation section, a microfracture channel simulation section, and a fault shielding simulation section connected in sequence. A back pressure adjustment module is provided on the outlet side of the fault shielding simulation section. Multiple microscopic visualization samplers are spaced apart on the matrix porosity simulation section, the microfracture channel simulation section, the fault shielding simulation section, between the matrix porosity simulation section and the microfracture channel simulation section, and between the microfracture channel simulation section and the fault shielding simulation section. The matrix porosity simulation section, the microfracture channel simulation section, and the fault shielding simulation section are coiled tube structures. The matrix pore simulation section is filled with a material to simulate the pore medium of a low-permeability reservoir matrix. The microfracture channel simulation section is filled with a filling material to simulate high-permeability fractures, natural microfractures, or locally dominant seepage channels developed in the reservoir. The fault shielding simulation section is filled with a material to simulate fault gouge, dense interlayer, local sealing body or seepage abrupt interface. The injection system includes a formation water injection unit, a crude oil injection unit, and a CO2 injection unit. The outlet sides of the formation water injection unit, crude oil injection unit, and CO2 injection unit are respectively connected to the inlet of the matrix pore simulation section. The formation water injection unit is used to saturate water and establish initial water saturation. The crude oil injection unit is used to inject simulated crude oil or degassed crude oil from the formation. The CO2 injection unit is used to inject liquid, supercritical, or gaseous CO2 into the device. Liquid, supercritical, or gaseous CO2 corresponds to different temperatures and pressures, and the phase state of CO2 is controlled by both temperature and pressure. Under normal temperature conditions, CO2 usually changes from a gaseous state to a liquid state as the pressure increases. When the temperature is higher than the critical temperature of 31.1℃ and the pressure is higher than the critical pressure of 7.38MPa, CO2 enters the supercritical state. Under reservoir conditions, since the formation temperature and pressure are usually high, the injected CO2 may exist in a gaseous, liquid, supercritical, or near-critical state, and its phase change will affect the density, viscosity, diffusion capacity, and displacement effect of CO2. Pressure sensors are installed at the inlet and outlet ends of the matrix pore simulation section, microcrack channel simulation section, and fault shielding simulation section to record pressure changes and pressure drop distribution in different sections in real time. The microscopic visualization sampler includes a sampling branch pipe, a pressure-resistant sampling container, an inlet valve, and an outlet valve. The pressure-resistant sampling container is connected to a long, thin tube reducing assembly via the sampling branch pipe. The inlet and outlet of the pressure-resistant sampling container are respectively equipped with inlet and outlet valves. The pressure-resistant sampling container is equipped with an observation window. The outlet valve is connected to a component analysis unit. The fluid flow pattern monitor is located at the observation window. The microscopic visualization sampler is not only located at the inlet of the long, thin tube reducing assembly, but is also located at the inlet end, the long, thin tube body, and the connection between the coils. The microscopic visualization sampler is located at different positions on the long, thin tube reducing assembly and at the coil connection, and is connected to the long, thin tube reducing assembly via a quick-connect interface at the coil connection to facilitate the introduction and sampling of experimental fluid between the long, thin tube reducing assembly and the microscopic visualization sampler.

[0007] The matrix pore simulation section, microcrack channel simulation section, and fault shielding simulation section are respectively set inside the first temperature control device, and a second temperature control device is set outside the micro-visual sampler. In order to prevent the oil and gas phases from changing due to the decrease in temperature during the sampling process, which would affect the changes in gas composition and oil phase composition, the second temperature control device is used to heat and keep the micro-visual sampler warm. The data processing system is connected to the pressure sensor, the component analysis unit, the fluid flow pattern monitor, the first temperature control device, and the second temperature control device, respectively.

[0008] The component analysis unit is connected to a microscopic visualization sampler to detect the concentration or mole fraction of CO2, methane, ethane, propane, C4-C6 light and medium hydrocarbons, and heavy components in the fluid. The fluid flow pattern monitor is connected to the data processing system to achieve time-synchronous acquisition of microscopic images and pressure data of the fluid within the high-pressure sampling chamber.

[0009] A back pressure control device is installed at the system outlet to maintain system back pressure, ensuring that CO2 is in the target phase and stably forms miscible or near-miscible displacement conditions. Preferably, the pressure control range is 1~50MPa. The back pressure control device is a back pressure valve with an inlet, outlet, and back pressure injection port. The back pressure injection port is connected to a back pressure pump, and the inlet of the back pressure control device is connected to the outlet end of a thin tube, with the outlet end venting. The miscibility pressure is determined by the properties of each crude oil. Upon receiving oil samples, the petroleum industry conducts miscibility pressure tests. When the pressure is below the miscibility pressure, it is considered immiscible displacement; when it is close, it is near-miscible displacement; and when it is above the pressure, it is considered miscible displacement.

[0010] Preferably, in this invention, the matrix pore simulation section includes a coil and a filling body located inside the coil, wherein the filling body is 50-80 mesh quartz sand to form the target porosity and permeability; The simulated microcrack channel section includes a coil, a filling body located within the coil, and a narrow slot plate structure embedded within the filling body. The narrow slot plate structures are spaced apart along the axial direction of the coil. The filling body is 150-200 mesh quartz sand. The narrow slot plate structure includes several elongated slots and a sintered particle filling layer within the elongated slots. In this invention, the narrow slot plate structure is disposed inside the coil cavity and can be spaced apart along the axial direction of the coil. Specifically, the narrow slot plate structure includes several elongated slots. The outer contour dimensions are adapted to the inner diameter of the coil and are fixed to the inner wall of the coil by welding; the narrow slot plate structure is built into the coil cavity, and the outer periphery of the narrow slot plate structure is matched and fixedly connected to the inner wall of the coil; the fluid passes through the coil flow channel through the narrow slot; a filling space is formed between the narrow slots, and a sintered particle filling layer is set in the filling space; by adjusting the width, length, spacing, number of slots, and particle size of the sintered particles of the narrow slots, the flow channel structure and seepage resistance in the coil can be controlled; The sintered particle filling layer is formed by mixing and cementing sintered glass particles, sintered ceramic particles, sintered metal particles, and sintered quartz particles. Its particle size ranges from 10 μm to 5 mm, with a porosity of 10% to 60% and a permeability of 0.1 mD to 100 mD. Sintered glass particles facilitate the formation of a more regular pore structure, sintered ceramic particles improve the wear resistance and compressive stability of the filling layer, sintered metal particles enhance the structural strength of the filling layer under high-pressure displacement conditions, and sintered quartz particles help simulate the quartz mineral framework characteristics in sandstone reservoirs. By mixing and cementing different materials, particle sizes, and ratios, the porosity, permeability, pore throat connectivity, and degree of heterogeneity of the filling layer can be adjusted. The fault-blocking simulation section includes a coil, a filling body located within the coil, and a low-permeability filling layer and / or narrowing channels disposed within the filling body. The low-permeability filling layer and / or narrowing channels are arranged at intervals along the axial direction of the coil. The filling body is 300-350 mesh quartz sand. The low-permeability filling layer includes porous baffles spaced apart along the coil axis and porous media filler disposed between the porous baffles. The porous media filler is made of a mixture of quartz sand, glass beads, ceramic particles, core fragments, and artificially sintered porous materials, with a particle size of 5μm to 10mm, a porosity of 5% to 70%, and a permeability of 0.001mD to 10mD. Porous media packing is made by mixing and bonding packing materials of different sizes and proportions with epoxy resin. Porous media packing is made by mixing and bonding quartz sand, glass beads, ceramic particles, core fragments, and artificially sintered porous materials to form different heterogeneous structures. It does not migrate, pulverize, or block the outlet under the flushing of experimental fluid. Porous media packing is not composed of particles of a single size, but is composed of particles of multiple size grades mixed in a certain proportion. The reduced-diameter channel is a reduced-diameter sleeve or throttling ring coaxially arranged with the coil. A low-permeability packing layer is disposed inside the coil cavity and is segmented within the coil. Specifically, the low-permeability packing layer can be formed by a mixture and cementation of quartz sand, glass beads, ceramic particles, core fragments, and artificially sintered porous materials, with the packing material confined within a predetermined area inside the coil. To prevent the packing material from migrating under fluid scouring, porous baffles can be installed at both ends of the packing layer to fix the packing particles within the coil cavity, thereby forming a low-permeability flow region with a certain porosity and permeability. The packing medium of the low-permeability packing layer uses porous media to create a significant pressure gradient transition and component hysteresis effect during displacement. Both the low-permeability packing layer and the reduced-diameter channel are equivalent low-permeability flow structures disposed inside the coil cavity; the former is formed by filling with particles, porous media, etc., while the latter is formed by locally reducing the flow cross-sectional area. Specifically, the outer wall of the reduced diameter channel is fixed or sealed to the inner wall of the coil, and a fluid channel smaller than the original inner diameter of the coil is formed inside the reduced diameter channel, causing local throttling and velocity changes when the fluid passes through this area.

[0011] The low-permeability packing layer and the narrow-bore channel can be set up individually or in combination. For example, a low-permeability packing layer can be set in one section of the coil, and a narrow-bore sleeve can be set in another section; or granular packing layers can be set before and after the narrow-bore channel, so that the fluid passes through the narrow-bore throttling zone and the low-permeability packing zone in sequence. In this way, an adjustable structure can be formed inside the coil to simulate a low-permeability reservoir, a heterogeneous channel, or a local high-resistivity flow zone.

[0012] Preferably, the equivalent permeability range of the matrix pore simulation section is 0.1-10 mD. The equivalent permeability range of the simulated microcrack channel is 10. 2 -10 4 mD; The equivalent permeability range of the fault-blocking simulation segment is 10. -3 -10 -1 mD.

[0013] Preferably, in this invention, two pressure-resistant sampling containers are connected in series vertically upwards to allow for segmented collection of oil and gas samples.

[0014] Preferably, the component analysis unit of this invention includes one or more of a gas chromatograph, mass spectrometer, infrared analyzer, or Raman spectroscopy device. The gas chromatograph primarily analyzes the gas phase composition, such as the content of CO2, CH4, C2H6, N2, O2, and light hydrocarbon components; the mass spectrometer primarily identifies the molecular types of gases, volatile organic compounds, or complex components; the infrared analyzer primarily examines molecular functional groups; and the Raman spectroscopy primarily analyzes the molecular structure and phase changes of CO2, hydrocarbons, aqueous phase, and minerals; it can be used for in-situ observation of the phase state, dissolution state, and gas-liquid distribution of CO2 in microscopic channels.

[0015] Preferably, the formation water injection unit of the present invention includes a first container and a drive pump; The crude oil injection unit includes a second container and a drive pump; The CO2 injection unit includes a third container and a drive pump.

[0016] Preferably, the first container, the second container, and the third container use the same driving pump as the first driving pump, and the first driving pump is connected to the first container, the second container, and the third container respectively through a six-way valve.

[0017] Preferably, the long thin tube diameter changing assembly further includes a coil support and a control valve, and the matrix pore simulation section, microcrack channel simulation section and fault shielding simulation section are respectively disposed on the coil support; Control valves are installed at the inlet and outlet of the matrix pore simulation section, the microcrack channel simulation section, and the fault shielding simulation section, respectively. The control valve is equipped with a quick-connect adapter.

[0018] This invention also discloses a multi-scale CO2 flooding multi-component migration quantitative monitoring method, implemented based on the above-mentioned multi-scale CO2 flooding oil component migration monitoring device, comprising the following steps: S1. Based on the pore structure, permeability distribution, fracture development degree, and fault shielding characteristics of the target reservoir, configure the structural parameters of the matrix pore simulation section, microfracture channel simulation section, and fault shielding simulation section in the long, thin, variable-diameter tube assembly to complete the construction of a multi-scale heterogeneous medium model. After sand filling, weigh the entire model. i ; S2. Prepare simulated formation water and simulated crude oil, or select degassed crude oil from the target block; configure the CO2 injection state according to experimental requirements, and set the experimental temperature, pressure and back pressure conditions to make CO2 in a gaseous, liquid, near-miscible or supercritical state. S3. First, turn on the formation water injection unit and control the injection pump to saturate the device with water at a preset injection rate until the outlet flow rate stabilizes. This is considered the saturation of formation water is complete. Weigh the entire model (m). wThe model pore volume was calculated; then the formation water injection unit was shut down, and the crude oil injection unit was opened. Crude oil was injected at a preset displacement rate to establish the initial oil saturation. When the displacement volume reached 20 PV, the model mass was weighed and recorded as m. o And calculate the oil saturation So of the model; PV=(m w -M i ) / ρ(1) PV number = V i / PV(2) (3) In the formula, PV is the pore volume of the model, mL; Mi is the mass of the dried model, g; m w The mass of the model after saturation with water is g; m o ρ is the mass of the model after saturation with oil, in g; ρ is the density of the saturated fluid, in g / cm³. 3 V i The cumulative injected fluid volume is expressed in mL. Oil saturation, % The density of the aqueous phase is g / cm³. 3 ; The density of the oil phase is g / cm³. 3 PV number is dimensionless and is used to represent how many pore volumes of fluid have been injected.

[0019] Because the pore volume of a model cannot usually be measured directly, it needs to be inferred from the mass difference before and after saturation. For example, when the model is an empty tube, a sand-filled model, a sintered particle-filled model, a porous medium model, or a coil-filled model, there is a certain amount of pore space inside. After the model is completely saturated with a fluid of a known density, the model mass will increase. The increased mass is the mass of the fluid entering the pore space. Therefore, the purpose of weighing is mainly threefold: first, to determine the actual flowable and fillable pore volume in the model; second, to provide basic parameters for subsequent calculations of the injected PV number; and third, to facilitate a unified experimental process for different models, different filling methods, and different permeation structures. S4. Open the CO2 injection unit and set the injection pump to inject CO2 into the device at a constant pressure. The injection pressure is adjustable, and the back pressure controls the miscibility of CO2 with crude oil. Record the final recovery rate when the CO2 displacement volume reaches 1.2 PV. A 1.2 PV injection volume is equivalent to 1.2 times the model pore volume. Recording the final recovery rate at this point is chosen because the injection volume exceeds the core pore volume, ensuring that CO2 effectively displaces the crude oil in the core. At this point, the recovery rate usually stabilizes, and further increasing the injection volume has limited effect on improving the recovery rate (this can be verified by referring to the attached diagram). Figure 10(Discovery). Therefore, using 1.2 PV as the experimental endpoint not only reflects the final effect of CO2 flooding but also facilitates a unified comparison of experimental results under different pressure conditions. It can be revised to state that when CO2 fully displaces the crude oil in the core, i.e., when a large amount of gas emerges at the outlet and the rate of increase in crude oil production rapidly decreases, it indicates that the usable crude oil in the core has been largely extracted, and further CO2 injection has limited effect on improving the recovery rate. At this point, the final recovery rate should be recorded.

[0020] S5. During the displacement process, a microscopic visualization sampler is used to acquire real-time images of the fluid front, and the oil-gas interface is observed through a high-temperature, high-pressure transparent window; pressure sensors are used to record pressure changes at various points; in addition, fluid samples from different locations can be collected periodically using the microscopic visualization sampler, and the sample collection locations are recorded. (t)(m) represents the fluid flow path length from the microscopic visualization sampler to the injection port of the matrix pore simulation section, and the CO2 and hydrocarbon component contents are obtained by the component analysis unit. Calculate the apparent migration rate V of each component. k ; = (t)(4) (5) In the formula, The mole fraction or volume fraction of the kth component at position x and time t (measured by a component analyzer). (t) represents the position of the k-th component at time t; k is the component number, namely C1, C2-C4, C5-C7, C8-C12, C13-C20, C21-C30, C30+; x is the distance (m) from the injection port (i.e., the injection port of the coil corresponding to the matrix pore simulation section); t is the time. Apparent migration rate of the k-th component, m / PV number; The axial coordinate of the device is defined as the positive x-axis direction along the displacement direction, with the CO2 injection end, i.e., the injection port of the long thin tube variable diameter component, as the starting point. The position of the mixed phase zone is represented by the distance from the injection end.

[0021] S6. Based on the component variation patterns and image recognition results at different monitoring points, identify the location of the miscible zone and record the CO2 displacement efficiency of crude oil under different miscible pressures. Component variation patterns refer to the concentration distribution and variation characteristics of CO2 and hydrocarbon components under different spatial locations and time conditions; image recognition results refer to the interface type obtained after identifying the morphological characteristics of the oil-gas interface through image data acquired by a microscopic visualization sampler.

[0022] Preferably, in step S6 of this invention, the interface type corresponding to the image recognition result is: Type I: pure gas phase region; Type II: clear interface between oil and gas phases; Type III: blurred interface region; Type IV: single continuous phase region. Identifying the location of the miscible zone involves directly observing the oil-gas interface during the displacement process using a microscopic visualization sampler, and identifying the location of the miscible zone based on changes in interface morphology. Specifically, this includes: When the oil and gas interface in the observation area exhibits one of the following states, it is determined to have entered the miscible transition zone: (1) The oil and gas interface gradually becomes blurred from a clear boundary; (2) The oil and gas two-phase interface cannot be clearly distinguished in some areas; By combining the changes in the interface position over time, the spatial distribution position X of the mixed phase zone is determined (based on the length of the coil).

[0023] This invention constructs a multi-scale heterogeneous medium environment closely resembling a natural reservoir by coupling matrix pore sections, microfracture channel sections, and fault-blocked sections in a long-distance experimental channel. After injection, CO2 first undergoes dissolution and diffusion with light hydrocarbon extraction in the matrix pores, then rapidly breaks through in the high-permeability microfracture channels, and forms a significant pressure difference and component hysteresis before and after the fault-blocked section. Through multi-point pressure monitoring, segmented sampling analysis, and simultaneous observation of local microscopic visualization, the migration rate and miscibility mode of CO2-driven oil recovery components can be quantitatively identified, thereby revealing the multi-component migration mechanism of CO2-driven oil recovery under multi-scale medium conditions.

[0024] Compared with the prior art, the beneficial effects of the present invention are: 1. This invention constructs displacement paths of meter length and above by setting up long and thin tube diameter components. Compared with conventional short core experiments, it can carry out displacement experiments on a longer transport scale, which is more conducive to characterizing the long-range transport process of CO2 in porous media and the formation and evolution characteristics of the miscible transition zone.

[0025] 2. By sequentially setting up matrix pore sections, microfracture channel sections, and fault shielding sections in the device, fluid transport behavior in different types of seepage channels can be simulated within the same experimental system, including matrix seepage, fracture-dominant channel transport, and local hindrance effects, thereby improving the adaptability of experimental results to the seepage characteristics of complex reservoirs.

[0026] 3. By deploying multiple sampling units along the displacement direction, i.e., multiple microscopic visualization samplers, and combining them with gas phase component analysis methods, dynamic monitoring of CO2 and hydrocarbon components inside the device can be achieved. Compared with the method of relying solely on sampling at the outlet end, it is possible to obtain the spatial distribution of components and their changes over time.

[0027] 4. By combining the fluid flow pattern monitor with the pressure monitoring and component analysis unit, the synchronous acquisition of oil-gas interface morphology changes and multi-component dynamic data during the displacement process can be achieved, which helps to improve the accuracy of identifying the miscible location. Attached Figure Description

[0028] Figure 1 A schematic diagram of a multi-scale CO2-driven oil displacement component migration monitoring device; Figure 2 A schematic diagram of the structure of a microscopic visualization sampler; Figure 3 This is a detailed schematic diagram of a single coil unit; Figure 4 This is a schematic diagram of the connection of the long, thin tube diameter changing assembly; Figure 5 This is a schematic diagram of the structure of the matrix pore simulation section; Figure 6 This is a schematic diagram of the structure of a simulated microcrack channel segment; Figure 7 A schematic diagram of the structure of the fault-blocked simulated segment; Figure 8 Schematic diagrams of different types of oil and gas interfaces; Figure 9 To visualize the oil-gas interface and gas phase component distribution of the sampler at different locations; Figure 10 Figure showing the variation of oil recovery rate with PV number under different pressures; The diagram shows 100 component analysis units, 200 fluid flow pattern monitors, and 300 data processing systems. 1. Matrix porosity simulation section; 2. Microcrack channel simulation section; 3. Fault shielding simulation section; 1000 back pressure regulation module; 4 Formation water injection unit, 5 Crude oil injection unit, 6 CO2 injection unit, 7 Pressure sensor, 8 Sampling branch pipe, 9 Pressure-resistant sampling container, 10 Inlet valve, 11 Outlet valve, 91 Observation window, 12 First temperature control device, 13 Second temperature control device, 41 First container, 51 Second container, 61 Third container, 14 First drive pump, 15 Coil support, 16 Control valve, 161 Quick-connect adapter, 17 Six-way valve; 400 coil, 500 filler body, 600 narrow slot plate structure, 700 low permeability filler layer, 800 diameter reduction channel; 601 Narrow through-slit, 602 Sintered particle filling layer, 701 Porous partition, 702 Porous media filler. Detailed Implementation

[0029] The present invention will be further described in detail below with reference to the embodiments and accompanying drawings, but the embodiments of the present invention are not limited thereto.

[0030] In this embodiment, the coil, porous partition, narrow slot plate structure, reduced diameter sleeve, and throttling ring are all made of metal materials, and the filler materials used, such as sintered glass particles, sintered ceramic particles, sintered metal particles, sintered quartz particles, as well as quartz sand, glass beads, ceramic particles, core fragments, and artificially sintered porous materials, are all commercially available products.

[0031] like Figures 1-4 As shown, a multi-scale CO2 flooding component migration monitoring device includes a long thin tube variable diameter assembly, an injection system, a microscopic visualization sampler, a component analysis unit 100, a fluid flow pattern monitor 200, and a data processing system 300.

[0032] The long, thin tube variable diameter assembly includes a matrix porosity simulation section 1, a microfracture channel simulation section 2, and a fault shielding simulation section 3 connected in sequence. A back pressure regulating module 1000 is installed at the outlet side of the fault shielding simulation section 3. Multiple microscopic visualization samplers are spaced apart on the matrix porosity simulation section 1, the microfracture channel simulation section 2, the fault shielding simulation section 3, between the matrix porosity simulation section 1 and the microfracture channel simulation section 2, and between the microfracture channel simulation section 2 and the fault shielding simulation section 3. The matrix porosity simulation section 1, the microfracture channel simulation section 2, and the fault shielding simulation section 3 are coiled structures. The back pressure regulating module 1000 is used to maintain the system back pressure, ensuring that CO2 is in the target phase and stably forms miscible or near-miscible displacement conditions. In this embodiment, the pressure control range is 1~50MPa. The back pressure control device is a back pressure valve with an inlet, an outlet, and a back pressure injection port. The back pressure injection port is connected to a back pressure pump, the inlet of the back pressure control device is connected to the outlet end of the thin tube, and the outlet end is vented. Miscibility pressure is determined by the properties of each type of crude oil. When oil samples are received, the oil industry conducts miscibility pressure tests. When the pressure is below the miscibility pressure, it is considered immiscible displacement; when it is close to the pressure, it is considered near-miscible displacement; and when it is above the pressure, it is considered miscible displacement.

[0033] Different sections of the elongated thin-tube diameter-changing assembly can be freely combined and connected in series via ball valves to form a modular structure. The main body of the elongated thin-tube diameter-changing assembly is a high-pressure resistant metal coil with three sampling ports. The coil is mounted on a coil support, and a ball valve and a quick-connect interface are provided at the coil inlet end. The quick-connect interface is a four-way interface, with the horizontal sides used to connect the ball valve and the coil inlet, and the vertical sides serving as sampling and pressure measurement ports to obtain fluid samples and pressure signals at different locations for detecting leading-edge transport characteristics. The microscopic visualization sampler is located at different positions and connections of the elongated thin-tube diameter-changing assembly and is connected to the elongated thin-tube diameter-changing assembly via the quick-connect interface to realize the introduction and sampling of experimental fluid between the elongated thin-tube diameter-changing assembly and the microscopic visualization sampler.

[0034] The matrix pore simulation section 1 is filled with a material to simulate the pore medium of a low-permeability reservoir matrix. The equivalent permeability of the matrix pore simulation section 1 ranges from 0.1 to 10 mD.

[0035] The simulated microfracture channel section 2 is filled with material to simulate high-permeability fractures, natural microfractures, or locally dominant flow channels developed in the reservoir. The equivalent permeability range of the simulated microfracture channel section 2 is 10. 2 -10 4 mD.

[0036] The fault shielding simulation section 3 is filled with a material to simulate fault gouge, dense interlayers, localized plugs, or abrupt seepage interfaces.

[0037] The equivalent permeability range of the fault-blocking simulation segment 3 is 10. -3 -10 -1 mD.

[0038] The injection system includes a formation water injection unit 4, a crude oil injection unit 5, and a CO2 injection unit 6. The outlet sides of the formation water injection unit 4, crude oil injection unit 5, and CO2 injection unit 6 are respectively connected to the inlet of the matrix pore simulation section 1.

[0039] The formation water injection unit 4 is used to saturate water and establish initial water saturation.

[0040] The crude oil injection unit 5 is used to inject simulated crude oil or degassed crude oil from the formation.

[0041] The CO2 injection unit 6 is used to inject liquid, supercritical, or gaseous CO2 into the device.

[0042] Pressure sensors 7 are respectively installed at the inlet and outlet ends of the matrix pore simulation section 1, microcrack channel simulation section 2, and fault shielding simulation section 3. The pressure sensors 7 are located at the inlet and outlet ends of the long thin tube variable diameter assembly to record the pressure changes and pressure drop distribution at different sections in real time.

[0043] The microscopic visualization sampler includes a sampling branch pipe 8, a pressure-resistant sampling container 9, an inlet valve 10, and an outlet valve 11. The pressure-resistant sampling container 9 is connected to a long, thin tube reducing assembly via the sampling branch pipe 8. The inlet and outlet of the pressure-resistant sampling container 9 are respectively equipped with inlet valve 10 and outlet valve 11. The pressure-resistant sampling container 9 is provided with an observation window 91. The outlet valve 11 is connected to the component analysis unit 100. The fluid flow pattern monitor 200 is located at the observation window 91 to achieve synchronous acquisition of microscopic fluid images and pressure data within the high-pressure sampling chamber. The pressure-resistant sampling container 9 is made of metal and can withstand high pressure. The fluid flow pattern monitor 200 is a purchased high-precision camera device.

[0044] The component analysis unit 100 includes one or more of a gas chromatograph, mass spectrometer, infrared analyzer, or Raman spectroscopy device. The component analysis unit 100 is used to detect the concentration or mole fraction of CO2, methane, ethane, propane, C4-C6 light and medium hydrocarbons, and heavy components in a fluid.

[0045] The matrix pore simulation section 1, microfracture channel simulation section 2, and fault shielding simulation section 3 are respectively disposed within the first temperature control device 12, and a second temperature control device 13 is disposed outside the microscopic visualization sampler. In this embodiment, the first temperature control device 12 is an oil bath heating box, and the second temperature control device 13 is a resistance heating jacket; wherein, the oil bath heating box is disposed on the outer periphery of the long thin tube diameter changing component, and is used to heat and keep the long thin tube diameter changing component warm; the resistance heating jacket covers the outside of the pressure-resistant sampling container 9, and is used to heat and keep the pressure-resistant sampling container 9 warm, so that the experimental system is maintained within a preset temperature range, the preset temperature range is 20~150℃, used to simulate different formation temperatures, and the temperature requirements of the microscopic visualization sampler and the long thin tube diameter changing component are the same.

[0046] The data processing system 300 is connected to the pressure sensor 7, the component analysis unit 100, the fluid flow pattern monitor 200, the first temperature control device 12, and the second temperature control device 13, respectively.

[0047] like Figure 5 As shown, the matrix pore simulation section 1 includes a coil 400 and a filling body 500 located inside the coil, wherein the filling body 500 is 50-80 mesh quartz sand.

[0048] like Figure 6As shown, the microcrack channel simulation section 2 includes a coil 400, a filling body 500 located within the coil, and a narrow-slot plate structure 600 embedded within the filling body. The narrow-slot plate structures are spaced apart along the axial direction of the coil. The filling body is 150-200 mesh quartz sand. The narrow-slot plate structure includes several elongated through-slots 601 and a sintered particle filling layer 602 filled within the elongated through-slots 601. The width, length, spacing, and number of slots per unit area of ​​the elongated through-slots 601 in the narrow-slot plate structure can be adjusted according to the experimental simulation requirements to change the flow resistance, shearing effect, and dispersion degree of the fluid within the coil. The elongated through-slots 601 are composed of narrow-slot plates, and a filling cavity can be formed between adjacent narrow-slot plates, which is filled with sintered particles. The sintered particles are confined between adjacent narrow-slot plates to avoid significant migration under the action of fluid scouring, and together with the narrow-slot plates, they form a composite flow structure with adjustable seepage channels. Before the coil is bent into shape, a narrow, elongated seam is pre-inserted into and fixed within the straight pipe section, and then the coil is formed. The direction of the seam is required, but it does not need to be limited to a single direction. It runs through the thickness of the thin plate, and adjacent narrow, elongated seams are staggered (see illustration). Figure 6 ).

[0049] The sintered particle filling layer 602 is formed by mixing and bonding sintered glass particles, sintered ceramic particles, sintered metal particles and sintered quartz particles. Its particle size is 10μm to 5mm, porosity is 10% to 60%, and permeability is 0.1mD to 100mD.

[0050] like Figure 7 As shown, the fault shielding simulation section 3 includes a coil 400, a filling body 500 located inside the coil, and a low-permeability filling layer 700 and / or a narrowing channel 800 disposed inside the filling body. The low-permeability filling layer and / or the narrowing channel are arranged at intervals along the axial direction of the coil. The filling body is 300-350 mesh quartz sand.

[0051] The low-permeability filling layer 700 includes porous baffles 701 spaced apart along the axial direction of the coil and porous media filler 702 disposed between the porous baffles. The porous media filler 702 is made of a mixture of quartz sand, glass beads, ceramic particles, core fragments and artificially sintered porous materials, with a particle size of 5μm to 10mm, a porosity of 5% to 70%, and a permeability of 0.001mD to 10mD.

[0052] The reduced diameter channel 800 is a reduced diameter sleeve or throttling ring arranged coaxially with the coil.

[0053] Two pressure-resistant sampling containers 9 are connected in series vertically upwards. The microscopic visualization sampler can be combined vertically, and through vertical series combination, segmented collection of oil and gas samples can be performed.

[0054] In this embodiment, the formation water injection unit 4 includes a first container 41 and a drive pump.

[0055] The crude oil injection unit 5 includes a second container 51 and a drive pump.

[0056] The CO2 injection unit 6 includes a third container 61 and a drive pump.

[0057] The first container 41, the second container 51, and the third container 61 all use the same driving pump, namely the first driving pump 14. The first driving pump 14 is connected to the first container 41, the second container 51, and the third container 61 respectively through a six-way valve 17. The first container 41, the second container 51, and the third container 61 are respectively connected to the control valve on the inlet side of the long and thin tube diameter changing assembly through pipes.

[0058] The long thin tube diameter changing assembly also includes a coil support 15 and a control valve 16. The matrix pore simulation section 1, the microcrack channel simulation section 2, and the fault shielding simulation section 3 are respectively arranged on the coil support 15.

[0059] Control valves 16 are respectively installed at the inlet and outlet of the matrix pore simulation section 1, the microcrack channel simulation section 2, and the fault shielding simulation section 3. The control valves 16 are equipped with quick-connect adapters 161 for connecting the pressure sensor 7 and the microscopic visualization sampler.

[0060] A multi-scale CO2 flooding multi-component migration quantitative monitoring method, implemented based on the aforementioned multi-scale CO2 flooding oil component migration monitoring device, includes the following steps: S1. Based on the pore structure, permeability distribution, fracture development degree, and fault shielding characteristics of the target reservoir, configure the structural parameters of matrix pore simulation section 1, microfracture channel simulation section 2, and fault shielding simulation section 3 in the long and thin tube variable diameter assembly to complete the construction of a multi-scale heterogeneous medium model. After sand filling, weigh the entire model M. i .

[0061] S2. Prepare simulated formation water and simulated crude oil, or select degassed crude oil from the target block; configure the CO2 injection state according to experimental requirements, and set the experimental temperature, pressure and back pressure conditions so that CO2 is in a gaseous, liquid, near-miscible or supercritical state.

[0062] S3. First, turn on the formation water injection unit and control the injection pump to saturate the device with water at a preset injection rate of 0.2 ml / min until the flow rate at the outlet section stabilizes. This is considered the saturation of formation water is complete. Weigh the entire model in m. wThe model pore volume was calculated; then the formation water injection unit was shut down, and the crude oil injection unit was opened. Crude oil was injected at a preset displacement rate of 0.2 ml / min to establish the initial oil saturation. When the displacement volume reached 20 PV, the model mass was weighed and recorded as m. o The oil saturation So of the model is calculated. The model mass is weighed at the end of each weighing process by closing the valves at both ends of the long, thin tube reducing assembly and disassembling the entire assembly for weighing. To reduce the number of operations, [the following steps can be taken]. Figure 4 Weigh it as a whole.

[0063] PV=(m w -M i ) / ρ(1) PV number = V i / PV(2) (3) In the formula, PV is the pore volume of the model, mL; Mi is the mass of the dried model, g; m w The mass of the model after saturation with water is g; m o ρ is the mass of the model after saturation with oil, in g; ρ is the density of the saturated fluid, in g / cm³. 3 V i The cumulative injected fluid volume is expressed in mL. Oil saturation, % The density of the aqueous phase is g / cm³. 3 ; The density of the oil phase is g / cm³. 3 PV number is dimensionless and is used to represent how many pore volumes of fluid have been injected.

[0064] S4. Open the CO2 injection unit, set the injection pump to inject CO2 into the device at a constant pressure. The injection pressure can be adjusted. The back pressure controls the degree of miscibility between CO2 and crude oil. When the CO2 displacement volume reaches 1.2 PV, record the final recovery rate.

[0065] S5. During the displacement process, a microscopic visualization sampler is used to acquire real-time images of the fluid front, i.e., the oil-gas interface images during fluid flow. The oil-gas interface is observed through a high-temperature, high-pressure transparent window. Pressure sensors are used to record pressure changes at various points. In addition, fluid samples from different locations can be collected periodically using the microscopic visualization sampler, and the sample collection locations are recorded. (t)(m), and the CO2 and the content of each hydrocarbon component are obtained by the component analysis unit. Calculate the apparent migration rate V of each component. k .

[0066] = (t)(4) (5) In the formula, The mole fraction or volume fraction of the k-th component at position x and time t; (t) represents the position of the k-th component at time t; k is the component number, namely C1, C2-C4, C5-C7, C8-C12, C13-C20, C21-C30, C30+, which can be assigned corresponding numbers according to the carbon number distribution; x is the distance from the injection port (m); t is the time (PV). Apparent migration rate of the k-th class of components, m / PV number.

[0067] S6. Based on the composition change patterns and image recognition results at different monitoring points, identify the location of the miscible zone and record the displacement efficiency of CO2 on crude oil under different miscible pressures.

[0068] like Figure 8 As shown, in step S6, the interface types corresponding to the image recognition results are: Type I: pure gas phase region; Type II: clear interface between oil and gas phases; Type III: blurred interface region; Type IV: single continuous phase region.

[0069] Identifying the location of the miscible zone involves directly observing the oil-gas interface during the displacement process using a microscopic visualization sampler, and identifying the location of the miscible zone based on changes in interface morphology. Specifically, this includes: When the oil and gas interface in the observation area exhibits one of the following states, it is determined to have entered the miscible transition zone: (1) The oil and gas interface gradually becomes blurred from a clear boundary; (2) The oil and gas two-phase interface cannot be clearly distinguished in some areas; By combining the change of interface position over time, the spatial distribution position X of the mixed phase zone is determined.

[0070] Taking a certain oilfield in Shengli as an example, multi-scale quantitative monitoring of CO2 flooding and multi-component migration was carried out according to the method described in this embodiment. This oilfield is a complex fault-block reservoir, in which the permeability of the matrix pore section is 5 mD and the permeability of the microfracture channel section is 10 mD. 3 mD and the permeability of the fault-blocked section are 10 -2 mD, miscibility pressure is 35.5 MPa.

[0071] In this embodiment, a microscopic visualization sampler 10 is set as a first monitoring point between the matrix pore segment 6 and the microfracture channel segment 7, and a microscopic visualization sampler 10 is set as a second monitoring point between the microfracture channel segment 7 and the fault-shielded segment 8. Component data at different locations are shown below. Figure 9Gas chromatography analysis showed that the concentration of light components below C15 was lower at the first monitoring point compared to the second monitoring point, while the concentration of light components increased significantly at the second monitoring point, indicating enhanced CO2 extraction capacity and that this point had entered the miscible region. The calculated migration rates of each component are shown in Table 1. The results indicate that the overall migration rate of light components is faster, with the approximate order being: C1 > C2-C4 > C5-C7 ≈ C8-C12 > C13-C20 > C21-C30 > C30+.

[0072] Table 1 Apparent migration rates of each component

[0073] In addition, six groups of displacement experiments were conducted under different pressures: 13.15 MPa, 18.00 MPa, 25.82 MPa, 32.05 MPa, 40.23 MPa, and 45.29 MPa. The crude oil recovery results are shown in […]. Figure 10 As the injection pressure increased, the crude oil recovery rate increased from 0.33 to 0.92.

Claims

1. A multi-scale CO2-driven oil displacement component migration monitoring device, characterized in that: It includes a long, thin tube diameter variable assembly, an injection system, a microscopic visualization sampler, a component analysis unit (100), a fluid flow pattern monitor (200), and a data processing system (300). The long, thin tube variable diameter assembly includes a matrix pore simulation section (1), a microcrack channel simulation section (2), and a fault shielding simulation section (3) connected in sequence. The fault shielding simulation section (3) is provided with a back pressure adjustment module (1000) on the outlet side. Multiple microscopic visualization samplers are spaced apart on the matrix pore simulation section (1), the microcrack channel simulation section (2), the fault shielding simulation section (3), between the matrix pore simulation section (1) and the microcrack channel simulation section (2), and between the microcrack channel simulation section (2) and the fault shielding simulation section (3). The matrix pore simulation section (1), the microcrack channel simulation section (2), and the fault shielding simulation section (3) are coil structures. The matrix pore simulation section (1) is filled with a filling material to simulate the matrix pore medium of a low-permeability reservoir. The microfracture channel simulation section (2) is filled with a filling material to simulate high-permeability fractures, natural microfractures or local dominant seepage channels developed in the reservoir. The fault shielding simulation section (3) is filled with a material to simulate fault gouge, dense interlayer, local sealing body or seepage abrupt interface; The injection system includes a formation water injection unit (4), a crude oil injection unit (5), and a CO2 injection unit (6). The outlet sides of the formation water injection unit (4), the crude oil injection unit (5), and the CO2 injection unit (6) are respectively connected to the inlet of the matrix pore simulation section (1). The formation water injection unit (4) is used to saturate water and establish initial water saturation. The crude oil injection unit (5) is used to inject simulated crude oil or degassed crude oil from the formation; The CO2 injection unit (6) is used to inject liquid, supercritical or gaseous CO2 into the device; Pressure sensors (7) are respectively installed at the inlet and outlet ends of the matrix pore simulation section (1), microcrack channel simulation section (2) and fault shielding simulation section (3). The microscopic visualization sampler includes a sampling branch pipe (8), a pressure-resistant sampling container (9), an inlet valve (10), and an outlet valve (11). The pressure-resistant sampling container (9) is connected to the long and thin tube reducing assembly through the sampling branch pipe (8). The inlet and outlet of the pressure-resistant sampling container (9) are respectively provided with an inlet valve (10) and an outlet valve (11). The pressure-resistant sampling container (9) is provided with an observation window (91). The outlet valve (11) is connected to the component analysis unit (100). The fluid flow pattern monitor (200) is located at the observation window (91). The matrix pore simulation section (1), microcrack channel simulation section (2) and fault shielding simulation section (3) are respectively set in the first temperature control device (12), and the micro-visual sampler is provided with a second temperature control device (13) on the outside. The data processing system (300) is connected to the pressure sensor (7), the component analysis unit (100), the fluid flow pattern monitor (200), the first temperature control device (12), and the second temperature control device (13), respectively.

2. The multi-scale CO2-driven oil displacement component migration monitoring device according to claim 1, characterized in that: The matrix pore simulation section (1) includes a coil (400) and a filling body (500) located inside the coil, wherein the filling body (500) is 50-80 mesh quartz sand; The microcrack channel simulation section (2) includes a coil (400), a filling body (500) located inside the coil, and a narrow slot plate structure (600) embedded in the filling body. The narrow slot plate structure is arranged at intervals along the axial direction of the coil. The filling body is 150-200 mesh quartz sand. The narrow slot plate structure includes several narrow through slots (601) and a sintered particle filling layer (602) filled in the narrow through slots (601). The sintered particle filling layer (602) is formed by mixing and bonding sintered glass particles, sintered ceramic particles, sintered metal particles and sintered quartz particles. Its particle size is 10μm to 5mm, porosity is 10% to 60%, and permeability is 0.1mD to 100mD. The fault shielding simulation section (3) includes a coil (400), a filling body (500) located inside the coil, and a low-permeability filling layer (700) and / or a narrowing channel (800) disposed inside the filling body. The low-permeability filling layer and / or narrowing channel are arranged at intervals along the axial direction of the coil. The filling body is 300-350 mesh quartz sand. The low-permeability filling layer (700) includes porous baffles (701) spaced apart along the coil axis and porous media filler (702) disposed between the porous baffles. The porous media filler (702) is made of a mixture of quartz sand, glass beads, ceramic particles, core fragments and artificially sintered porous materials, with a particle size of 5μm to 10mm, a porosity of 5% to 70%, and a permeability of 0.001mD to 10mD. The reduced diameter channel (800) is a reduced diameter sleeve or throttling ring arranged coaxially with the coil.

3. The multi-scale CO2-driven oil displacement component migration monitoring device according to claim 1, characterized in that: The equivalent permeability range of the matrix pore simulation section (1) is 0.1-10 mD; The equivalent permeability range of the simulated microcrack channel segment (2) is 10. 2 -10 4 mD; The equivalent permeability range of the fault-blocking simulation segment (3) is 10. -3 -10 -1 mD.

4. The multi-scale CO2-driven oil displacement component migration monitoring device according to claim 1, characterized in that: Two pressure-resistant sampling containers (9) are connected in series vertically upwards.

5. The multi-scale CO2-driven oil displacement component migration monitoring device according to claim 1, characterized in that: The component analysis unit (100) includes one or more of a gas chromatograph, mass spectrometer, infrared analyzer or Raman spectroscopy analyzer.

6. The multi-scale CO2-driven oil displacement component migration monitoring device according to claim 1, characterized in that: The formation water injection unit (4) includes a first container (41) and a drive pump; The crude oil injection unit (5) includes a second container (51) and a drive pump; The CO2 injection unit (6) includes a third container (61) and a drive pump.

7. The multi-scale CO2-driven oil displacement component migration monitoring device according to claim 6, characterized in that: The first container (41), the second container (51), and the third container (61) all use the same driving pump, namely the first driving pump (14). The first driving pump (14) is connected to the first container (41), the second container (51), and the third container (61) respectively through a six-way valve (17).

8. The multi-scale CO2-driven oil displacement component migration monitoring device according to claim 1, characterized in that: The long thin tube diameter changing assembly also includes a coil support (15) and a control valve (16). The matrix pore simulation section (1), the microcrack channel simulation section (2) and the fault shielding simulation section (3) are respectively set on the coil support (15). The inlet and outlet of the matrix pore simulation section (1), the microcrack channel simulation section (2), and the fault shielding simulation section (3) are respectively equipped with control valves (16); The control valve (16) is equipped with a quick-connect adapter (161).

9. A method for quantitative monitoring of multi-component migration in multi-scale CO2 flooding, implemented based on the multi-scale CO2 flooding component migration monitoring device according to any one of claims 1-8, characterized in that: Includes the following steps: S1. Based on the pore structure, permeability distribution, fracture development degree, and fault shielding characteristics of the target reservoir, configure the structural parameters of the matrix pore simulation section (1), microfracture channel simulation section (2), and fault shielding simulation section (3) in the long and thin tube variable diameter component, complete the construction of the multi-scale heterogeneous medium model, and weigh the entire model after sand filling treatment. i ; S2. Prepare simulated formation water and simulated crude oil, or select degassed crude oil from the target block; Configure the CO2 injection state according to experimental requirements, and set the experimental temperature, pressure and back pressure conditions to make CO2 be in a gaseous, liquid, near-miscible or supercritical state. S3. First, turn on the formation water injection unit and control the injection pump to saturate the device with water at a preset injection rate until the outlet flow rate stabilizes. This is considered the saturation of formation water is complete. Weigh the entire model (m). w The model pore volume was calculated; then the formation water injection unit was shut down, and the crude oil injection unit was opened. Crude oil was injected at a preset displacement rate to establish the initial oil saturation. When the displacement volume reached 20 PV, the model mass was weighed and recorded as m. o And calculate the oil saturation So of the model; PV=(m w -M i ) / ρ(1) PV number=V i / PV(2) （3） In the formula, PV is the pore volume of the model, mL; Mi is the mass of the dried model, g; m w The mass of the model after saturation with water is g; m o ρ is the mass of the model after saturation with oil, in g; ρ is the density of the saturated fluid, in g / cm³. 3 V i The cumulative injected fluid volume is expressed in mL. Oil saturation, % The density of the aqueous phase is g / cm³. 3 ; The density of the oil phase is g / cm³. 3 The PV number is dimensionless and is used to represent how many pore volumes of fluid have been injected. S4. Open the CO2 injection unit, set the injection pump to inject CO2 into the device at a constant pressure, adjust the injection pressure, and control the degree of miscibility between CO2 and crude oil with the back pressure. When the CO2 displacement volume reaches 1.2 PV, record the final recovery rate. S5. During the displacement process, a microscopic visualization sampler is used to acquire real-time images of the fluid front, and the oil-gas interface is observed through a high-temperature, high-pressure transparent window; pressure sensors are used to record pressure changes at various points; in addition, fluid samples are collected at different locations at regular intervals using the microscopic visualization sampler, and the sample collection locations are recorded. (t)(m) represents the fluid flow path length from the microscopic visualization sampler to the injection port of the matrix pore simulation section, and the CO2 and hydrocarbon component contents are obtained by the component analysis unit. Calculate the apparent migration rate V of each component. k ; = （t）（4） （5） In the formula, The mole fraction or volume fraction of the k-th component at position x and time t; (t) represents the position of the k-th component at time t; k is the component number; x is the distance from the injection port (m); t is the time (PV); Apparent migration rate of the k-th component, m / PV number; S6. Based on the composition change patterns and image recognition results at different monitoring points, identify the location of the miscible zone and record the displacement efficiency of CO2 on crude oil under different miscible pressures.

10. The method for quantitative monitoring of multi-component migration driven by multi-scale CO2 according to claim 9, characterized in that: In step S6, the interface type corresponding to the image recognition result is: Type I: Pure gas phase region; Type II: Clear oil-gas two-phase interface; Type III: Interface ambiguity region; Type IV: Single continuous phase region; Identifying the location of the miscible zone involves directly observing the oil-gas interface during the displacement process using a microscopic visualization sampler, and identifying the location of the miscible zone based on changes in interface morphology. Specifically, this includes: When the oil and gas interface in the observation area exhibits one of the following states, it is determined to have entered the miscible transition zone: (1) The oil and gas interface gradually becomes blurred from a clear boundary; (2) The oil and gas two-phase interface cannot be clearly distinguished in some areas; By combining the change of interface position over time, the spatial distribution position X of the mixed phase zone is determined.

Images