Method for increasing carbon dioxide storage capacity by high multiple carbon injection

Abstract

The present application relates to a kind of high multiple carbon injection method for improving carbon dioxide storage capacity.The present application simulates high multiple carbon dioxide displacement process, and the micro-distribution state of pore volume, porosity, pore structure and fracture of core before and after displacement is obtained by core permeameter test experiment and cold field emission SEM technology, and then the change of core reservoir pore before and after high multiple carbon injection is quantitatively characterized, and the influence of high multiple carbon injection on carbon dioxide storage capacity is quantified by high multiple carbon injection displacement experiment.The method provided by the present application clearly shows the influence mechanism of high multiple carbon injection on reservoir carbon storage capacity, improves the accuracy of experimental results, and also provides strong data support for subsequent theoretical analysis and practical application.This innovative experimental method not only provides a new idea for the research of carbon dioxide geological storage technology, but also lays a solid foundation for future practical application.

Description

Technical Field

[0001] This invention relates to the field of green and low-carbon development of carbon dioxide sequestration, specifically to a method for increasing the amount of carbon dioxide stored by high-multiplication carbon injection. Background Technology

[0002] Human activities have disrupted the dynamic balance of the natural carbon cycle. This disruption has triggered the greenhouse effect, leading to global warming, a critical environmental issue globally. Reducing carbon dioxide emissions has become a shared responsibility for humanity. Developing CCUS (Carbon Capture, Utilization and Storage) or CCS (Carbon Capture and Storage) technologies is a top priority for carbon emission reduction in the near future. In the oil and gas industry, oilfields can purify carbon dioxide emitted by refining plants and inject it into oil and gas reservoirs. This improves oil recovery while simultaneously achieving carbon sequestration, enabling oil displacement and recycling. This approach can turn carbon dioxide into a resource, generating economic benefits and demonstrating practical operability. According to the analysis of the "Resource Utilization and Underground Storage of Greenhouse Gases for Enhanced Oil Recovery" project, China has approximately 13 billion tons of suitable geological reserves for carbon-assisted oil recovery and carbon storage. This could increase recovery by 15%, equivalent to adding 1.95 billion tons of recoverable oil reserves, while simultaneously storing 4.7 to 5.5 billion tons of CO2. However, during carbon flooding and carbon burial, CO2 can form a weak acid with formation water under formation conditions, and react chemically with calcite, dolomite, feldspar, and other minerals in the formation rocks. The secondary minerals produced by the reaction migrate, all of which will change the reservoir properties. At the same time, long-term scouring also changes the reservoir properties. The changes in reservoir properties will affect the reservoir's carbon burial capacity. Therefore, it is of great significance to clarify the degree of influence of high-multiplier carbon dioxide injection on the reservoir's carbon burial capacity.

[0003] Currently, the changes in reservoir properties following high-multiplier carbon injection during carbon flooding and storage processes are not well understood both domestically and internationally. There is a lack of experimental methods for quantitative characterization, particularly in quantitative and visual characterization, where systematic processes and devices have not yet been established. Furthermore, the impact on carbon dioxide storage is completely unexplored. Patent CN202410071580 discloses a comprehensive testing method and system for reservoir properties under dissolution during carbon dioxide flooding in tight oil reservoirs. It focuses on testing and comparing the dry weight, pore throat structure, pore size distribution, and permeability of cores before and after carbon dioxide flooding to comprehensively characterize the degree of influence of dissolution on reservoir properties. It establishes the correlation between dissolution reaction intensity and mineral composition, pressure changes, the degree of property improvement, and pore throat distribution. However, this patent does not consider the long-term scouring effect of high-multiplier carbon injection on rock, which alters reservoir properties.

[0004] Based on the above, a method for increasing carbon dioxide storage by high-multiplier carbon injection is invented. This method quantifies the degree of change in reservoir properties after high-multiplier carbon injection, and further quantifies the impact on the reservoir's carbon storage capacity. This is of great significance for guiding carbon storage in carbon flooding. Summary of the Invention

[0005] To achieve the above objectives, this invention proposes a method for increasing carbon dioxide storage capacity through high-expansion carbon injection. It simulates a high-expansion carbon dioxide flooding process and uses core porosity and permeability measurement experiments and cold field emission scanning electron microscopy (SEM) to obtain the core pore volume, porosity, pore structure, and fracture microstructure distribution before and after displacement. This allows for the quantitative characterization of changes in core reservoir porosity before and after high-expansion carbon injection, and the quantification of the impact of high-expansion carbon injection on carbon dioxide storage capacity through displacement experiments.

[0006] This invention provides a method for increasing carbon dioxide storage capacity through high-multiplication carbon injection, the specific technical solution of which includes the following steps:

[0007] S10: Obtain natural core samples of the target reservoir, ensuring that the core lithology and mineral composition are similar;

[0008] S20: Determine the pore volume, porosity, and microscopic SEM images of the core before displacement;

[0009] S30: Simulates the process of bound water formation in the reservoir and the process of oil formation in the reservoir;

[0010] S40: Perform high-expansion CO2 displacement, record pressure, flow rate, injected PV number, produced oil, gas and water volume, and determine core SEM images and core physical properties under different set PV numbers;

[0011] S50: Based on the rate of change of pore volume, porosity, and porosity of cores injected with different PV numbers, the degree of change in reservoir porosity after high-multiple CO2 injection is quantitatively assessed and visualized.

[0012] S60: Calculate the theoretical and actual carbon dioxide storage capacity of cores after injection of different PV numbers, and clarify the relationship between high-multiplier carbon injection and reservoir carbon burial capacity.

[0013] As a preferred embodiment of the present invention, the above method specifically includes the following steps:

[0014] S10: Obtain natural cores of the target reservoir, ensure that the core lithology and mineral composition are similar, pre-treat the cores, or use artificial three-layer / multi-layer heterogeneous artificial cores to simulate actual heterogeneous strata;

[0015] S20: Determine the pore volume, porosity, and microscopic SEM images of the core before displacement;

[0016] S201: Cut the rock core into several parts and measure the pore volume and porosity of each core section.

[0017] S202: Microscopic SEM images of the pre-displacement core segment obtained by cold field emission SEM;

[0018] S30: Simulates the process of bound water formation in the reservoir and the process of oil formation in the reservoir;

[0019] S301: Mixed formation water, the spliced ​​core is placed in the core holder, the core is vacuumed and saturated with formation water to simulate the process of establishing bound water in the reservoir.

[0020] S302: Compound formation oil, core injection saturated with oil until no more water comes out of the outlet, simulates the formation of reservoir oil, determines the original oil saturation, and is placed in a holder for aging for more than 36 hours;

[0021] S40: Perform high-expansion CO2 displacement under specified experimental conditions, record the pressure, flow rate, injected PV number, and produced oil, gas and water at both ends, and when the injected volume reaches the specified PV number, take out a section of core for cold field emission SEM scanning and measure the pore volume and porosity. Continue to inject CO2 into the remaining core until the next specified PV number, take out another section of core for SEM scanning and measure the pore volume and porosity, and continue this step until the specified PV number is reached.

[0022] S50: Observe and compare the changes in pore volume, porosity, and pore structure of cores injected with different PV numbers, and calculate the rate of change of core pore volume, porosity, and porosity to achieve a quantitative and visual characterization of the degree of reservoir property changes after high-PV injection.

[0023] S60: Calculate the theoretical and actual carbon dioxide burial volume of cores after different PV numbers are injected, and clarify the impact of high-multiplier carbon injection on the reservoir's carbon burial capacity.

[0024] Furthermore, the calculation methods for the theoretical and actual buried reserves are as follows:

[0025] The theoretical CO2 reserves were calculated using a two-stage method, calculating the theoretical CO2 reserves before and after the gas breakthrough, resulting in higher accuracy.

[0026] Methods for calculating theoretical carbon dioxide reserves:

[0027]

[0028] Among them, the maximum theoretical carbon dioxide storage capacity is the theoretical carbon dioxide storage capacity calculated under the conditions of bound water saturation and residual oil saturation in this study.

[0029] Method for calculating the actual amount of carbon dioxide buried:

[0030] M CO2 =ρ CO2 ·(V 注入 -V 采出 ) (Formula 2)

[0031] Among them, M CO2 —The actual amount of carbon dioxide buried;

[0032] ρ CO2 —The density of carbon dioxide;

[0033] RF – Recovery rate of carbon dioxide flooding;

[0034] OOIP – Original crude oil reserves;

[0035] Cog – the solubility of carbon dioxide in crude oil;

[0036] Cwg—Solubility of carbon dioxide in formation water;

[0037] So—oil saturation;

[0038] Sw – Water saturation;

[0039] Vφ — pore volume;

[0040] Bo—Crude oil volume coefficient;

[0041] Before BT – before the CO2 breakthrough;

[0042] afterBT—after CO2 breakthrough;

[0043] V 注入 —Record the amount of carbon dioxide injected;

[0044] V 采出 —Record the amount of carbon dioxide extracted.

[0045] Compared with the prior art, the beneficial effects of the present invention are as follows:

[0046] 1. To more accurately simulate actual field conditions and precisely characterize the increasing significance of carbon dioxide's impact on reservoir properties as the cumulative injection volume increases, this invention raises the displacement ratio to over 2.0 PV. This improvement not only enhances the scientific rigor of the experimental design but also ensures the rationality and reliability of the experimental results, thereby enabling a deeper understanding of the dynamic changes in reservoir properties during carbon dioxide injection.

[0047] 2. Utilizing advanced cold field emission scanning electron microscopy (SEM), this invention achieves quantitative and visual characterization of the changes in reservoir pore structure after high-magnification carbon injection. Through SEM observation, we can intuitively observe the microscopic changes in reservoir pore structure, thereby clarifying the mechanism by which high-magnification carbon injection affects the reservoir's carbon burial capacity. The application of this technique not only improves the accuracy of experimental results but also provides strong data support for subsequent theoretical analysis and practical applications.

[0048] 3. The method proposed in this invention has the capability to conduct experiments under different pressures, thereby enabling in-depth analysis of the impact of high-expansion carbon flooding on reservoir property changes under varying degrees of carbon miscibility. By comparing experimental results under different pressure conditions, the specific impact of high-expansion carbon injection on reservoir carbon burial capacity is explored, thereby improving the accuracy of carbon dioxide burial quantity evaluation. This innovative experimental method not only provides new insights into carbon dioxide geological storage technology but also lays a solid foundation for future practical applications. Attached Figure Description

[0049] Figure 1 Mineral SEM image of core Y01-01 before displacement;

[0050] Figure 2 Mineral SEM image of core Y01-01 after CO2 injection of 1PV;

[0051] Figure 3 Mineral SEM image of core Y01-02 before displacement;

[0052] Figure 4 SEM images of core Y01-02 after CO2 displacement of 10PV;

[0053] Figure 5 The efficiency curve of CO2 displacement of carbon storage;

[0054] Figure 6 The curve showing the CO2 displacement of buried stock.

[0055] Figure 7 Curves showing the actual burial volume of carbon dioxide under different pressures due to high-expansion carbon injection. Detailed Implementation

[0056] To more clearly illustrate the objectives, technical solutions, and advantages of this invention, the following detailed description of the invention will be provided in conjunction with embodiments. It should be understood that the following description of the embodiments is intended to explain and illustrate the overall concept of the invention and should not be construed as limiting this disclosure.

[0057] In the description of this disclosure, it should be noted that the terms "center," "upper," "lower," "left," "right," "vertical," "horizontal," "inner," and "outer," etc., indicating orientation or positional relationships, are used solely for the convenience and simplicity of describing this disclosure, and do not indicate or imply that the device or element referred to must have a specific orientation, or be constructed and operated in a specific orientation, and therefore should not be construed as a limitation of this disclosure. Furthermore, the terms "first," "second," and "third" are used for descriptive purposes only to distinguish different components and should not be construed as indicating or implying relative importance. The word "a" or "an" does not exclude multiple components. Words such as "including" or "comprising" mean that the element or object preceding the word encompasses the elements or objects listed following the word and their equivalents, without excluding other elements or objects.

[0058] Furthermore, the technical features involved in the different embodiments of this disclosure described below can be combined with each other as long as they do not conflict with each other.

[0059] Unless otherwise defined, the technical or scientific terms used in this disclosure shall have the ordinary meaning as understood by one of ordinary skill in the art to which this disclosure pertains.

[0060] In this invention, PV (Pore Volume) refers to the total volume of pore space in the reservoir that can be used to store fluids (such as carbon dioxide).

[0061] In this invention, a method for increasing carbon dioxide storage capacity through high-expansion carbon injection allows the specified PV number to be determined based on experimental needs. This means the experimenter can flexibly adjust the injection volume according to reservoir characteristics, experimental objectives, and desired storage effect. As an example, the PV number provided by this invention covers an injection volume range from small-scale (e.g., 0.2 PV) to large-scale (e.g., 15.0 PV). The experimenter can select any one or more values ​​as needed, such as 0.2 PV, 0.5 PV, 1.0 PV, 5.0 PV, 10.0 PV, and 20.0 PV. Note that to ensure the high-expansion carbon injection effect, the maximum PV number selected in this invention should be greater than 2.0 PV. If the injection volume is too small (e.g., less than or equal to 2.0 PV), the advantages of high-expansion carbon injection may not be fully realized.

[0062] Furthermore, in the method described above for increasing carbon dioxide storage capacity through high-expansion carbon injection, the experimental pressure can be determined according to experimental requirements. That is, a suitable experimental pressure can be selected based on the reservoir characteristics, experimental objectives, and desired storage effect, such as 10 MPa, 20 MPa, 30 MPa, 40 MPa, or 50 MPa. Note that the carbon dioxide miscibility varies under different pressures, allowing for experiments under miscible, near-miscible, and immiscible conditions. These conditions can simulate the behavior of carbon dioxide in the reservoir under different geological environments, thereby providing a more comprehensive analysis of the impact of high-expansion carbon injection under different miscibility states on the degree of change in reservoir porosity and the reservoir's carbon storage capacity.

[0063] The method described above for increasing carbon dioxide storage capacity through high-multiplication carbon injection can be used to determine the experimental temperature according to experimental requirements, such as 20℃, 30℃, 50℃, 100℃, etc.

[0064] Example 1

[0065] The method for increasing carbon dioxide storage capacity through high-expansion carbon injection in this embodiment includes the following steps:

[0066] S10: Obtain natural cores of the target reservoir, ensuring that the core lithology and mineral composition are similar, pre-treat the cores, or use artificial three-layer / multi-layer heterogeneous artificial cores to simulate actual heterogeneous strata;

[0067] S20: Determine the pore volume, porosity, and microscopic SEM images of the core before displacement;

[0068] S30: Simulates the process of bound water formation in the reservoir and the process of oil formation in the reservoir;

[0069] S40: Perform high-expansion CO2 displacement, record pressure, flow rate, injected PV number, produced oil, gas and water volume, determine core SEM images under different set PV numbers, and determine core pore volume and porosity;

[0070] S50: Based on the rate of change of pore volume, porosity, and porosity of cores injected with different PV numbers, the degree of change in reservoir porosity after high-multiple CO2 injection is quantitatively assessed and visualized.

[0071] S60: Calculate the carbon dioxide burial volume of cores after injection of different PV numbers to clarify the relationship between high-multiplier carbon injection and reservoir carbon burial capacity.

[0072] Example 2

[0073] S10: Obtain natural cores of the target reservoir, ensure that the core lithology and mineral composition are similar, and pre-treat the cores;

[0074] This step is the preparation stage for the experiment, and its goal is to obtain core samples that can represent the characteristics of the target reservoir. Ideally, natural core samples should be obtained directly from the target reservoir, as these core samples accurately reflect the formation characteristics. However, if natural core samples are difficult to obtain or are too expensive, artificial three-layer / multi-layer heterogeneous core samples can be used to simulate actual heterogeneous formations. These artificial core samples are designed to closely resemble natural core samples in terms of material composition and structural properties. Furthermore, regardless of whether natural or artificial core samples are used, certain pretreatment processes are necessary to ensure the accuracy and reliability of the experiment.

[0075] S20: Determine the pore volume, porosity, and microscopic SEM images of the core before displacement;

[0076] S201: Cut the core into several sections and measure the porosity and pore volume of each core section.

[0077] The core was cut into several smaller segments so that each segment could be tested and observed individually. The porosity and pore volume of each core segment were measured.

[0078] S202: Microscopic SEM images of pre-displacement cores obtained by cold field emission SEM;

[0079] Prior to the displacement experiment, the core was microscopically observed using cold field emission scanning electron microscopy (SEM). SEM provides high-resolution images, revealing the core's microstructure and pore distribution. This method is crucial for obtaining the core's microscopic properties and understanding the flow and distribution of carbon dioxide within the core during subsequent displacement.

[0080] S30: Simulates the process of bound water formation in the reservoir and the process of oil formation in the reservoir;

[0081] S301: Simulation of the process of establishing bound water in the reservoir: Formation water is prepared according to the formation water composition of the target reservoir. Then, the assembled core is placed in a core holder and subjected to vacuum treatment to remove gas. Next, saturated formation water is injected into the core to simulate the state of bound water in the reservoir.

[0082] S302: Simulated the oil formation process in the reservoir: Formation oil was compounded according to the formation oil composition of the target reservoir and injected into a core already saturated with formation water until no more water was produced at the outlet. This process simulated the oil formation process in the reservoir. The original oil saturation of the core could be determined by measuring the injected oil volume. Then, the core was placed in a holder and aged for a period of time (e.g., more than 36 hours) to simulate the changes in the reservoir over a long geological process.

[0083] S40: Perform high-expansion CO2 displacement under specified experimental conditions. During the injection process, record the pressure, flow rate, injected PV number, and produced oil, gas, and water volume at both ends. Whenever the injected volume reaches the specified PV number, take out a section of core for cold field emission SEM scanning and measure the core pore volume and porosity. Then, continue injecting CO2 into the remaining core until the next specified PV number, and take out another section of core for SEM scanning and measure the core pore volume and porosity. This step continues until the specified PV number is reached.

[0084] S50: Observe and compare the changes in pore volume, porosity, and pore structure of core samples under different PV numbers. By calculating the rate of change of pore volume, porosity, and pore surface area of ​​the core samples, the degree of change in reservoir porosity after high-PV injection can be quantitatively described. Simultaneously, SEM images are used for visualization, providing a more intuitive display of these changes.

[0085] S60: Calculate the carbon dioxide sequestration in core samples after injection of different PV numbers to clarify the impact of high-multiplier carbon injection on reservoir carbon sequestration capacity. This is crucial for assessing the potential for geological carbon dioxide sequestration and optimizing sequestration strategies.

[0086] Furthermore, the method for calculating the carbon dioxide storage capacity is as follows:

[0087] Methods for calculating theoretical carbon dioxide reserves:

[0088]

[0089] Among them, the maximum theoretical carbon dioxide storage capacity is the theoretical carbon dioxide storage capacity calculated under the conditions of bound water saturation and residual oil saturation in this study.

[0090] Method for calculating the actual amount of carbon dioxide buried:

[0091] M CO2 =ρ CO2 ·(V 注入 -V 采出 (Formula 2) where M CO2 —The actual amount of carbon dioxide buried;

[0092] ρ CO2 —The density of carbon dioxide;

[0093] RF – Recovery rate of carbon dioxide flooding;

[0094] OOIP – Original crude oil reserves;

[0095] Cog – the solubility of carbon dioxide in crude oil;

[0096] Cwg—Solubility of carbon dioxide in formation water;

[0097] So—oil saturation;

[0098] Sw – Water saturation;

[0099] Vφ — pore volume;

[0100] Bo—Crude oil volume coefficient;

[0101] Before BT – before the CO2 breakthrough;

[0102] After BT—CO2 breakthrough;

[0103] V 注入 —Record the amount of carbon dioxide injected;

[0104] V 采出 —Record the amount of carbon dioxide extracted.

[0105] Example 3

[0106] S10: Obtain natural cores from Block A reservoir, ensuring that the core lithology and mineral composition are similar. The main primary minerals include quartz, feldspar (such as potassium feldspar and plagioclase), and chlorite is the most abundant clay mineral.

[0107] S201: Six core samples were cut and the porosity and pore volume of the core samples before displacement were measured. The test results are shown in Table 1.

[0108] S202: Microscopic SEM images of the core before displacement were observed using cold field emission scanning electron microscopy (SEM), and the porosity of the core surface was calculated. The results are shown in Table 1.

[0109] Table 1. Results of determination of physical properties of the core samples before displacement.

[0110] Core No. Pore volume V (cm3 3 )]]> Porosity Φ (%) Face porosity (%) Y01-01 5.61 15.59 8.92 Y01-02 5.79 15.52 8.86 Y01-03 5.56 15.46 8.72 Y01-04 5.68 15.62 8.83 Y01-05 5.92 15.76 8.97 Y01-06 5.70 15.75 9.08 Average value 5.71 15.617 8.897

[0111] S301: A compound formulation simulating formation water, containing Ca in the formation water. 2+ and Mg 2+ Low ion content, HCO3- 3- The formation water has a high ion content; details of the ion concentration are shown in Table 2. The total mineralization is 10185.6 mg / L, classifying it as NaHCO3-type formation water. A spliced ​​natural core was placed in a core holder, saturated with formation water after vacuuming, and the core volume and saturated formation water quantity were measured; details are shown in Table 3.

[0112] Table 2. Ion Concentration of Experimental Water

[0113]

[0114] S302: Saturate the oil at a rate of 0.1 mL / min, and after 12 hours increase the flow rate to 0.5 mL / min for high-speed saturation. When water is first observed at the produced end of the core, increase the flow rate to 1 mL / min again to continue the saturation operation. After the produced end of the core no longer produces water, the core reaches a stable oil saturation state. In this example, the original oil saturation is determined to be 84.01%. The saturated oil core is placed in a holder and aged for more than 36 hours.

[0115] S40: A high-expansion CO2 displacement experiment was conducted at an experimental temperature of 80℃ and an experimental pressure of 35MPa. The pressure, flow rate, injected PV number, and produced oil, gas and water volume at both ends of the core were recorded. Detailed data are shown in Table 4. After the injected PV number reached 1.0PV and 10PV, a section of the core was taken out for cold field emission electron microscopy scanning and core property determination.

[0116] Table 3. Pore variations in CO2-displaced cores

[0117]

[0118] Table 4 Note: CO2 displacement experiment data table

[0119]

[0120]

[0121]

[0122] S50: Observe and compare the changes in core porosity. After CO2 displacement of 1 PV, both the pore volume and porosity of the core decreased, with the core pore volume being 5.02 cm³. 3 The pore volume decreased by 0.59 cm compared to before displacement. 3 The porosity was 14.87%, a decrease of 4.6% compared to before displacement, and the porosity was 6.77%, a decrease of 29.6% compared to before displacement. From Figure 1 and Figure 2 Comparative analysis and microscopic SEM images obtained by cold field emission scanning electron microscopy revealed that the blockage of pores by new minerals and clay particles was the fundamental reason for the decrease in core pore volume and permeability. After displacement of 10 PV, the core pore volume was 6.35 cm³. 3 The pore volume increased by 0.56 cm³ compared to before displacement. 3 The porosity was 15.73%, an increase of 1.4% compared to before displacement; the porosity was 9.16%, an increase of 3.4% compared to before displacement. According to... Figure 3-4It is evident that high-magnification CO2 erosion leads to the expansion of microcracks, dissolution of mineral particle surfaces, and smoothing of particle edges; high-magnification erosion plays a role in unblocking and can restore the physical properties of the core. At the same time, the microcracks formed by mineral dissolution improve the physical properties of the reservoir.

[0123] S60: Analyze the changes in carbon dioxide burial volume during displacement to clarify the impact of high-multiplication carbon injection on reservoir carbon burial capacity. Based on experimental data, calculate the relationship curves between carbon dioxide burial efficiency, carbon dioxide burial volume, and injected PV number.

[0124] The minimum miscibility pressure of carbon dioxide in Block A reservoir is 28.9 MPa. Under the experimental temperature and pressure, carbon dioxide is displaced in a miscible manner. Figure 5-6 Analysis shows that before the gas injection rate of 0.22 PV, it is mainly the gas-free oil recovery stage. The oil is mainly driven out by the elastic energy slug due to the volume expansion of the crude oil after gas dissolution. The recovery rate is slow. Before the CO2 breakthrough, the actual carbon injection amount equals the carbon storage amount, and the actual carbon dioxide storage amount is 6.97 g. When the gas injection rate is 0.22 PV to 0.51 PV, it is the gas production stage, mainly driven by dissolved gas and the displacement of crude oil by gas flow. The crude oil recovery rate increases rapidly. There is still no carbon dioxide production in this stage. When the gas injection rate is 0.51 PV to 1.77 PV, it is the stage where carbon dioxide gas is seen. The dissolved carbon dioxide at the displacement front is displaced. As carbon dioxide is extracted from crude oil, its burial rate decreases. When the injection volume reaches 1.77 PV, gaseous carbon dioxide has formed a continuous channel in the reservoir, which significantly reduces the flowability of crude oil and greatly enhances gas flowability, further increasing the decline in carbon burial rate. In subsequent high-volume carbon injection, the high-volume erosion and flushing of CO2 plays a role in unblocking, and the microfractures formed improve reservoir properties, resulting in a slight increase in carbon dioxide burial efficiency. When the injected CO2 volume reaches 10 PV, the final burial efficiency is 40%, and the actual burial CO2 mass is 42.01 g.

[0125] Example 4

[0126] S10: Obtain natural cores from Block B reservoirs, ensuring that the core lithology and mineral composition are similar. The main primary minerals include quartz, feldspar (such as potassium feldspar and plagioclase), and chlorite is the most abundant clay mineral.

[0127] S201: Eight core samples were cut and the porosity and pore volume of the core samples before displacement were measured. The test results are shown in Table 1.

[0128] S202: Microscopic SEM images of the core before displacement were observed using cold field emission scanning electron microscopy (SEM), and the porosity of the core surface was calculated. The results are shown in Table 1.

[0129] Table 5. Results of determination of physical properties of the experimental core before displacement.

[0130]

[0131]

[0132] S301: A compound simulated formation water is prepared, and a spliced ​​natural rock core is placed in a core holder. After the core is vacuumed, it is saturated with formation water.

[0133] S302: The compound formation oil is injected into the core. After the core no longer produces water at the produced end, the core reaches a stable oil saturation state. In this embodiment, the original oil saturation is determined to be 82.96%. The saturated oil core is placed in a holder and aged for more than 36 hours.

[0134] The minimum miscibility pressure of carbon dioxide in the S40:B block reservoir is 31.8 MPa. High-expansion CO2 displacement experiments were conducted at an experimental temperature of 82℃ and experimental pressures of 35 MPa, 30 MPa, and 25 MPa. The pressure, flow rate, injected PV number, and produced oil, gas and water volume at both ends of the core were recorded. After the injected PV number reached 1.0 PV, 5.0 PV, and 15.0 PV, a section of the core was taken out for cold field emission electron microscopy scanning and core property determination.

[0135] S50: Observe and compare the changes in core physical properties, see Table 6.

[0136] S60: Analyze the changes in carbon dioxide burial volume under different pressures using high-expansion carbon injection. Figure 7 It can be seen that among the three groups of experiments, the carbon dioxide miscible flooding yielded the highest storage capacity, followed by the near-miscible carbon dioxide flooding, while the carbon dioxide immiscible flooding yielded the lowest storage capacity. Comparing the increase in carbon dioxide storage capacity under different pressures using Tables 7 and 8, the theoretical and actual storage capacities of carbon dioxide miscible flooding showed the largest increases, with theoretical storage capacity changes ranging from 16.8% to 38.9% and actual storage capacity changes ranging from 30.5% to 31.2%. This was followed by near-miscible carbon dioxide flooding, while the increase in carbon dioxide immiscible flooding was the smallest, with theoretical storage capacity changes ranging from 10.5% to 26.9% and actual storage capacity changes ranging from 19.8% to 23.5%. Tables 6 and 9 show that the maximum theoretical storage capacity of carbon dioxide decreases as the pore volume decreases and increases as the pore volume increases.

[0137] Table 6 Changes in physical properties of CO2-displaced cores

[0138]

[0139] Table 7 Theoretical Carbon Dioxide Storage Capacity under High-Expansion Carbon Injection under Different Pressures

[0140]

[0141] Table 8 Actual Carbon Dioxide Storage Volume under High-Expansion Carbon Injection under Different Pressures

[0142]

[0143] Table 9. Maximum theoretical carbon dioxide storage capacity under different pressures with high-expansion carbon injection.

[0144]

[0145] In summary, based on the above embodiments and the method of the present invention, the impact of high-intensity carbon injection on the carbon burial capacity of the reservoir can be obtained. Firstly, high-intensity carbon injection affects the carbon dioxide burial rate. In the initial stage, before a "CO2 breakthrough" occurs, the injected carbon dioxide is captured and burial by the reservoir. At this stage, the actual injected carbon amount is equal to the burial amount, resulting in a 100% carbon dioxide burial rate. As carbon dioxide injection continues, when the "carbon dioxide gas exposure stage" begins, some carbon dioxide at the displacement front dissolves in the crude oil and is produced from the reservoir along with the crude oil. Therefore, the amount of carbon dioxide captured and burial by the reservoir decreases relative to the injected amount, leading to a decrease in the carbon dioxide burial rate. As the injection process continues, carbon dioxide gradually diffuses in the reservoir and forms gas-phase continuity channels. These channels may become pathways for carbon dioxide to escape from the reservoir, causing more carbon dioxide to leak out. Therefore, the decrease in the carbon dioxide burial rate will further increase before stabilizing.

[0146] When carbon dioxide is injected at a high rate, it may cause long-term erosion and scouring of the reservoir. This can remove some of the blockages in the reservoir, thereby improving the permeability and connectivity of the reservoir. The effective porosity and pore volume of the reservoir increase. These changes are conducive to the diffusion and burial of carbon dioxide in the reservoir. Therefore, the carbon dioxide burial rate increases slightly, which improves the carbon burial capacity of the reservoir to a certain extent.

[0147] Secondly, there's the impact of high-multiplication carbon injection on the reservoir's carbon dioxide storage capacity. Carbon dioxide reacts with formation water to form a weak acid, which then chemically reacts with the reservoir. The secondary minerals produced by this reaction migrate, leading to a decrease in reservoir pore volume and porosity. This means the reservoir's storage space for carbon dioxide decreases, and the maximum theoretical storage capacity of carbon dioxide decreases. However, continued high-multiplication carbon dioxide injection causes prolonged erosion and flushing of the reservoir. This can remove some of the blockages in the reservoir, thereby improving its permeability and connectivity. The reservoir's pore volume and porosity increase, leading to a larger maximum theoretical carbon dioxide storage capacity and enhancing the reservoir's carbon burial capacity.

[0148] The above description is merely a preferred embodiment of the present invention, but the scope of protection of the present invention is not limited thereto. Any equivalent substitutions or modifications made by those skilled in the art within the scope of the technology disclosed in the present invention, based on the technical solution and inventive concept of the present invention, should be covered within the scope of protection of the present invention.

Claims

1. A method for increasing carbon dioxide storage capacity through high-multiplication carbon injection, characterized in that, Includes the following steps: S10: Obtain natural core samples of the target reservoir, ensuring that the core lithology and mineral composition are similar; S20: Determine the pore volume, porosity, and microscopic SEM images of the core before displacement; S30: Simulates the process of bound water formation in the reservoir and the process of oil formation in the reservoir; S40: Perform high-expansion CO2 displacement, record pressure, flow rate, injected PV number, produced oil, gas and water volume, and determine core SEM images and core physical properties under different set PV numbers; S50: Based on the rate of change of pore volume, porosity, and porosity of cores injected with different PV numbers, the degree of change in reservoir porosity after high-multiple CO2 injection is quantitatively assessed and visualized. S60: Calculate the theoretical and actual carbon dioxide storage capacity of the core after different PV numbers are injected, and clarify the relationship between high carbon injection ratio and reservoir carbon burial capacity.

2. The method according to claim 1, characterized in that, In step S10, artificial three-layer / multi-layer heterogeneous artificial rock cores can be used to simulate actual heterogeneous strata.

3. The method according to claim 1, characterized in that, Step S20 includes step S201: cutting the rock core into several parts and measuring the pore volume and pore volume of each rock core section.

4. The method according to claim 1, characterized in that, Step S20 further includes step S202: using cold field emission SEM to observe the microscopic SEM image of the core segment before displacement.

5. The method according to claim 1, characterized in that, Step S30 includes step S301: compounding formation water, placing the spliced ​​core in a core holder, saturating the core with formation water after vacuuming, and simulating the process of establishing bound water in the reservoir.

6. The method according to claim 1, characterized in that, Step S30 further includes step S302: compounding formation oil, injecting saturated oil into the core until no more water is produced at the outlet, simulating the formation of reservoir oil, determining the original oil saturation of the core, and aging the core in a holder for more than 36 hours.

7. The method according to claim 1, characterized in that, Step S40 specifically involves: performing high-expansion CO2 displacement under specified experimental conditions, recording the pressure, flow rate, injected PV number, and produced oil, gas, and water volume at both ends; whenever the injected volume reaches the specified PV number, taking out a section of core for cold field emission SEM scanning and measuring the pore volume and porosity; then, continuing to inject CO2 into the remaining core to the next specified PV number, and taking out another section of core for SEM scanning and measuring the pore volume and porosity, continuing this step until the specified PV number is reached.

8. The method according to claim 1, characterized in that, Methods for calculating theoretical carbon dioxide reserves: Among them, M CO2 —The actual amount of carbon dioxide buried; ρ CO2 —The density of carbon dioxide; RF – Recovery rate of carbon dioxide flooding; OOIP – Original crude oil reserves; Cog – the solubility of carbon dioxide in crude oil; Cwg—Solubility of carbon dioxide in formation water; So—oil saturation; Sw – Water saturation; Vφ — pore volume; Bo—Crude oil volume coefficient; Before BT – before the CO2 breakthrough; After BT—CO2 breakthrough.

9. The method according to claim 1, characterized in that, Method for calculating the actual amount of carbon dioxide buried: M CO2 =ρ CO2 ·(V 注入 -V 采出 ) (Formula 2) Where M CO2 —The actual amount of carbon dioxide buried; ρ CO2 —The density of carbon dioxide; V 注入 —Record the amount of carbon dioxide injected; V 采出 —Record the amount of carbon dioxide extracted.

10. The method according to claim 7, characterized in that, The maximum number of PVs in the specified PV count is greater than 2.0 PVs.

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