Method for determining carbon dioxide-water two-phase seepage relative permeability curve and method for determining reservoir porosity and permeability evolution under action of carbon dioxide

Abstract

The invention provides a method for determining a carbon dioxide-water two-phase seepage relative permeability curve and a method for determining reservoir porosity and permeability evolution under the action of carbon dioxide. The method for determining the relative permeability curve of the carbon dioxide-water two-phase seepage comprises the following steps: acquiring the dry weight of a rock core and the mass of the rock core saturated with formation water; under the simulated formation temperature and pressure condition, constant-speed injection of different kinds of fluid composed of saturated carbon dioxide formation water and gas-phase carbon dioxide with different flow ratios is sequentially carried out into a saturated water core; the pressure difference between the two ends of the rock core, the gas-phase carbon dioxide flow and the saturated carbon dioxide formation water flow after the injection pressure is stable in the injection process of various fluids are obtained; then the rock core is blow-dried with CO2, and the mass of the rock core blow-dried with CO2 is obtained; based on the obtained data, the water-phase relative permeability, the gas-phase relative permeability and the water saturation of the rock core are determined respectively when various kinds of fluid are injected, and then the carbon dioxide-water two-phase seepage relative permeability curve of the rock core is determined.

Description

Technical Field

[0001] The invention belongs to the technical field of unconventional oil and gas development, and particularly relates to a method for determining a carbon dioxide-water two-phase permeability curve applicable to a tight reservoir and a method for determining reservoir porosity and permeability evolution under the action of carbon dioxide. Background Art

[0002] CO 2 Huff and puff technology can effectively replenish formation energy, thereby extending the exhaustion recovery cycle of tight oil reservoirs after fracturing and improving crude oil recovery. Tight reservoirs have high water saturation. On the one hand, CO 2 The injection of formation water produces carbonic acid, which reacts physically and chemically with the reservoir matrix minerals, dissolves the minerals on the pore throat wall, increases the pore space, and has a certain microscopic reservoir transformation effect, thereby improving the fluid seepage capacity. On the other hand, clay minerals tend to swell, disperse, and migrate when they come into contact with water, resulting in serious water sensitivity in the reservoir, and clay particles block the small pore throats. 2 The mineral dissolution and reprecipitation caused by dissolution will affect the pore throat characteristics of porous media and further affect the multiphase seepage in tight reservoirs. However, dissolution characteristics and multiphase seepage laws are important bases for studying the seepage process of multiphase fluids in tight reservoirs. 2 It is of great significance in terms of migration mechanism, injection capacity evaluation and production capacity prediction.

[0003] The relative permeability curve can directly reflect the multiphase seepage law. 2 The measurement methods of the relative permeability curve of the two phases of carbon dioxide and water include the steady-state method and the non-steady-state method. The non-steady-state method obtains the real-time saturation of the fluid in the core by monitoring the fluid quality or X-ray at the outlet of the core container, and then obtains the real-time relative permeability of water and carbon dioxide. There are existing technologies that use the non-steady-state method to measure the relative permeability of CO2 in sandstone and carbonate formations in different regions. 2 - Water relative permeability, this technology monitors the gas phase flow and water phase flow at the core outlet to calculate the fluid saturation, the instrument error and measurement error are large, at the same time, this technology is time-consuming, CO 2 The tight core cannot be fully dissolved to change its pore throat characteristics, and the two-phase seepage characteristics of the core after dissolution do not change significantly. There are existing technologies that use CT scanning and other technologies to conduct core visualization displacement experiments. This technology measures the in-situ fluid saturation of porous media in real time to generate relative permeability curves. However, micro-CT can only measure micron-level pores, while nano-CT can measure nano- to micron-level pores and throats, but the sample size is generally at the millimeter level, making it difficult to measure the two-phase distribution in the core during the flow process. The applicability of this technology in tight oil reservoirs is limited. There are existing technologies that use the steady-state method to measure CO in sandstone formations in different regions. 2-water relative permeability, but the experimental samples used are not tight cores, with large porosity and permeability, and the conclusions have little guiding significance for tight oil development. 2 - Saltwater two-phase flow experiment, this method uses CT scanning technology to determine CO 2 saturation, and the porosity and permeability of the experimental samples are relatively large, not dense cores. 2 There are few reports on the research of two-phase flow of water and oil. In recent years, low-field nuclear magnetic resonance (LF-NMR) online measurement technology has gradually been applied to the field of tight oil development, but the instrument generally has an upper pressure limit of 20MPa, which cannot meet the pressure requirements of tight oil reservoirs.

[0004] In summary, due to the small pore throats and poor multiphase permeability of tight reservoir matrix, the multiphase flow experiment of tight core is more difficult. 2 There is a lack of research on dissolution characteristics and multiphase seepage. Advanced technologies such as X-ray CT scanning and nuclear magnetic resonance still have limitations in the application of tight oil. They cannot accurately characterize the physical properties of tight reservoirs, the device parameters cannot meet the conditions of tight oil reservoirs, and the experimental cost is high. Therefore, it is urgent to establish a method that can simply and accurately determine the CO2 content of tight reservoirs. 2 Dynamic dissolution of CO 2 -Technical solutions for the two-phase seepage law of water, and the ability to simply and accurately reflect the CO 2 Dynamic dissolution characteristics of CO 2 Technical solution for determining reservoir porosity and permeability evolution under the action of Summary of the invention

[0005] In view of the shortcomings of the prior art, the present invention aims to provide a method for simply and accurately determining the CO 2 Dynamic dissolution of CO 2 -water two-phase seepage law. The present invention also aims to provide a method that can simply and accurately reflect the CO 2 Dynamic dissolution characteristics of CO 2 Technical solution for determining reservoir porosity and permeability evolution under the action of

[0006] In order to achieve the above objectives, the present invention provides the following two technical solutions.

[0007] In a first aspect, the present invention provides a method for determining a carbon dioxide-water two-phase permeability curve, the method comprising:

[0008] 1) Obtain the dry weight of the core and the mass of the core after saturation with formation water;

[0009] 2) Under the conditions of simulated formation temperature and pressure, different types of fluids were injected into the water-saturated core at a constant rate in sequence, and the pressure difference at both ends of the core, the gas phase carbon dioxide flow rate, and the carbon dioxide-saturated formation water flow rate were obtained after the injection pressure of each type of fluid was stabilized during the injection process; then, the CO 2 Blow dry the core to obtain CO 2 The quality of the core after drying;

[0010] Among them, different types of fluids refer to fluids composed of saturated carbon dioxide formation water and gaseous carbon dioxide at different flow ratios, and different types of fluids include pure saturated carbon dioxide formation water fluid; during the constant rate injection of different types of fluids, the fluid with a high flow ratio of saturated carbon dioxide formation water and gaseous carbon dioxide is injected first, and then the fluid with a low flow ratio of saturated carbon dioxide formation water and gaseous carbon dioxide is injected, and the injection of the next type of fluid is performed after the former type of fluid is injected until the injection pressure is stable; the saturated water core is saturated with formation water or saturated carbon dioxide formation water;

[0011] 3) Based on the pressure difference at both ends of the core obtained in step 2), the flow rate of gas phase carbon dioxide and saturated formation water, and the flow rate data of carbon dioxide formation water, the water phase relative permeability and gas phase relative permeability of the core when various types of fluids are injected are determined respectively; based on the dry weight of the core, the mass of the core after saturation with formation water, CO 2 The mass of the dried core and the ratio of the carbon dioxide saturated formation water and gas phase carbon dioxide flow rate of each type of fluid are used to determine the water saturation of each type of fluid when injected;

[0012] 4) Based on the water phase relative permeability and gas phase relative permeability of the core when various types of fluids are injected, combined with the water saturation when various types of fluids are injected, the carbon dioxide-water two-phase seepage permeability curve of the core is determined.

[0013] The method for determining the permeability curve of carbon dioxide-water two-phase flow by steady-state method provided by the present invention uses formation water saturated with carbon dioxide and gas-phase carbon dioxide with different injection flow ratios to more accurately measure the CO2 content of reservoirs, especially tight reservoirs. 2-Relative permeability of water phases. In the prior art, formation water is usually used instead of saturated carbon dioxide formation water. The formation water will first dissolve carbon dioxide to a saturated state. This process takes a long time (more than 10 hours) and there are changes in components. The phase permeability law is complex and difficult to measure. At the same time, since the saturation process takes a long time, the core pore permeability changes during this period, and it is difficult to establish an accurate quantitative relationship between phase permeability and core pore permeability. The present invention uses saturated carbon dioxide formation water. Saturated carbon dioxide formation water no longer dissolves carbon dioxide to ensure that the entire experimental fluid system only includes a liquid phase (saturated carbon dioxide formation water) and a supercritical phase (supercritical carbon dioxide). Even if the acid-rock reaction consumes part of the dissolved carbon dioxide, the supercritical phase will quickly replenish and dissolve into the liquid phase, and the liquid phase is always kept in a saturated state. This process is closer to the actual mine situation of carbon dioxide flooding or carbon dioxide throughput, thereby ensuring a more accurate measurement of the CO2 content of the reservoir, especially the tight reservoir. 2 -Relative permeability of water two phases.

[0014] According to a preferred embodiment of the first aspect, during the constant rate injection process of different types of fluids, the sum of the gas phase carbon dioxide flow rate of each type of fluid is equal to the flow rate of saturated carbon dioxide formation water.

[0015] According to a preferred embodiment of the first aspect, during the constant rate injection of different types of fluids, the sum of the gas phase carbon dioxide flow rate of each type of fluid and the carbon dioxide saturated formation water flow rate is 0.3 mL min -1 .

[0016] According to a preferred embodiment of the first aspect, the different types of fluids include pure gas-phase carbon dioxide fluids.

[0017] According to a preferred embodiment of the first aspect, based on the pressure difference at both ends of the core, the flow rate of gas phase carbon dioxide and saturated carbon dioxide, and the flow rate data of carbon dioxide formation water obtained in step 2), respectively determining the water phase relative permeability and gas phase relative permeability of the core when various types of fluids are injected includes:

[0018] Based on the pressure difference at both ends of the core, the gas phase carbon dioxide flow rate and the flow rate data of carbon dioxide-saturated formation water obtained in step 2), respectively determine the water phase effective permeability and gas phase effective permeability of the core when various types of fluids are injected;

[0019] Based on the effective permeability of water phase and gas phase of the core when various types of fluids are injected, the effective permeability of water phase of the core when pure saturated carbon dioxide formation water fluid is injected is taken as the absolute permeability to determine the relative permeability of water phase and gas phase of the core when various types of fluids are injected.

[0020] Furthermore, the water phase effective permeability and gas phase effective permeability of the core are determined by the following formula:

[0021]

[0022]

[0023] In the formula, K gi is the gas phase effective permeability of the core when the i-th type of fluid is injected, μm 2 ;Q gi is the flow rate of gaseous carbon dioxide when the i-th type of fluid is injected, cm 3 ·s -1 ;μ g is the viscosity of gaseous carbon dioxide, mPa·s; L is the core length, cm; A is the cross-sectional area of ​​the core perpendicular to the fluid flow direction, cm 2 ; ΔP is the pressure difference between the two ends of the core, 10 -1 MPa; K wi is the liquid phase effective permeability of the core when the i-th type of fluid is injected, μm 2 ;Q wi is the flow rate of carbon dioxide saturated formation water when the i-th type of fluid is injected, cm 3 ·s -1 ;μ w is the viscosity of carbon dioxide-saturated formation water, mPa·s;

[0024] Furthermore, the water phase absolute permeability and gas phase absolute permeability of the core are determined by the following formula:

[0025]

[0026]

[0027] In the formula, K rgi K is the gas phase relative permeability of the core when the i-th type of fluid is injected, dimensionless; gi is the gas phase effective permeability of the core when the i-th type of fluid is injected, μm 2 ; K rwi is the liquid phase relative permeability of the core when the i-th type of fluid is injected, dimensionless; K wi is the liquid phase effective permeability of the core when the i-th type of fluid is injected, μm 2 ; K w1 is the effective permeability of the water phase in the core when pure carbon dioxide saturated formation water fluid is injected, μm 2 .

[0028] According to a preferred embodiment of the first aspect, based on the dry weight of the core, the mass of the core after saturation with formation water, CO 2The mass of the dried core and the ratio of the saturated carbon dioxide formation water and gas phase carbon dioxide flow rate of various types of fluids are used to determine the water saturation of various types of fluids when injected, including:

[0029] Based on the dry weight of the core, the mass of the core saturated with formation water, and the CO 2 The mass of the core after drying is used to determine the bound water saturation:

[0030] Based on the irreducible water saturation, combined with the flow rate ratio of saturated carbon dioxide formation water and gas phase carbon dioxide of various types of fluids, the water saturation of various types of fluids when injected is determined respectively; among which, the water saturation of pure saturated carbon dioxide formation water fluid when injected is 1;

[0031] Furthermore, the irreducible water saturation is determined by the following formula:

[0032]

[0033] In the formula, S wf7 is the bound water saturation, dimensionless; m 1 is the core dry weight, g; m 2 is the mass of the core after CO2 drying, g; m 3 is the mass of the core after saturation with formation water, g;

[0034] Furthermore, the water saturation of each type of fluid when injected is determined by the following formula:

[0035]

[0036] In the formula, S wi is the water saturation of the i-th type of fluid when injected, dimensionless; S wf7 is bound water saturation, dimensionless; Q i is the flow rate ratio of carbon dioxide saturated formation water to gas phase carbon dioxide of the ith type of fluid, dimensionless.

[0037] In a second aspect, the present invention provides a method for determining reservoir porosity and permeability evolution under the action of carbon dioxide, the method comprising:

[0038] Determine the carbon dioxide-water two-phase seepage phase permeability curve of the reservoir core before and after aging with saturated carbon dioxide formation water using the method for determining the carbon dioxide-water two-phase seepage phase permeability curve provided in the first aspect;

[0039] Determine the mineralogical composition of reservoir cores before and after aging with CO2-saturated formation water;

[0040] Determine the porosity of reservoir cores before and after aging with CO2-saturated formation water;

[0041] Determine the pore size distribution of reservoir cores before and after aging with CO2-saturated formation water;

[0042] The porosity and permeability evolution of the reservoir under the action of carbon dioxide is characterized by changes in the carbon dioxide-water two-phase seepage phase permeability curve of the reservoir core before and after aging with saturated carbon dioxide formation water, changes in the mineral composition of the reservoir core before and after aging with saturated carbon dioxide formation water, changes in the porosity of the reservoir core before and after aging with saturated carbon dioxide formation water, and changes in the pore size distribution of the reservoir core before and after aging with saturated carbon dioxide formation water.

[0043] According to a preferred embodiment of the second aspect, the mineral composition is determined using an X-ray diffractometer.

[0044] According to a preferred embodiment of the second aspect, the porosity determination is performed using a helium porosimeter.

[0045] According to a preferred embodiment of the second aspect, the pore size distribution is determined based on a nuclear magnetic resonance experiment; specifically, by detecting the signal of hydrogen atoms in the core saturated water and performing a propagation analysis, the distribution characteristics of the fluid in the core matrix are determined, and then the distribution characteristics of the pore size in the core are obtained.

[0046] According to a preferred embodiment of the second aspect, the method further comprises:

[0047] Determine gas-tested permeability of reservoir cores before and after aging with CO2-saturated formation water;

[0048] The changes in gas permeability of reservoir cores before and after aging with saturated carbon dioxide formation water are used to characterize the porosity and permeability evolution of the reservoir under the action of carbon dioxide.

[0049] According to a preferred embodiment of the second aspect, when the method for determining the carbon dioxide-water two-phase seepage phase permeability curve provided by the first aspect is used to determine the carbon dioxide-water two-phase seepage phase permeability curve of the reservoir core before aging with saturated carbon dioxide formation water, the saturated water core is saturated with formation water;

[0050] When the method for determining the carbon dioxide-water two-phase seepage phase permeability curve provided in the first aspect is used to determine the carbon dioxide-water two-phase seepage phase permeability curve of the reservoir core after aging with saturated carbon dioxide formation water, the saturated water core is saturated with saturated carbon dioxide formation water.

[0051] According to a preferred embodiment of the second aspect, the method for determining the porosity and permeability evolution of a reservoir under the action of carbon dioxide utilizes an integrated multifunctional CO 2 Dynamic dissolution test device is used; the integrated multifunctional CO 2 The dynamic corrosion test device includes:

[0052] Core sample device, confining pressure system, back pressure system, fluid supply system, fluid control system, sensor system, experimental control and safety system, data recording and analysis system;

[0053] The core sample device includes a core holder and a bracket for fixing the core holder, thereby ensuring that the core sample remains in a fixed position;

[0054] The fluid supply system includes a first ISCO pump, a second ISCO pump, a first ultrapure water storage tank, a second ultrapure water storage tank, a CO 2 Intermediate container, booster pump, formation water intermediate container, CO 2 gas cylinder, helium cylinder; the outlet of the first ultrapure water storage tank is connected to the inlet of the first ISCO pump, and the outlet of the first ISCO pump is connected to the CO 2 The bottom of the intermediate container is connected, the outlet of the second ultrapure water storage tank is connected to the inlet of the second ISCO pump, and the outlet of the second ISCO pump is connected to the bottom of the formation water intermediate container, CO 2 The outlet of the gas cylinder is connected to the inlet of the booster pump, and the outlet of the booster pump is connected to the CO 2 Intermediate container, top connection of formation water intermediate container, helium cylinder, CO 2 The top of the intermediate container and the top of the formation water intermediate container are respectively connected to the fluid inlet of the core holder;

[0055] The confining pressure system includes a confining pressure pump, which is connected to the core holder;

[0056] The back pressure system includes a back pressure pump and a back pressure valve connected in sequence, and the outlet of the back pressure valve is connected to the core holder;

[0057] The sensor system includes a pressure sensor and a temperature sensor, wherein the pressure sensor is used to obtain pressure, temperature and core nuclear magnetic resonance data;

[0058] The fluid control system includes a control valve disposed on each connecting pipeline to control fluid transmission;

[0059] The data recording and analysis system is used to transmit the data acquired by the sensor to a computer for recording and analysis;

[0060] The experimental control and safety system includes control software, power adapter and safety valve to ensure safe operation and control of experimental parameters.

[0061] The above integrated multifunctional CO 2 The dynamic dissolution test device can simply and accurately measure the CO 2 Dynamic dissolution porosity, permeability, and phase permeability curves can be tested in the same chamber throughout the entire process. It can accurately measure and continuously record the CO2 -Related test data of relative permeability of water phases, reduce the influence of human error and uncertain factors, save time. It can meet the requirements of testing core physical properties at different temperatures and pressures, and realize physical property detection requirements within different temperature and pressure ranges. Compared with other single-density core detection instruments, it can obtain higher and more accurate precision and achieve a wider range of experimental conditions.

[0062] According to a preferred embodiment of the second aspect, the fluid supply system is used to provide the required fluid, including CO 2 Gas, ultrapure water, formation water, saturated carbon dioxide formation water and helium; the fluid control system is used to accurately control the flow, pressure and supply rate of the fluid to ensure the accuracy and repeatability of the experimental parameters.

[0063] The system has adjustable performance and can simulate the dissolution process under different fluid media. It is also equipped with sensors and monitoring equipment to monitor fluid properties such as temperature, pressure and flow rate in real time to ensure the controllability of the experiment, provide high-quality fluid supply, and ensure the reliability and accuracy of the experimental data.

[0064] In order to accurately control the flow, pressure and supply speed of liquids and gases to meet the requirements of experimental parameters, the fluid control system is first configured to accurately adjust the parameters of fluid supply according to specific experimental requirements when measuring data, including the flow rate, pressure and temperature of liquids and gases to ensure that the experiment is under control. Precise control of fluids is achieved through timeable valves, gas supply valves, and pressure regulating valves. This precision and adjustability help ensure the accuracy and repeatability of the experiment to achieve a high degree of automation and data integration.

[0065] According to a preferred embodiment of the second aspect, the confining pressure system is capable of setting the initial confining pressure and temperature and maintaining high pressure conditions to simulate underground reservoir conditions. During the experiment, it stabilizes and monitors these conditions to ensure that they meet the requirements. Subsequently, the experiment is carried out with CO 2 Dynamic dissolution, the confining pressure system continuously maintains high pressure conditions to ensure that the experiment is close to the actual situation. The system also records pressure and temperature data for subsequent analysis. The technical solution provided by the present invention comprehensively considers CO 2 Effect of pore throat characteristics changes under dynamic dissolution on supercritical CO 2 -The influence of relative permeability of water and water phases solves the problem of CO 2 During the huff and puff process, it is difficult to measure CO due to the small pore throats of the matrix and poor multiphase permeability. 2 Dynamic dissolution characteristics and CO 2 -The relative permeability of water phase can be simply and accurately measured in tight reservoir CO 2 Dynamic dissolution characteristics and CO 2-water two-phase relative permeability. The method for determining the carbon dioxide-water two-phase permeability curve provided by the present invention fully utilizes the advantages of the steady-state method. In the process of the multiphase fluid slowly reaching a stable state, carbonic acid continues to dissolve the core, which better reflects the CO 2 Two-phase seepage law under dynamic dissolution. The method for determining reservoir porosity and permeability evolution under the action of carbon dioxide provided by the present invention integrates the changes in the carbon dioxide-water two-phase seepage phase permeability curve, mineral composition changes, porosity changes, and pore size distribution changes of the reservoir core before and after aging with saturated carbon dioxide formation water to characterize the reservoir porosity and permeability evolution. BRIEF DESCRIPTION OF THE DRAWINGS

[0066] Figure 1 is the CO used in Example 1 2 Schematic diagram of the dynamic dissolution evaluation device.

[0067] Figure 2 This is the mineral composition diagram of the reservoir core in Example 1 before aging with saturated carbon dioxide formation water.

[0068] Figure 3 is the T of the reservoir core in Example 1 before aging with saturated carbon dioxide formation water 2 Atlas.

[0069] Figure 4 This is a permeability curve of the carbon dioxide-water two-phase seepage of the reservoir core in Example 1 before aging with saturated carbon dioxide formation water.

[0070] Figure 5 This is a permeability curve diagram of the carbon dioxide-water two-phase seepage before and after aging the reservoir core in Example 1 using saturated carbon dioxide formation water.

[0071] Figure 6 This is the mineral composition diagram of the reservoir core in Example 1 before and after aging with saturated carbon dioxide formation water.

[0072] Figure 7 This is the gas permeability diagram of the reservoir core in Example 1 before and after aging with saturated carbon dioxide formation water.

[0073] Figure 8 is the T of the reservoir core in Example 1 before and after aging with saturated carbon dioxide formation water 2 Atlas. DETAILED DESCRIPTION

[0074] In order to make the purpose, technical solution and advantages of the embodiment of the present invention clearer, the technical solution in the embodiment of the present invention will be clearly and completely described below in conjunction with the drawings in the embodiment of the present invention. Obviously, the described embodiment is a part of the embodiment of the present invention, not all of the embodiments. Based on the embodiment of the present invention, all other embodiments obtained by ordinary technicians in this field without making creative work belong to the protection scope of the present invention.

[0075] Example 1

[0076] This embodiment provides a method for determining reservoir porosity and permeability evolution under the action of carbon dioxide, which specifically includes the following steps:

[0077] Step 1: Connect Figure 1 The CO shown 2 Dynamic dissolution evaluation device.

[0078] CO 2 The dynamic corrosion evaluation device mainly consists of the first ISCO pump 1, the first ultrapure water storage tank 2, CO 2 Gas cylinder 3, booster pump 5, CO 2 The intermediate container 7, the formation water intermediate container 8, the pressure sensor 9, the pressure regulating valve 10, the gas supply valve 11, the gas flow meter 12, the dryer 13, the vent valve 14, the temperature sensor 16, the bracket 17, the helium cylinder 18, the core clamp 19, the back pressure valve 20, the back pressure pump 21, the confining pressure pump 22, the gas-liquid separator 23, the second ISCO pump 24, the second ultrapure water storage tank 25, etc. are specifically as follows Figure 1 As shown. The core holder 19 is provided with a core loading area 15 to be tested. The device uses a large amount of corrosion-resistant materials such as polytetrafluoroethylene and 316L steel, such as polytetrafluoroethylene coated sealing rings and 316L steel core holders, which greatly reduces CO 2 It has excellent sealing performance and is resistant to high temperature and corrosion.

[0079] The core holder 19 and the bracket 17 are fixed to ensure that the core sample remains in a fixed position; the outlet of the first ultrapure water storage tank 2 is connected to the inlet of the first ISCO pump 1, and the outlet of the first ISCO pump 1 is connected to the CO 2 The bottom of the intermediate container 7 is connected, the outlet of the second ultrapure water storage tank 25 is connected to the inlet of the second ISCO pump 24, and the outlet of the second ISCO pump 24 is connected to the bottom of the formation water intermediate container 8, CO 2 The outlet of the gas cylinder 3 is connected to the inlet of the booster pump 5, and the outlet of the booster pump 5 is connected to the CO 2 The top of the intermediate container 7 and the formation water intermediate container 8 are connected, the helium cylinder 18, the CO 2The top of the intermediate container 7 and the top of the formation water intermediate container 8 are respectively connected to the fluid inlet of the core clamp 19; the confining pressure pump 22 is connected to the core clamp 19; the back pressure pump 21 is connected to the back pressure valve 20, and the outlet of the back pressure valve 20 is connected to the core clamp 19; the gas supply valve 11 and the pressure regulating valve 10 are sequentially arranged on the connecting pipeline between the helium bottle 18 and the fluid inlet of the core clamp 19; the gas flow meter 12, the dryer 13, and the pressure sensor 9 are arranged at the fluid inlet of the core clamp 19; the vent valve 14 and the temperature sensor 16 are respectively connected to the core clamp 19 to realize the venting of the core clamp 19 and the acquisition of temperature data; the gas-liquid separator 23 is connected to the fluid outlet of the core clamp 19 to realize the gas-liquid separation of the fluid discharged from the core clamp 19.

[0080] The CO 2 The dynamic dissolution evaluation device also includes a fluid control system, an experimental control and safety system, and data recording; the fluid control system includes a control valve 6 arranged on each connecting pipeline to control fluid transmission; the data recording and analysis system is used to transmit the data obtained by each sensor to a computer for recording and analysis; the experimental control and safety system includes control software, a power adapter and a safety valve to ensure safe operation and control of experimental parameters.

[0081] Step 2: Obtain the target tight reservoir core, characterize the physical properties of the target tight reservoir core, including mineral composition, porosity, gas permeability, and pore size distribution, and obtain the mineral composition, porosity, gas permeability, and pore size distribution of the target tight reservoir core before aging using saturated carbon dioxide to simulate formation water; specifically including:

[0082] The target tight reservoir core is dried and its dry weight is weighed;

[0083] The mineral composition of the target tight reservoir core was analyzed by X-ray diffractometer to obtain the mineral composition of the tight core before dissolution. The results are as follows: Figure 2 shown.

[0084] After the dried target tight reservoir core is fully saturated with simulated water, a low-field nuclear magnetic resonance online displacement evaluation device is used to conduct a nuclear magnetic resonance experiment to obtain the T of the target tight reservoir rock. 2 Spectra, such as Figure 3 As shown, based on the T of the target tight reservoir rock 2 The map determines the distribution characteristics of the pore size of the target tight reservoir rock.

[0085] Load the target tight reservoir core into the CO 2The dynamic dissolution evaluation device is specifically loaded into the core holder, and a standard core gasket is placed, and confining pressure is applied. Close the valves on the left and right sides of the core holder, and open the valves on the left and right sides of the core holder after the target tight reservoir core is vacuumed; open the gas source valve and the gas supply valve of the helium bottle, and adjust the pressure regulating valve to remove the air in the pipeline. Then increase the pressure of the standard gas chamber to about 200psi, close the gas supply valve, and record P1 after the pressure stabilizes. Then close the vent valve, open the sample valve, and wait for the pressure to stabilize and record P2. Based on Darcy's law and record the core length, diameter, P1, and P2 using the matching porosity calculation software, the porosity of the target tight reservoir core can be measured. The results are shown in Table 1. For other single porosity measuring instruments (such as water saturation measuring instruments, drying measuring instruments, and density measuring instruments, etc.), the accuracy range of these instruments for testing porosity is usually between 1% and 5%. This means that when using conventional instruments to measure porosity, the results are subject to an error range of about 1% to 5%. 2 The dynamic dissolution test device has obvious advantages over traditional instruments in porosity measurement. It can provide higher measurement accuracy, between 0.1% and 1%. This makes the measurement results closer to the true value and reduces the measurement error.

[0086] Then, the target tight reservoir core was characterized by gas permeability based on one-dimensional steady-state seepage theory. The gas permeability of the target tight reservoir core was 0.185×10 -3 μm 2 .

[0087] Table 1

[0088] Length (cm) Diameter(cm) <![CDATA[P 1 (Psi)]]> <![CDATA[P 2 (Psi)]]> Porosity(%) 4.934 2.532 207 112 12.44

[0089] Step 3: Determine the target reservoir core and use saturated carbon dioxide to simulate the carbon dioxide-water two-phase seepage permeability curve before formation water aging. Specifically include:

[0090] 1) Vacuum and pressurize the target reservoir core to saturate it with simulated formation water, and weigh the mass of the core saturated with simulated formation water;

[0091] 2) Conduct steady-state experiments on target reservoir cores under simulated formation temperature and pressure conditions, including:

[0092] CO 2 The dynamic corrosion evaluation device was preheated to simulate the formation temperature of 44°C, and the CO was pumped into the device at an experimental pressure of 15 MPa using an ISCO pump. 2 Injecting into simulated formation water to prepare saturated carbon dioxide simulated formation water (i.e. saturated carbonic acid);

[0093] CO 2The back pressure of the dynamic dissolution evaluation device was increased to the experimental pressure of 15 MPa, and the confining pressure was set to track the pressure difference of 3.5 MPa (the confining pressure was always greater than the injection pressure of 3.5 MPa);

[0094] Two ISCO pumps were used to pump the gas phase CO 2 The saturated carbon dioxide simulated formation water was injected into the core at a constant rate according to the flow rate ratio set in Table 2. That is, the gas phase CO with different flow rate ratios was injected into the core in turn. 2 The constant-rate injection of different types of fluids composed of saturated carbon dioxide simulated formation water and saturated carbon dioxide simulated formation water was performed, and the pressure difference at both ends of the core, the gas phase carbon dioxide flow rate and the saturated carbon dioxide simulated formation water flow rate were recorded after the injection pressure of each type of fluid was stable. In the constant-rate injection of different types of fluids, the fluid with a high flow rate ratio of saturated carbon dioxide simulated formation water and gas phase carbon dioxide was injected first, and then the fluid with a low flow rate ratio of saturated carbon dioxide simulated formation water and gas phase carbon dioxide was injected, and the injection of the first type of fluid was carried out after the injection pressure was stable; the gas phase CO 2 The sum of the flow rates of the simulated formation water and saturated carbon dioxide was maintained at 0.3 mL min -1 ;

[0095] Utilizing CO 2 The core was dried with gas to prevent the residual simulated water from crystallizing in the core. The core was taken out and the CO 2 The quality of the core after drying.

[0096] Table 2

[0097]

[0098] 3) Based on the pressure difference at both ends of the core, the gas phase carbon dioxide flow rate and the flow rate data of saturated carbon dioxide simulated formation water obtained in step 2), the water phase effective permeability and gas phase effective permeability of the target reservoir core before aging of saturated carbon dioxide simulated formation water when various types of fluids are injected are determined by the following formulas:

[0099]

[0100]

[0101] In the formula, K gi is the gas phase effective permeability of the core when the i-th type of fluid is injected, μm 2 ;Q gi is the flow rate of gaseous carbon dioxide when the i-th type of fluid is injected, cm 3 ·s -1 ;μ g is the viscosity of gaseous carbon dioxide, mPa·s; L is the core length, cm; A is the cross-sectional area of ​​the core perpendicular to the fluid flow direction, cm2 In this embodiment, A=πr 2 , r is the core radius measured; ΔP is the pressure difference between the two ends of the core, 10 -1 MPa; K wi is the liquid phase effective permeability of the core when the i-th type of fluid is injected, μm 2 ;Q wi is the flow rate of saturated carbon dioxide simulating formation water when the i-th type of fluid is injected, cm 3 ·s -1 ;μ w is the viscosity of simulated formation water saturated with carbon dioxide, mPa·s;

[0102] Based on the effective water phase permeability and gas phase effective permeability of the target reservoir core before aging of formation water simulated by saturated carbon dioxide when various types of fluids are injected, the effective water phase permeability of the target reservoir core before aging of formation water simulated by saturated carbon dioxide when pure saturated carbon dioxide is injected to simulate formation water fluid is taken as the absolute permeability. The water phase relative permeability and gas phase relative permeability of the target reservoir core before aging of formation water simulated by saturated carbon dioxide when various types of fluids are injected are determined by the following formulas:

[0103]

[0104]

[0105] In the formula, K rgi K is the gas phase relative permeability of the core when the i-th type of fluid is injected, dimensionless; gi is the gas phase effective permeability of the core when the i-th type of fluid is injected, μm 2 ; K rwi is the liquid phase relative permeability of the core when the i-th type of fluid is injected, dimensionless; K wi is the liquid phase effective permeability of the core when the i-th type of fluid is injected, μm 2 ; K w1 is the effective permeability of the water phase in the core when pure saturated carbon dioxide is injected to simulate formation water fluid, μm 2 .

[0106] See Table 3 for specific results.

[0107] In this embodiment, because the simulated formation water is fully saturated with carbon dioxide, the gas phase CO 2 During the simultaneous injection of saturated carbon dioxide and simulated formation water, it is believed that the gas phase and liquid phase are immiscible with each other, which can better meet the conditions for accurate permeability measurement using the steady-state method.

[0108] 4) Based on the dry weight of the core, the mass of the core saturated with simulated formation water, and CO 2The mass of the dried core is used to determine the bound water saturation using the following formula:

[0109]

[0110] In the formula, S wf7 is the bound water saturation, dimensionless; m 1 is the core dry weight, g; m 2 is the mass of the core after CO2 drying, g; m 3 is the mass of the core after saturation with simulated formation water, g;

[0111] Based on the irreducible water saturation, combined with the flow rate ratio of saturated carbon dioxide simulated formation water and gas phase carbon dioxide of various types of fluids, the water saturation of various types of fluids when injected is determined respectively; among which, the water saturation of pure saturated carbon dioxide simulated formation water fluid when injected is 1; among which, the water saturation of various types of fluids when injected is determined by the following formula:

[0112]

[0113] In the formula, S wi is the water saturation of the i-th type of fluid when injected, dimensionless; S wf7 is bound water saturation, dimensionless; Q i is the ratio of the flow rate of formation water and gas-phase carbon dioxide simulated by the carbon dioxide saturated in the i-th type of fluid, dimensionless.

[0114] See Table 3 for specific results.

[0115] Table 3

[0116]

[0117]

[0118] 5) Based on the water phase relative permeability and gas phase relative permeability of the target reservoir core before aging of formation water simulated by saturated carbon dioxide when various types of fluids were injected, combined with the water saturation when various types of fluids were injected, the carbon dioxide-water two-phase permeability curve of the target reservoir core before aging of formation water simulated by saturated carbon dioxide was determined. The results are as follows Figure 4 shown.

[0119] Step 4: Reload the target reservoir core into the CO 2 In the dynamic dissolution evaluation device, the temperature was raised to 44°C, and saturated carbon dioxide simulated formation water was injected into the core at a constant experimental pressure of 15 MPa to saturate the target reservoir core with saturated carbon dioxide simulated formation water. The core was left to stand for more than 48 hours for aging to allow the saturated carbon dioxide simulated formation water to fully dissolve the core minerals and ensure that the core was CO 2Fully dissolved in CO 2 The pore throat structure of the dense core changes under dissolution, and the target reservoir core is obtained after aging with saturated carbon dioxide to simulate formation water.

[0120] Step 5: Determine the permeability curve of the target reservoir core using saturated carbon dioxide to simulate the carbon dioxide-water two-phase flow after formation water aging. Specifically include:

[0121] 1) Drying and weighing the target reservoir core after aging with saturated carbon dioxide simulated formation water to obtain the dry weight of the core; vacuuming and pressurizing the dried target reservoir core to saturate it with simulated formation water, and weighing the mass of the core after saturation with simulated formation water;

[0122] 2) The target reservoir core that has been aged with saturated carbon dioxide to simulate formation water is vacuumed and pressurized to saturate with saturated carbon dioxide to simulate formation water, and the core saturated with saturated carbon dioxide to simulate formation water is loaded into the CO 2 In the dynamic corrosion evaluation device, CO 2 Dynamic dissolution evaluation device, to conduct steady-state experiments on target reservoir cores under simulated formation temperature and pressure conditions, including:

[0123] CO 2 The back pressure of the dynamic dissolution evaluation device was increased to the experimental pressure of 15 MPa, and the confining pressure was set to track the pressure difference of 3.5 MPa (the confining pressure was always greater than the injection pressure of 3.5 MPa);

[0124] Two ISCO pumps were used to pump the gas phase CO 2 The saturated carbon dioxide simulated formation water was injected into the core at a constant rate according to the flow rate ratio set in Table 2. That is, the gas phase CO with different flow rate ratios was injected into the core in turn. 2 The constant-rate injection of different types of fluids composed of saturated carbon dioxide simulated formation water and saturated carbon dioxide simulated formation water was performed, and the pressure difference at both ends of the core, the gas phase carbon dioxide flow rate and the saturated carbon dioxide simulated formation water flow rate were recorded after the injection pressure of each type of fluid was stable. In the constant-rate injection of different types of fluids, the fluid with a high flow rate ratio of saturated carbon dioxide simulated formation water and gas phase carbon dioxide was injected first, and then the fluid with a low flow rate ratio of saturated carbon dioxide simulated formation water and gas phase carbon dioxide was injected, and the injection of the first type of fluid was carried out after the injection pressure was stable; the gas phase CO 2 The sum of the flow rates of the simulated formation water and saturated carbon dioxide was maintained at 0.3 mL min -1 ;

[0125] Utilizing CO 2 The core was dried with gas to prevent the residual simulated water from crystallizing in the core. The core was taken out and the CO 2 The quality of the core after drying.

[0126] 3) Based on the pressure difference at both ends of the core, the gas phase carbon dioxide flow rate and the flow rate data of saturated carbon dioxide simulated formation water obtained in step 2), the water phase effective permeability and gas phase effective permeability of the target reservoir core after aging of saturated carbon dioxide simulated formation water when various types of fluids are injected are determined by the following formulas:

[0127]

[0128]

[0129] In the formula, K gi is the gas phase effective permeability of the core when the i-th type of fluid is injected, μm 2 ;Q gi is the flow rate of gaseous carbon dioxide when the i-th type of fluid is injected, cm 3 ·s -1 ;μ g is the viscosity of gaseous carbon dioxide, mPa·s; L is the core length, cm; A is the cross-sectional area of ​​the core perpendicular to the fluid flow direction, cm 2 In this embodiment, A=πr 2 , r is the core radius measured; ΔP is the pressure difference between the two ends of the core, 10 -1 MPa; K wi is the liquid phase effective permeability of the core when the i-th type of fluid is injected, μm 2 ;Q wi is the flow rate of saturated carbon dioxide simulating formation water when the i-th type of fluid is injected, cm 3 ·s -1 ;μ w is the viscosity of simulated formation water saturated with carbon dioxide, mPa·s;

[0130] Based on the effective water phase permeability and gas phase effective permeability of the target reservoir core after aging of formation water simulated by saturated carbon dioxide when various types of fluids are injected, the effective water phase permeability of the core when pure saturated carbon dioxide is injected to simulate formation water fluid is taken as the absolute permeability. The water phase relative permeability and gas phase relative permeability of the target reservoir core after aging of formation water simulated by saturated carbon dioxide when various types of fluids are injected are determined by the following formulas:

[0131]

[0132]

[0133] In the formula, K rgi K is the gas phase relative permeability of the core when the i-th type of fluid is injected, dimensionless; gi is the gas phase effective permeability of the core when the i-th type of fluid is injected, μm 2 ; K rwiis the liquid phase relative permeability of the core when the i-th type of fluid is injected, dimensionless; K wi is the liquid phase effective permeability of the core when the i-th type of fluid is injected, μm 2 ; K w1 is the effective permeability of the water phase in the core when pure saturated carbon dioxide is injected to simulate formation water fluid, μm 2 .

[0134] See Table 4 for specific results.

[0135] 4) Based on the dry weight of the core, the mass of the core saturated with simulated formation water, and CO 2 The mass of the dried core is used to determine the bound water saturation using the following formula:

[0136]

[0137] In the formula, S wf7 is the bound water saturation, dimensionless; m 1 is the core dry weight, g; m 2 is the mass of the core after CO2 drying, g; m 3 is the mass of the core after saturation with simulated formation water, g;

[0138] Based on the irreducible water saturation, combined with the flow rate ratio of saturated carbon dioxide simulated formation water and gas phase carbon dioxide of various types of fluids, the water saturation of various types of fluids when injected is determined respectively; among which, the water saturation of pure saturated carbon dioxide simulated formation water fluid when injected is 1; among which, the water saturation of various types of fluids when injected is determined by the following formula:

[0139]

[0140] In the formula, S wi is the water saturation of the i-th type of fluid when injected, dimensionless; S wf7 is bound water saturation, dimensionless; Q i is the ratio of the flow rate of formation water and gas-phase carbon dioxide simulated by the carbon dioxide saturated in the i-th type of fluid, dimensionless.

[0141] See Table 4 for specific results.

[0142] Table 4

[0143]

[0144] 5) Based on the water phase relative permeability and gas phase relative permeability of the target reservoir core after aging of formation water simulated by saturated carbon dioxide when various types of fluids were injected, combined with the water saturation when various types of fluids were injected, the carbon dioxide-water two-phase permeability curve of the target reservoir core after aging of formation water simulated by saturated carbon dioxide was determined. The results are as follows Figure 5 shown.

[0145] Step 6: Refer to step 2 to determine the mineral composition, porosity, gas permeability, and pore size distribution of the target tight reservoir core after aging with saturated carbon dioxide to simulate formation water. The results are as follows: Figure 6-Figure 8 As shown in Table 5, the gas permeability of the target tight reservoir after aging with saturated carbon dioxide to simulate formation water is 0.207×10 -3 μm 2 .

[0146] Step 7: Use saturated carbon dioxide to simulate the changes in the carbon dioxide-water two-phase seepage curve, mineral composition, porosity, pore size distribution, and gas permeability before and after formation water aging using saturated carbon dioxide in the target tight reservoir core to characterize the porosity and permeability evolution of the target tight reservoir under the action of carbon dioxide.

[0147] Table 5

[0148]

[0149] The specific embodiments described above further illustrate the objectives, technical solutions and beneficial effects of the present invention in detail. It should be understood that the above description is only a specific embodiment of the present invention and is not intended to limit the scope of protection of the present invention. Any modifications, equivalent substitutions, improvements, etc. made within the spirit and principles of the present invention should be included in the scope of protection of the present invention.

Claims

1. A method for determining the permeability curve of carbon dioxide-water two-phase flow, the method include: 1) Obtain the dry weight of the core and the mass of the core after saturation with formation water; 2) Under the conditions of simulated formation temperature and pressure, different types of fluids were injected into the water-saturated core at a constant rate in sequence, and the pressure difference at both ends of the core, the gas phase carbon dioxide flow rate, and the carbon dioxide-saturated formation water flow rate were obtained after the injection pressure of each type of fluid was stabilized during the injection process; then, the CO 2 Blow dry the core to obtain CO 2 The quality of the core after drying; different types of fluids refer to fluids composed of saturated carbon dioxide formation water and gaseous carbon dioxide at different flow ratios, and different types of fluids include pure saturated carbon dioxide formation water fluid; during the constant rate injection of different types of fluids, the fluid with a high flow ratio of saturated carbon dioxide formation water and gaseous carbon dioxide is injected first, and then the fluid with a low flow ratio of saturated carbon dioxide formation water and gaseous carbon dioxide is injected, and the injection of the next type of fluid is carried out after the injection of the former type of fluid is stabilized; the saturated water core is saturated with formation water or saturated carbon dioxide formation water; 3) Based on the pressure difference between the two ends of the core, the flow rate of gas phase carbon dioxide and saturated formation water, and the flow rate data of carbon dioxide formation water, the water phase relative permeability and gas phase relative permeability of the core when various types of fluids are injected are determined respectively; based on the dry weight of the core, the mass of the core after saturation with formation water, CO 2 The mass of the dried core and the ratio of the carbon dioxide saturated formation water and gas phase carbon dioxide flow rate of each type of fluid are used to determine the water saturation of each type of fluid when injected; 4) Based on the water phase relative permeability and gas phase relative permeability of the core when various types of fluids are injected, combined with the water saturation when various types of fluids are injected, the carbon dioxide-water two-phase seepage permeability curve of the core is determined.

2. The method according to claim 1, in, During the constant rate injection process of different types of fluids, the sum of the gas phase carbon dioxide flow rate of each type of fluid is equal to the flow rate of saturated carbon dioxide formation water.

3. The method according to claim 1, in, During the constant rate injection of different types of fluids, the sum of the gas phase carbon dioxide flow rate of each type of fluid and the carbon dioxide saturated formation water flow rate is mL·min -1 .

4. The method according to claim 1, in, The different types of fluids include pure gas phase carbon dioxide fluids.

5. The method according to claim 1, in, Based on the pressure difference between the two ends of the core, the flow rate of gas phase carbon dioxide and saturated gas, and the flow rate of carbon dioxide formation water, the water phase relative permeability and gas phase relative permeability of the core when various types of fluids are injected are determined respectively, including: Based on the obtained pressure difference at both ends of the core, gas phase carbon dioxide flow rate and carbon dioxide saturated formation water flow rate data, the water phase effective permeability and gas phase effective permeability of the core when various types of fluids are injected are determined respectively; Based on the effective water permeability and gas permeability of the core when various types of fluids are injected, the water relative permeability and gas relative permeability of the core when various types of fluids are injected are determined respectively, taking the effective water permeability of the core when pure saturated carbon dioxide formation water fluid is injected as the absolute permeability.

6. The method according to claim 5, in, The effective permeability of water phase and gas phase of the core is determined by the following formula: In the formula, K gi is the gas phase effective permeability of the core when the i-th type of fluid is injected, μm 2 ;Q gi is the flow rate of gaseous carbon dioxide when the i-th type of fluid is injected, cm 3 ·s -1 ;μ g is the viscosity of gaseous carbon dioxide, mPa·s; L is the core length, cm; A is the cross-sectional area of ​​the core perpendicular to the fluid flow direction, cm 2 ; ΔP is the pressure difference between the two ends of the core, 10 -1 MPa; K wi is the liquid phase effective permeability of the core when the i-th type of fluid is injected, μm 2 ;Q wi is the flow rate of carbon dioxide saturated formation water when the i-th type of fluid is injected, cm 3 ·s -1 ;μ w is the viscosity of carbon dioxide saturated formation water, mPa·s.

7. The method according to claim 5, in, The water phase absolute permeability and gas phase absolute permeability of the core are determined by the following formula: In the formula, K rgi K is the gas phase relative permeability of the core when the i-th type of fluid is injected, dimensionless; gi is the gas phase effective permeability of the core when the i-th type of fluid is injected, μm 2 ; K rwi is the liquid phase relative permeability of the core when the i-th type of fluid is injected, dimensionless; K wi is the liquid phase effective permeability of the core when the i-th type of fluid is injected, μm 2 ; K w1 is the effective permeability of the water phase in the core when pure carbon dioxide saturated formation water fluid is injected, μm 2 .

8. The method according to claim 1, in, Based on the dry weight of the core, the mass of the core after saturation with formation water, CO 2 The mass of the dried core and the ratio of the saturated carbon dioxide formation water and gas phase carbon dioxide flow rate of various types of fluids are used to determine the water saturation of various types of fluids when injected, including: Based on the dry weight of the core, the mass of the core saturated with formation water, and the CO 2 The mass of the core after drying is used to determine the bound water saturation: Based on the irreducible water saturation and the flow rate ratio of saturated carbon dioxide formation water and gas phase carbon dioxide of various types of fluids, the water saturation of various types of fluids when injected is determined respectively; among which, the water saturation of pure saturated carbon dioxide formation water fluid when injected is 1.

9. The method according to claim 8, in, The irreducible water saturation is determined by the following formula: In the formula, S wf7 is the bound water saturation, dimensionless; m 1 is the core dry weight, g; m 2 is the mass of the core after CO2 drying, g; m 3 is the mass of the core after saturation with formation water, g.

10. The method according to claim 8, in, The water saturation of various types of fluids when injected is determined by the following formula: In the formula, S wi is the water saturation of the i-th type of fluid when injected, dimensionless; S wf7 is bound water saturation, dimensionless; Q i is the flow rate ratio of carbon dioxide saturated formation water to gas phase carbon dioxide of the ith type of fluid, dimensionless.

11. A method for determining the porosity and permeability evolution of a reservoir under the action of carbon dioxide, the method include: Determine the carbon dioxide-water two-phase seepage phase permeability curve of the reservoir core before and after aging with saturated carbon dioxide formation water using the method for determining the carbon dioxide-water two-phase seepage phase permeability curve according to any one of claims 1 to 10; Determine the mineralogical composition of reservoir cores before and after aging with CO2-saturated formation water; Determine the porosity of reservoir cores before and after aging with CO2-saturated formation water; Determine the pore size distribution of reservoir cores before and after aging with CO2-saturated formation water; The porosity and permeability evolution of the reservoir under the action of carbon dioxide is characterized by changes in the carbon dioxide-water two-phase seepage phase permeability curve of the reservoir core before and after aging with saturated carbon dioxide formation water, changes in the mineral composition of the reservoir core before and after aging with saturated carbon dioxide formation water, changes in the porosity of the reservoir core before and after aging with saturated carbon dioxide formation water, and changes in the pore size distribution of the reservoir core before and after aging with saturated carbon dioxide formation water.

12. The method according to claim 11, in, The method further includes: Determine gas-tested permeability of reservoir cores before and after aging with CO2-saturated formation water; The changes in gas permeability of reservoir cores before and after aging with saturated carbon dioxide formation water are used to characterize the porosity and permeability evolution of the reservoir under the action of carbon dioxide.

13. The method according to claim 11, in, When the method for determining the carbon dioxide-water two-phase seepage phase permeability curve according to any one of claims 1 to 10 is used to determine the carbon dioxide-water two-phase seepage phase permeability curve of the reservoir core before aging with saturated carbon dioxide formation water, the saturated water core is saturated with formation water; When the method for determining the carbon dioxide-water two-phase seepage phase permeability curve described in any one of claims 1 to 10 is used to determine the carbon dioxide-water two-phase seepage phase permeability curve after the reservoir core is aged with saturated carbon dioxide formation water, the saturated water core is saturated with saturated carbon dioxide formation water.

14. The method according to claim 11, in, A method for determining reservoir porosity and permeability evolution under carbon dioxide using an integrated multifunctional CO 2 Dynamic dissolution test device is used; the integrated multifunctional CO 2 The dynamic corrosion test device includes: Core sample device, confining pressure system, back pressure system, fluid supply system, fluid control system, sensor system, experimental control and safety system, data recording and analysis system; The core sample device includes a core holder and a bracket for fixing the core holder, thereby ensuring that the core sample remains in a fixed position; The fluid supply system includes a first ISCO pump, a second ISCO pump, a first ultrapure water storage tank, a second ultrapure water storage tank, a CO 2 Intermediate container, booster pump, formation water intermediate container, CO 2 gas cylinder, helium cylinder; the outlet of the first ultrapure water storage tank is connected to the inlet of the first ISCO pump, and the outlet of the first ISCO pump is connected to the CO 2 The bottom of the intermediate container is connected, the outlet of the second ultrapure water storage tank is connected to the inlet of the second ISCO pump, and the outlet of the second ISCO pump is connected to the bottom of the formation water intermediate container, CO 2 The outlet of the gas cylinder is connected to the inlet of the booster pump, and the outlet of the booster pump is connected to the CO 2 Intermediate container, top connection of formation water intermediate container, helium cylinder, CO 2 The top of the intermediate container and the top of the formation water intermediate container are respectively connected to the fluid inlet of the core holder; The confining pressure system includes a confining pressure pump, which is connected to the core holder; The back pressure system includes a back pressure pump and a back pressure valve connected in sequence, and the outlet of the back pressure valve is connected to the core holder; The sensor system includes a pressure sensor and a temperature sensor, wherein the pressure sensor is used to obtain pressure and temperature data; The fluid control system includes a control valve disposed on each connecting pipeline to control fluid transmission; The data recording and analysis system is used to transmit the data acquired by the sensor to a computer for recording and analysis; The experimental control and safety system includes control software, power adapter and safety valve to ensure safe operation and control of experimental parameters.

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