Numerical simulation method for migration of CO2 in stratum

Abstract

The invention belongs to the technical field of carbon dioxide capture and utilization and geological sequestration, and discloses a numerical simulation method for migration of CO2 in stratum.The method comprises the steps that an actual stratum complex geological model is constructed, and then a numerical simulation model is obtained; finely adjusting the numerical simulation model to limit fluid channeling and external substance and energy exchange, and ensuring rapid convergence of operation; the injection of CO2 in different layers is simulated, and the influence of the injection layers on the migration law is analyzed; cO2 injection at different injection speeds and temperatures is simulated to analyze the influence of the injection speeds and temperatures on the migration law; cO2 is simulated to be injected at different injection temperatures under the condition of consistent initial salt concentration, and the influence of dissolved salt on migration and dissolution rules is analyzed; the injection of CO2 at different positions of the reservoir is simulated, and the influence of the injection well position on CO2 storage is analyzed; and optimizing well position arrangement to obtain an optimal well pattern scheme. According to the method, the results of various influence factors are comprehensively analyzed, and then the migration rule of CO2 in the stratum is accurately obtained.

Description

Technical Field

[0001] The present invention belongs to the technical field of carbon dioxide capture, utilization and geological storage (CCUS), and in particular relates to a numerical simulation method for CO2 migration in a formation. Background Art

[0002] CCUS technology is a key technology for energy conservation and emission reduction in the fossil energy sector. Among them, geological CO2 storage is the most widely used CCUS technology due to its maturity and low risk. Understanding the migration patterns of CO2 in strata can further improve storage effectiveness. Due to the long storage timescale, experimental methods cannot accurately evaluate CO2 migration patterns over such long timescales. Numerical simulation technology, enabling large-scale simulations at the mine site level, provides a foundation for clarifying these migration patterns.

[0003] Research on the migration laws of CO2 during geological storage is still in its infancy, and the migration and dissolution laws of CO2 are difficult to accurately describe and are not clearly understood. Summary of the Invention

[0004] To address the challenges of existing technologies, the present invention provides a method that fully considers various influencing factors, accurately simulates the migration of CO2 in formations, and thus derives its migration patterns. This method proposes a numerical simulation method for CO2 migration in formations, fully accounting for the effects of different injection rates, injection temperatures, and injection well locations on CO2 migration in formations. The method also derives the distribution of CO2 concentration and formation pressure under different conditions, thereby optimizing the well pattern.

[0005] The basic solution provided by the present invention is a method for numerically simulating CO2 migration in a formation, comprising the following steps:

[0006] S1. Construct a complex geological model of the actual stratum, and then obtain a numerical simulation model of the actual stratum;

[0007] S2. Fine-tune the numerical simulation model to limit fluid cross-layering, prevent the exchange of matter and energy with the outside world, and ensure rapid convergence of the calculation;

[0008] S3. Simulate CO2 injection at different layers and analyze the impact of injection layer on migration patterns;

[0009] S4. Simulate CO2 injection at different injection rates and temperatures to analyze the effects of injection rate and temperature on migration patterns;

[0010] S5. Simulate CO2 injection at different reservoir temperatures under the condition of consistent initial salt concentration and analyze the effect of dissolved salt on migration and dissolution patterns;

[0011] S6. Simulate CO2 injection at different locations in the reservoir and analyze the impact of injection well location on CO2 storage;

[0012] S7. Optimize the well layout to obtain a well pattern plan that matches the best CO2 migration.

[0013] Furthermore, the actual formation numerical simulation model in S1 specifically includes:

[0014] A grid model with hundreds of thousands of levels of grids is constructed, and all grids are discretized using integrated finite differences to obtain discrete elements. The Jacobian matrix is ​​constructed for each discrete element and solved using Newton iteration.

[0015] Furthermore, the S5 simulates CO2 injection at different reservoir temperatures under the condition of consistent initial salt concentration, and analyzes the influence of dissolved salt on migration and dissolution patterns, specifically including:

[0016] In each simulation, the initial salt concentration was kept constant, different reservoir temperatures were set, and the changes in injection pressure, CO2 mass fraction, and CO2 mass fraction in the solution were observed.

[0017] Furthermore, the above-mentioned S6 simulates CO2 injection at different locations in the reservoir and analyzes the impact of injection well location on CO2 storage, specifically including:

[0018] The different positions of the reservoir include dividing the reservoir into three areas: high, medium and low according to the top depth, arranging injection wells in the three areas respectively, keeping other injection conditions consistent, and analyzing the impact of injection well locations on CO2 storage.

[0019] Furthermore, the well layout is optimized in S7 to obtain a well pattern solution that matches the best CO2 migration, specifically including:

[0020] The goal of the well pattern optimization is to achieve a higher CO2 injection volume while meeting safety conditions, that is, to inject at a higher injection rate, with a 10-year evaluation period; the constraint condition of the optimization process is that the maximum pressure in the formation is less than or equal to the threshold of 27.8 MPa; the well pattern scheme that matches the best CO2 migration is the scheme with the most uniform pressure step between different injection wells.

[0021] The principles and advantages of the present invention are as follows: the present invention discloses a method for numerically simulating the migration of CO2 in a formation, comprising: constructing a complex geological model of an actual formation, thereby obtaining a numerical simulation model; fine-tuning the numerical simulation model to limit fluid cross-layering, material and energy exchange with the outside world, and ensuring rapid convergence of the calculation; simulating the injection of CO2 at different strata, and analyzing the influence of the injection strata on the migration law; simulating the injection of CO2 at different injection rates and temperatures, and analyzing the influence of the injection rate and temperature on the migration law; simulating the injection of CO2 at different injection temperatures under the condition of consistent initial salt concentration, and analyzing the influence of dissolved salts on the migration and dissolution laws; simulating the injection of CO2 at different positions in the reservoir, and analyzing the influence of the injection well location on CO2 storage; optimizing the well location layout, and obtaining the optimal well network solution. The present invention comprehensively analyzes the results of various influencing factors, thereby accurately obtaining the migration law of CO2 in the formation.

[0022] The problem to be solved by the present invention is to provide a numerical simulation method for CO2 migration in formations, which fully considers various types of influencing factors, thereby accurately simulating the migration process of CO2 in formations and obtaining the migration law of CO2 in formations. BRIEF DESCRIPTION OF THE DRAWINGS

[0023] Figure 1 Schematic diagram of an actual formation numerical simulation model according to an embodiment of the present invention;

[0024] Figure 2 Schematic diagram of vertical permeability and porosity of a numerical simulation model according to an embodiment of the present invention;

[0025] Figure 3 This is a pressure distribution diagram of CO2 injected into different layers at different time points according to an embodiment of the present invention;

[0026] Figure 4 The concentration of gaseous CO2 at different time points when CO2 is injected into different layers according to the embodiment of the present invention;

[0027] Figure 5 The concentration of liquid CO2 at different injection times at different layers according to the embodiment of the present invention;

[0028] Figure 6 This is the pressure distribution of CO2 at different injection rates after 20 years according to the embodiment of the present invention;

[0029] Figure 7 The CO2 distribution after 20 years at different injection rates of CO2 according to the embodiment of the present invention;

[0030] Figure 8 The distribution of liquid CO2 after 20 years at different injection rates of CO2 according to the embodiment of the present invention;

[0031] Figure 9The temperature distribution of CO2 at different injection temperatures over 10 years according to the embodiment of the present invention;

[0032] Figure 10 The distribution of gaseous CO2 for 10 years at different injection temperatures for CO2 according to the embodiment of the present invention;

[0033] Figure 11 The CO2 of the embodiment of the present invention is injected at different temperatures for 10 years in liquid CO2 distribution;

[0034] Figure 12 The dissolved salt analysis of CO2 in the embodiment of the present invention is carried out at different injection temperatures for 10 years;

[0035] Figure 13 For the example of the present invention, the dissolved salt analysis of CO2 was conducted to analyze the distribution of gaseous CO2 at different injection temperatures for 10 years;

[0036] Figure 14 For the example of the present invention, the dissolved salt analysis of CO2 was conducted at different injection temperatures for 10 years of liquid CO2 distribution;

[0037] Figure 15 The salt concentration distribution of CO2 at different injection temperatures over 10 years according to the embodiment of the present invention;

[0038] Figure 16 This is the pressure distribution of CO2 after 20 years of injection at different locations according to the embodiment of the present invention;

[0039] Figure 17 The distribution of gaseous CO2 after 20 years of CO2 injection at different locations according to the embodiment of the present invention;

[0040] Figure 18 The distribution of liquid CO2 after 20 years of CO2 injection at different locations according to the embodiment of the present invention;

[0041] Figure 19 The single-well injection rate after different multi-well injection optimizations in the embodiments of the present invention;

[0042] Figure 20 The total injection rate and the number of wells after different multi-well injection optimizations in the embodiments of the present invention. DETAILED DESCRIPTION

[0043] To make the technical solutions and technical advantages of the present invention more clear, the following will provide a clear and complete description of the technical solutions during the implementation of the present invention, combined with the actual application process of the present invention in the geological sealing process of a deep saline water layer in Jilin and the accompanying drawings.

[0044] Example 1

[0045] The present invention provides a numerical simulation method for CO2 migration in a formation, comprising the following steps:

[0046] Construct a complex geological model of the actual stratum, and then obtain a numerical simulation model of the actual stratum. The established numerical simulation model is as follows Figure 1 shown.

[0047] Fine-tune the numerical simulation model to limit fluid channeling, prevent the exchange of matter and energy with the outside world, and ensure rapid convergence of the calculation; the limiting fluid channeling includes reducing the permeability and porosity by 1000 times in the vertical direction. The vertical initial permeability and porosity in the model are as follows: Figure 2 As shown; the restriction that there is no exchange of matter and energy with the outside world includes setting the boundary to a closed boundary; the ensuring of rapid convergence of the operation includes the initial conditions of setting the water saturation to 0.99999 and the initial CO2 concentration to 1.e -5 .

[0048] Simulate the injection of CO2 into different layers; pressure distribution at different time points, distribution of gaseous CO2 and liquid CO2 as follows Figure 3-5 As shown in the figure, the pressure is significantly higher at the injection well and increases rapidly throughout the model with continued injection. After 20 years, the pressure throughout the model exceeds 26 MPa. As the pressure changes, CO2 gradually diffuses from the injection well to the surrounding area, eventually forming a quasi-circular region. The CO2 concentration within this region is around 0.5, with even higher concentrations at the injection well, reaching CO2 saturation. After 20 years of continuous injection, the CO2 diffusion radius reaches approximately 476 meters. The diffusion radius of dissolved CO2 is consistent with that of CO2 gas. The maximum liquid CO2 concentration is approximately 0.055.

[0049] Under the same initial conditions, injection rates of 0.22kg / s, 0.33kg / s, and 0.44kg / s were used. The corresponding annual injection volumes were 6937t / a, 10406t / a, and 13875t / a. The pressure distribution and CO2 diffusion range under different injection rates are shown in Figure 2. Figure 6-8 As shown. First, the pressure value will increase with the injection rate, but the distribution range is similar. At a rate of 0.44 kg / s, the pressure will reach about 36 MPa after 20 years of continuous injection. The pressure gradient is the main driving force for the diffusion of gaseous and liquid CO2. Obviously, high injection rates will drive CO2 to diffuse farther, but the distribution range of gaseous and dissolved CO2 is not much different. Since CO2 reaches an equilibrium between gaseous and liquid states, this equilibrium depends only on temperature and pressure, so the diffusion range of gaseous and liquid CO2 is always the same. Over 20 years, the maximum diffusion distance at a rate of 0.22 kg / s is 479.2 meters, the maximum diffusion distance at a rate of 0.33 kg / s is 562.5 meters, and the maximum diffusion distance at a rate of 0.44 kg / s is 645.8 meters. Due to the accumulation of CO2 around the injection well, the diffusion distance does not increase in proportion to the injection rate.

[0050] The injection rate is set to 0.345 kg / s. CO2 is injected continuously for 10 years at 20℃, 25℃, 30℃, 35℃, and 40℃. The temperature, gaseous and liquid CO2 concentration distribution after 10 years under different injection temperature conditions are as follows: Figure 9-11 As shown in Figure 2, the temperature drop is significantly smaller than the CO2 diffusion region because CO2 is heated by the high-temperature rock during diffusion. The CO2 concentration peaks at the injection well and increases slightly with increasing temperature. Temperature affects the amount of CO2 that can be dissolved, with lower temperatures increasing the amount. Therefore, the peak CO2 concentration occurs around the injection well. However, the diffusion regions for both gaseous and liquid CO2 are nearly identical.

[0051] The model was injected at an initial salt concentration of 2.4% at a rate of 0.345 kg / s. CO2 was injected continuously for 10 years at 20°C, 25°C, 30°C, 35°C, and 40°C. The distribution of temperature, gaseous and liquid CO2 concentrations, and dissolved salt concentration after 10 years is shown in Figure 2. Figure 12-14 As shown in Figure 2, due to low temperatures, the liquid CO2 concentration around the injection well increases. Under the influence of CO2-displacing water, the salt concentration around the injection well increases. However, when gas saturation is reached, the salt concentration decreases. Analysis of the above curves reveals that dissolved salts reduce CO2 dissolution, while low temperatures promote it. The significant increase in liquid CO2 concentration around the injection well indicates that temperature has a greater impact on CO2 dissolution than salt.

[0052] Three wells located at the top, middle and bottom of the model were selected as injection wells. After 20 years of continuous injection at a constant rate of 0.22 kg / s, the pressure distribution is as follows: Figure 16 As shown. At the same injection rate, the position of the injection well has a more obvious effect on the pressure. In the case of the upper and lower injection wells, the pressure value distribution is concentrated and high. This is because the closed boundary conditions limit the diffusion of CO2 and water. The maximum pressure during the middle injection is only 28.2MPa. During the injection process, the pressure response is faster and the corresponding range is wider. However, when injecting at the upper and lower positions, the model boundary limits the outward diffusion of pressure, resulting in a higher pressure than the injection at the middle position. The concentration distribution of gaseous and liquid CO2 is shown in Figure 17-18 As shown, when the injection well is located at the bottom, the CO2 diffusion range is even smaller. Because the injection well is close to the model boundary, the CO2 diffusion range already reaches the right edge of the model. Given the closed boundary, the model boundary will affect CO2 diffusion. The maximum diffusion distance for injection at the three locations is approximately 479 meters, significantly smaller than the pressure influence range.

[0053] For different injection well number schemes, the final optimized injection rate is as follows: Figure 19As shown in Figure 2. Since the pressure increase in different injection wells will affect the diffusion of CO2 in adjacent injection wells, the injection rate of a single well decreases significantly as the number of injection wells increases, reducing the injection efficiency of a single well. In addition, the injection rate of different injection wells in the same model is unevenly distributed, which is related to the selected injection well location. The relationship between the optimized total injection rate and the number of injection wells is shown in Figure 2. Figure 20 As shown in the figure, the total injection rate generally increases with the number of access wells, reaching its peak in the four-well model. This is because multiple injection wells can more evenly distribute the CO2. Adding one more well does not double the total CO2 injection volume. Given this, the single-well model is recommended for CO2 injection. The total injection rate for a single well is 0.345 kg / s.

[0054] The above description is merely a preferred embodiment of the present invention and does not constitute any form of limitation to the present invention. Although the present invention has been disclosed as a preferred embodiment as above, it is not intended to limit the present invention. Any technician familiar with this profession can make some changes or modifications to equivalent embodiments of the technical contents disclosed above without departing from the scope of the technical solution of the present invention. However, any simple modifications, equivalent changes and modifications made to the above embodiments based on the technical essence of the present invention without departing from the content of the technical solution of the present invention are still within the scope of the technical solution of the present invention.

Claims

1. A numerical simulation method for CO2 migration in a formation, characterized in that: The following steps are involved: S1. Construct a complex geological model of the actual stratum, and then obtain a numerical simulation model of the actual stratum; S2. Fine-tune the numerical simulation model to limit fluid cross-layering, prevent the exchange of matter and energy with the outside world, and ensure rapid convergence of the calculation; S3. Simulate CO2 injection at different layers and analyze the impact of injection layer on migration patterns; S4. Simulate CO2 injection at different injection rates and temperatures to analyze the effects of injection rate and temperature on migration patterns; S5. Simulate CO2 injection at different reservoir temperatures under the condition of consistent initial salt concentration and analyze the effect of dissolved salt on migration and dissolution patterns; S6. Simulate CO2 injection at different locations in the reservoir and analyze the impact of injection well location on CO2 storage; S7. Optimize the well layout to obtain a well pattern plan that matches the best CO2 migration.

2. The numerical simulation method for CO2 migration in a formation according to claim 1, characterized in that: The actual formation numerical simulation model in S1 specifically includes: A grid model of hundreds of thousands levels is constructed, and all grids are discretized based on integral finite differences to obtain discrete units. The Jacobian matrix of each discrete unit is constructed and solved using Newton iteration.

3. The numerical simulation method for CO2 migration in a formation according to claim 1, characterized in that: The S5 simulates CO2 injection at different reservoir temperatures under the condition of consistent initial salt concentration, and analyzes the influence of dissolved salt on migration and dissolution patterns, specifically including: In each simulation, the initial salt concentration was kept constant, different reservoir temperatures were set, and the changes in injection pressure, CO2 mass fraction, and CO2 mass fraction in the solution were observed.

4. The method for numerical simulation of CO2 migration in a formation according to claim 1, characterized in that: The S6 simulates CO2 injection at different locations in the reservoir and analyzes the impact of injection well location on CO2 storage, specifically including: The different positions of the reservoir include dividing the reservoir into three areas: high, medium and low according to the top depth, arranging injection wells in the three areas respectively, keeping other injection conditions consistent, and analyzing the impact of injection well locations on CO2 storage.

5. The method for numerical simulation of CO2 migration in a formation according to claim 1, characterized in that: The optimization of the well layout in S7 to obtain a well pattern solution that matches the best CO2 migration specifically includes: The goal of the well pattern optimization is to achieve a greater CO2 injection volume while meeting safety conditions, that is, to inject at a higher injection rate, with a 10-year evaluation period.

6. The method for numerical simulation of CO2 migration in a formation according to claim 1, characterized in that: The optimization of the well layout in S7 to obtain a well pattern solution that matches the best CO2 migration specifically includes: The limiting condition of the optimization process is that the maximum pressure in the formation is less than or equal to a threshold value of 27.8 MPa.

7. The method for numerical simulation of CO2 migration in a formation according to claim 1, characterized in that: The optimization of the well layout in S7 to obtain a well pattern solution that matches the best CO2 migration specifically includes: The well pattern scheme that matches the best CO2 migration is a scheme that achieves the most uniform pressure distribution among different injection wells.

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