CO2 mineralization sequestration method based on deep co-injection of high salinity mine water

Abstract

This invention relates to the fields of carbon sequestration and environmental protection in mining areas, specifically a CO2 mineralization and sequestration method based on deep co-injection of high-salinity mine water. It includes modules for pre-enrichment and heating, injection fluid preparation, gas-liquid mixing and staged depressurization injection, and produced-out treatment. The system combines impurity-removed and concentrated high-salinity mine water, amino acid catalysts, polycarboxylic acid chelating agents, and inorganic bases. Its core is to ensure catalyst activity under CO2-rich acidic conditions through pH buffering and control technology, accelerate carbon fixation reactions using carbamate intermediate pathways, and improve gas-liquid mixing conditions using staged variable pressure pulse injection technology, achieving controllable nucleation and in-situ precipitation of carbonates in deep formations. This invention rationally selects specific chelating agents, solving the technical problems of slow traditional mineralization kinetics, easy scaling and clogging near the wellbore, and the complete loss of nucleophilic catalytic activity of conventional amine catalysts due to protonation. This improves the in-situ mineralization rate and achieves multi-process synergistic treatment of deep reinjection of high-salinity mine water and CO2 mineralization and sequestration.

Description

Technical Field

[0001] This invention belongs to the field of carbon sequestration and environmental protection technology in mining areas, specifically a CO2 mineralization and sequestration method based on deep co-injection of high-mineralization mine water. Background Technology

[0002] In coal mining bases, coal mining produces highly mineralized mine water rich in divalent metal cations such as calcium, magnesium, strontium, and barium. Simultaneously, surrounding industrial activities emit large amounts of greenhouse gas CO2. Organically combining the treatment of highly mineralized mine water with deep geological CO2 sequestration, achieving multi-process synergistic treatment of deep reinjection of highly mineralized mine water and CO2 mineralization sequestration, is a key technological path for achieving carbon emission reduction and environmental protection. However, traditional CO2 mineralization sequestration technology has the following technical drawbacks: First, the reaction kinetics are slow, with a long cycle for CO2 to react with calcium and magnesium ions in formation water or rock minerals to form carbonate precipitation. Second, direct co-injection into the wellbore or near-wellbore area easily leads to uncontrollable instantaneous scaling, resulting in formation blockage and loss of injection capacity. Third, in deep, high-pressure, CO2-rich environments, the fluid pH often drops to 3-4. Under this acidic environment, not only is the nucleation and precipitation of calcium / magnesium carbonate thermodynamically inhibited, but conventional amine catalysts also completely lose their nucleophilic catalytic activity due to protonation, leading to the stagnation of the mineralization reaction. Summary of the Invention

[0003] The purpose of this invention is to provide a CO2 mineralization and sequestration method based on deep co-injection of high-salinity mine water. Existing traditional CO2 mineralization and sequestration technologies suffer from drawbacks in practical applications, including slow reaction kinetics, uncontrollable instantaneous scaling during direct co-injection into the wellbore or near-wellbore zone leading to formation blockage and loss of injection capacity, and the complete loss of nucleophilic catalytic activity of conventional amine catalysts due to protonation in deep, high-pressure, CO2-rich acidic environments, resulting in stagnation of the mineralization reaction. This invention provides a method that uses pH buffering control technology to ensure catalyst activity in CO2-rich environments, utilizes polycarboxylic acid chelating agents to prevent near-wellbore scaling and controllable nucleation at depth, and combines segmented variable pressure pulse injection technology to improve gas-liquid mixing conditions, thereby increasing the mineralization reaction rate and achieving multi-process synergistic treatment of deep reinjection of high-salinity mine water and CO2 mineralization and sequestration. The specific technical solution is as follows: CO2 mineralization and sequestration methods based on deep co-injection of high-salinity mine water include: Step (1) Pre-enrichment and heating treatment: The high-mineralization mine water is subjected to chemical precipitation to remove sulfate, acid stripping to remove bicarbonate and neutralization to adjust pH to obtain pretreated mine water; the pretreated mine water is concentrated by electrodialysis and the resulting concentrated water is heated to obtain mineralization reaction base liquid; Step (2) Preparation of injection fluid: Add amino acid catalyst, chelating agent and inorganic base to the mineralization reaction base liquid. Set the amount of inorganic base according to the pH drop after CO2 dissolution and the principle of neutralizing excess carbonic acid based on the target reservoir conditions. Set the amount of catalyst in combination with the amphoteric dissociation buffering effect so that the microenvironment pH of the mixed fluid is maintained at 7.0-8.5 during in-situ mineralization in the reservoir pores. Mix to obtain homogeneous injection fluid; Step (3) Mixing and segmented depressurization injection: Supercritical CO2 and the homogeneous injection fluid are reinjected to the target reservoir depth through concentric double pipes via inner and outer pipes respectively; after mixing by downhole gas-liquid mixer, segmented depressurization is performed and injected into the pores of the target reservoir for mineralization and storage; Step (4) Extraction and treatment: Extract the mineralized and sealed formation water and purify it a second time to remove residual suspended solids and meet the water quality requirements of pretreated mine water. As a supplementary water source, it can continue to participate in the preparation of CO2 mineralized and sealed fluid to realize the recycling of water resources.

[0004] Preferably, in step (1), the electrodialysis concentration treatment increases the concentration of calcium and magnesium ions in the concentrated water to 2-4 times the concentration of calcium and magnesium ions in the pretreated mine water.

[0005] Preferably, in step (1), the temperature of the heat treatment is controlled between 40°C and 80°C.

[0006] Preferably, in step (2), the amino acid catalyst is selected from at least one of glycine, N-methylalanine, and arginine, and the mass fraction of the amino acid catalyst in the homogeneous injection fluid is 0.1%-5%.

[0007] Preferably, in step (2), the chelating agent is selected from at least one of sodium citrate, sodium gluconate, and polyaspartic acid, and the mass fraction of the chelating agent in the homogeneous injection fluid is 0.05%-2.5%; the inorganic base is sodium carbonate.

[0008] Preferably, in step (3), the injection pressure of the supercritical CO2 is controlled at 14MPa-25MPa.

[0009] Preferably, in step (3), gas-liquid mixing is performed downhole using a gas-liquid mixer; and segmented pressure reduction is performed downhole using a multi-stage throttle valve. The segmented pressure reduction includes 3-5 pressure reduction gradients, with the pressure drop of each gradient controlled between 0.5 MPa and 2.0 MPa.

[0010] Preferably, in step (2), the amino acid catalyst is glycine with a mass fraction of 0.4%-0.6%; the chelating agent is sodium citrate with a mass fraction of 0.2%-0.4%; and the inorganic base has a mass fraction of 0.05%-0.15%.

[0011] Preferably, in step (2), the amino acid catalyst is N-methylalanine with a mass fraction of 0.7%-0.9%; the chelating agent is polyaspartic acid with a mass fraction of 0.5%-0.7%; and the inorganic base has a mass fraction of 0.05%-0.15%.

[0012] The beneficial effects of this invention are as follows: By adjusting the addition ratio of amino acid catalysts, chelating agents, and inorganic bases to maintain the pH value, the activity of amino acid catalysts in CO2-rich environments was ensured, and the mineralization rate was improved. Specific chelating agents were selected in a reasonable manner to prevent scaling of fluids in the wellbore area and to achieve controllable nucleation in deep formations. A segmented depressurization process was adopted for injection, which improved gas-liquid mixing conditions and extended the effective reaction contact area. Detailed Implementation

[0013] The technical solutions in the embodiments of the present invention will be clearly and completely described below; the described embodiments are some embodiments of the present invention, but not all embodiments. All other embodiments obtained by those skilled in the art based on the embodiments of the present invention without creative effort are within the scope of protection of the present invention. Example 1: This embodiment provides an in-situ mineralization and sequestration method based on deep co-injection of CO2 with high-salinity mine water, specifically including the following steps: S1 Pretreatment, Pre-enrichment and Heating: Take mine water from a deep aquifer in a coal mine. The aquifer is buried at a depth of 1200m, the formation temperature is 45℃, and the formation pressure is 12MPa. The calcium ion concentration in the raw mine water is 1200mg / L, and the magnesium ion concentration is 800mg / L. Sulfate ions and bicarbonate ions were removed from mine water by chemical precipitation to obtain pretreated mine water. The pretreated mine water removed interfering anions, providing a low-impurity precursor for subsequent electrodialysis concentration, which can effectively avoid scaling during the concentration process. The specific steps are as follows: Barium chloride is added to the mine water as a chemical precipitant, with an addition amount of SO4. 2- The concentration was 1.05 times that of barium sulfate, and the mixture was stirred at room temperature for 30 minutes to precipitate barium sulfate. Dilute hydrochloric acid was added to adjust the pH of the fluid to 4.5, and air was purged for 30 minutes to remove HCO3-. -Finally, sodium hydroxide is added to adjust the pH to neutral; this process achieves selective removal of sulfate and bicarbonate ions without causing calcium and magnesium ions to co-precipitate and be lost. Pretreated mine water is fed into a selective electrodialysis unit for concentration, with the concentration factor controlled at 2.5 times, so that the calcium ion concentration in the concentrate reaches 3000 mg / L and the magnesium ion concentration reaches 2000 mg / L. The concentrate is then heated to 55°C using a heating device to obtain a mineralization reaction base solution. This base solution serves as a carrier for enriching calcium and magnesium ions, providing a sufficient cation source and suitable initial thermodynamic conditions for subsequent mineralization reactions. S2 Injection Fluid Preparation: Glycine, sodium citrate, and sodium carbonate are added to the mineralization reaction base solution obtained in step S1, wherein the mass fraction of glycine in the homogeneous injection fluid is 0.5%, the mass fraction of sodium citrate is 0.3%, and the mass fraction of sodium carbonate is 0.1%. In this process, by adjusting the addition ratio of amino acid catalysts, chelating agents and inorganic bases, the pH value of the mixed fluid during mineralization and storage treatment in the target reservoir pores is maintained at 7.0-8.5. The specific adjustment criteria and calculation methods are as follows: first, the initial hardness and alkalinity of the raw mine water are measured, and the theoretical acid pH reduction after CO2 dissolution is predicted based on the formation temperature and pressure of the target reservoir, using a geochemical thermodynamic model. The dosage of chelating agent was determined according to the total molar ratio of calcium to magnesium of 1:0.06. The dosage of inorganic base was calculated and added according to the predicted amount of carbonic acid generated and the acid-base neutralization stoichiometric ratio to make the basic pH of the mixture reach 6.5. An amino acid catalyst with amphoteric dissociation buffering effect was added according to the final target pH to control the microenvironment pH during the formation mineralization process at 7.5. The mixture was stirred at a speed of 400 r / min for 30 min to obtain a homogeneous injection fluid. The homogeneous injection fluid ensured the uniform distribution of the catalyst, chelating agent and inorganic base, so as to fully contact with supercritical CO2 downhole and exert a synergistic regulatory effect. S3 Downhole Mixing and Staged Pressure Reduction: Concentric double-tube injection is used. Supercritical CO2 is injected into the inner tube, and the homogeneous injection fluid obtained in step S2 is injected into the outer tube. The supercritical CO2 injection pressure is controlled at 16MPa. A downhole gas-liquid mixer is set at the target reservoir depth to mix the supercritical CO2 with the homogeneous injection fluid to form a mixed fluid. The mixed fluid enables supercritical CO2 to form a highly dispersed gas-liquid mixture in a liquid phase containing catalysts and hardness ions, providing the material and kinetic basis for rapid in-situ mineralization after entering the formation pores. The mixed fluid undergoes staged depressurization through a downhole multi-stage choke valve, with three stages of depressurization and a pressure drop of 1.0 MPa at each stage. After staged depressurization, the mixed fluid is injected into the target reservoir pores. S4 Formation Mineralization and Production: After the mixed fluid enters the formation, the dissolved CO2 is converted into bicarbonate and carbonate under the catalysis of glycine; citrate complexes calcium and magnesium ions in the wellbore stage, reducing the tendency of near-wellbore scaling; sodium carbonate and the buffering capacity of the mine water together regulate the pH of the formation microenvironment. After the formation reaction is completed, the mineralized formation water is extracted through production wells and sent to a surface separation system for secondary purification to remove residual carbonate solids and interfering ions to meet the initial pretreatment requirements. This purified water then serves as a supplementary water source for the next round of CO2 mineralization and sequestration fluid preparation, achieving water resource recycling. Monitoring well sampling shows that the formation microenvironment pH remains between 7.2 and 7.8. X-ray diffraction analysis of the extracted core samples shows a distinct calcite characteristic peak at 2θ = 29.4°, where 2θ is the diffraction angle and the 29.4° peak corresponds to the characteristic diffraction peak of calcite. Scanning electron microscopy and energy dispersive spectroscopy indicate the formation of carbonate crystals with a particle size of 2 to 5 μm on the pore surface. Stable carbon isotope analysis indicates that the carbon in the newly formed carbonates originates from injected CO2.

[0014] Example 2: This embodiment provides an in-situ mineralization and sequestration method based on deep co-injection of CO2 with high-salinity mine water, specifically including the following steps: S1 Pretreatment, Pre-enrichment and Heating: Take similar high-mineralization mine water and remove sulfate and bicarbonate ions according to the method in Example 1; concentrate by selective electrodialysis, controlling the concentration factor to be 3.0 times; heat the concentrated water to 60°C using a heating device to obtain the mineralization reaction base liquid; S2 injection fluid preparation: N-methylalanine, polyaspartic acid, and sodium carbonate are added to the mineralization reaction base solution, wherein the mass fraction of N-methylalanine is 0.8%, the mass fraction of polyaspartic acid is 0.6%, and the mass fraction of sodium carbonate is 0.1%. Based on the adjustment criteria of Example 1, the pH value of the mixed fluid during mineralization and storage treatment in the target reservoir pores was maintained at 7.0-8.5 by adjusting the addition ratio of amino acid catalyst, chelating agent and inorganic base; the mixture was then mixed by ultrasonic dispersion, with the ultrasonic frequency controlled at 40kHz, power at 300W and dispersion time at 20min, to obtain a homogeneous injection fluid. S3 downhole mixing and staged depressurization: Concentric dual-tube injection is used, with supercritical CO2 injected into the inner tube and homogeneous injection fluid injected into the outer tube; the supercritical CO2 injection pressure is controlled at 14.5 MPa; after mixing by the downhole gas-liquid mixer, the mixed fluid is subjected to staged depressurization through a 4-stage throttle valve, with a pressure drop of 1.0 MPa at each stage, before being injected into the target reservoir pores; S4 Formation Mineralization and Production: In-situ mineralization reactions were carried out in the formation using mixed fluids, and the resulting formation water was produced. Monitoring results showed that this formulation could delay the degradation of calcium. 2+ and Mg 2+ Release allows mineralized deposits to be distributed more extensively in deeper regions, resulting in minimal changes in near-wellbore injection pressure; Fourier transform infrared spectroscopy of the in-situ sampled fluid at 1535 cm⁻¹... -1 and 1382cm -1 Characteristic absorption peaks of carbamate intermediates were observed at [location].

[0015] Example 3: This embodiment provides an in-situ mineralization and sequestration method based on deep co-injection of CO2 with high-salinity mine water, specifically including the following steps: S1 Pretreatment, Pre-enrichment and Heating: High-mineralization mine water was taken and sulfate and bicarbonate ions were removed according to the method in Example 1; selective electrodialysis was used for concentration, and the concentration factor was controlled to be 2.0 times; the concentrated water was heated to 40°C to obtain the mineralization reaction base liquid; S2 Injection Fluid Preparation: Glycine, sodium gluconate, and sodium carbonate were added to the mineralization reaction base solution, wherein the mass fraction of glycine was 0.1%, the mass fraction of sodium gluconate was 0.05%, and the mass fraction of sodium carbonate was 0.05%. Following the adjustment criteria in Example 1, the pH value of the mixed fluid during mineralization and storage treatment in the target reservoir pores was maintained at 7.0-8.5 by adjusting the addition ratio of amino acid catalyst, chelating agent, and inorganic base. The mixture was then stirred at a speed of 300 r / min for 25 min to obtain a homogeneous injection fluid. S3 downhole mixing and staged depressurization: Concentric double pipes are used for injection, with supercritical CO2 injected into the inner pipe and homogeneous injection fluid injected into the outer pipe; the supercritical CO2 injection pressure is controlled at 14MPa; after mixing by the downhole gas-liquid mixer, the mixed fluid is subjected to staged depressurization through a 3-stage throttle valve, with a pressure drop of 0.5MPa at each stage, before being injected into the target reservoir pores; S4 Formation mineralization and production: The mixed fluid undergoes in-situ mineralization reaction in the formation and the formation water is produced through the production well; in this example, the amount of catalyst, chelating agent and inorganic base is relatively low, and mineralization can still occur, but the carbonate formation rate and hardness removal are lower than in Example 1.

[0016] Example 4: This embodiment provides an in-situ mineralization and sequestration method based on deep co-injection of CO2 with high-salinity mine water, specifically including the following steps: S1 Pretreatment, Pre-enrichment and Heating: High-mineralization mine water was taken and sulfate and bicarbonate ions were removed according to the method in Example 1; selective electrodialysis was used for concentration, and the concentration factor was controlled to be 4.0 times; the concentrated water was heated to 80°C to obtain the mineralization reaction base solution; S2 injection fluid preparation: Arginine, sodium citrate, and sodium carbonate were added to the mineralization reaction base liquid, wherein the mass fraction of arginine was 5.0%, the mass fraction of sodium citrate was 2.5%, and the mass fraction of sodium carbonate was 0.15%; after stirring and mixing, the stirring speed was controlled at 500 r / min and the stirring time was 40 min to obtain a homogeneous injection fluid; S3 downhole mixing and staged depressurization: Concentric double pipes are used for injection, with supercritical CO2 injected into the inner pipe and homogeneous injection fluid injected into the outer pipe; the supercritical CO2 injection pressure is controlled at 25MPa; after mixing by the downhole gas-liquid mixer, the mixed fluid is subjected to staged depressurization through a 5-stage throttle valve, with a pressure drop of 2.0MPa at each stage, before being injected into the target reservoir pores; S4 Formation Mineralization and Production: The mixed fluid undergoes in-situ mineralization in the formation, and formation water is produced via a production well. In this example, the ion enrichment level is high, and a large amount of carbonate precipitate can be formed in the formation. However, due to the high dosage of chelating agent, Ca... 2+ and Mg 2+ The release rate was somewhat slowed down, and the overall mineralization rate was lower than that in Example 1.

[0017] Comparative Example 1: The difference between this comparative example and Example 1 is that glycine is omitted in step S2, while other operating steps and process parameters are exactly the same as in Example 1; in this comparative example, the homogeneous injection fluid contains only 0.3% sodium citrate and 0.1% sodium carbonate.

[0018] Comparative Example 2: The difference between this comparative example and Example 1 is that sodium citrate is omitted in step S2, while other operating steps and process parameters are exactly the same as in Example 1; in this comparative example, the homogeneous injection fluid contains only 0.5% glycine and 0.1% sodium carbonate.

[0019] Comparative Example 3: The difference between this comparative example and Example 1 is that sodium carbonate is omitted in step S2, while other operating steps and process parameters are exactly the same as in Example 1; in this comparative example, the homogeneous injection fluid contains only 0.5% glycine and 0.3% sodium citrate.

[0020] Comparative Example 4: The difference between this comparative example and Example 1 is that: in step S3, no staged depressurization is performed, and the mixture is directly injected into the target reservoir pores after downhole mixing; other operating steps and process parameters are exactly the same as in Example 1.

[0021] Comparative Example 5: The difference between this comparative example and Example 1 is that: in step S1, electrodialysis concentration is not performed, and the mine water after removing sulfate and bicarbonate ions is directly heated to 55°C and used as the base liquid for mineralization reaction. Other operating steps and process parameters are exactly the same as in Example 1.

[0022] Comparative Example 6: The difference between this comparative example and Example 1 is that no heating treatment is performed in step S1, and the concentrated water after electrodialysis is directly used as the base liquid for mineralization reaction. Other operating steps and process parameters are exactly the same as in Example 1.

[0023] Performance Tests and Data Sheets: The formation of carbonates in the formation was confirmed by sampling from monitoring wells combined with X-ray diffraction, scanning electron microscopy, energy dispersive spectroscopy, Fourier transform infrared spectroscopy, and stable carbon isotope analysis. The relative mineralization rate was characterized by the amount of carbonates formed per unit volume of formation water. The total hardness of the produced water was calculated as CaCO3, and the increase in injection pressure was the increase in wellhead pressure relative to the initial injection pressure under the same injection volume. The determination of the total hardness of the produced water was based on the "Determination of Total Calcium and Magnesium in Water by EDTA Titration Method". The carbonate crystal size was observed and calibrated using scanning electron microscopy in accordance with the "Guidelines for Calibration of Magnification of Scanning Electron Microscope Images for Microbeam Analysis". Table 1 Performance test results of each embodiment and comparative example sample Formation microenvironment pH Relative mineralization rate factor Total hardness reduction of produced water / % Injection pressure increase / % Characteristics of newly formed carbonates Example 1 7.2 to 7.8 50 85 8 The calcite peaks are distinct, and the crystals are evenly distributed. Example 2 7.1 to 7.6 42 82 5 Carbonate deposits are deep, with fewer near-wellbore deposits. Example 3 7.0 to 7.3 28 76 10 Low carbonate formation Example 4 7.4 to 8.1 35 80 12 The amount of carbonate formed is relatively high, and the release rate is relatively slow. Comparative Example 1 6.6 to 7.0 1 31 9 Only a small amount of carbonate precipitate was observed. Comparative Example 2 7.1 to 7.6 18 52 38 Near-wellbore deposits are concentrated and scaling is obvious. Comparative Example 3 4.3 to 5.1 6 36 4 The carbonate peak is weak. Comparative Example 4 7.0 to 7.5 21 58 24 Uneven carbonate deposition Comparative Example 5 7.0 to 7.5 20 49 7 Low carbonate formation Comparative Example 6 6.8 to 7.2 24 57 13 Low rate of carbonate formation ; As can be seen from the comparison of the test results of Example 1 and Comparative Example 1 in Table 1, omitting the amino acid catalyst resulted in a decrease in both the relative mineralization rate and the reduction in the total hardness of the produced water; after the absence of glycine, dissolved CO2 mainly relied on natural hydration to generate HCO3. - The hydration kinetics reaction rate is extremely low, resulting in low CO3 concentration in the formation. 2- The accumulation rate decreases, Ca 2+ and Mg 2+ The rate of precipitation by combining with carbonate ions decreases accordingly, so only a small amount of carbonate solid phase is formed, and the removal of hardness ions also decreases. As can be seen from the comparison of the test results of Example 1 and Comparative Example 2 in Table 1, omitting the chelating agent increased the injection pressure increase and decreased the total hardness reduction of the produced water; after the absence of sodium citrate, the free Ca in the wellbore and near-wellbore area decreased. 2+ and Mg 2 +If effective complexation cannot be achieved, the locally supersaturated zone formed after mixing is more likely to precipitate carbonates near the wellbore, resulting in early limitation of pores and flow channels and increased injection pressure; at the same time, the amount of hardness ions that can participate in the reaction in the deep formation is reduced, thus reducing the degree of deep mineralization. As can be seen from the comparison of the test results of Example 1 and Comparative Example 3 in Table 1, omitting the inorganic alkali significantly reduced the pH of the formation microenvironment, and decreased the relative mineralization rate and hardness removal rate; with the absence of sodium carbonate, the H+ generated by CO2 dissolution could not be adequately buffered, and the system was more prone to acidic conditions; under these conditions, CO3... 2- As the proportion decreases, the driving force for the nucleation and precipitation of CaCO3 and MgCO3 weakens, and the effective nucleophilic activity of glycine is also inhibited, thus limiting the mineralization reaction. As can be seen from the comparison of the test results of Example 1 and Comparative Example 4 in Table 1, after canceling the segmented pressure reduction treatment, the relative mineralization rate decreased and the injection pressure increase increased. The pressure pulse generated by the segmented pressure reduction is conducive to the formation of a finer dispersed phase of supercritical CO2 in the liquid phase and improves the gas-liquid contact conditions. After this feature is lost, the mass transfer efficiency between CO2 and the liquid phase decreases, the local concentration distribution is uneven, and the deposition is concentrated in some areas, resulting in a decrease in mineralization efficiency and an increase in flow resistance during the injection process. As can be seen from the comparison of the test results of Example 1 and Comparative Example 5 in Table 1, omitting the electrodialysis concentration treatment resulted in a decrease in both the relative mineralization rate and the total hardness of the produced water; the Ca in the unconcentrated mine water... 2+ and Mg 2+ At lower concentrations, the total amount of mineralized cations that can be provided per unit volume of injected fluid is reduced, resulting in insufficient material basis for the formation of carbonate precipitation in the formation. Therefore, both CO2 fixation and hardness ion removal are limited. As can be seen from the comparison of the test results of Example 1 and Comparative Example 6 in Table 1, after omitting the heat treatment, the relative mineralization rate and the decrease in the total hardness of the produced water both decreased. The heat treatment is beneficial to improve the ion activity and improve the mass transfer conditions in the reaction process between CO2 and the liquid phase. After this feature is missing, the reactivity of the mixed fluid decreases, the counteracting effect of the segmented depressurization process on local temperature fluctuations is weakened, resulting in a decrease in the effective mineralization reaction degree in the formation. A comparison of the test results of Examples 1 to 4 in Table 1 shows that, within the scope defined by this invention, adjusting the concentration factor, heating temperature, catalyst type and dosage, chelating agent type and dosage, and staged pressure reduction parameters can all achieve in-situ CO2 mineralization and storage and formation water hardness reduction. Among them, in Example 1, the matching of catalytic, complexing, buffering, ion supply, and staged pressure reduction parameters is more coordinated, the mineralization rate and hardness reduction are higher than in other examples, and the injection pressure increase is lower than in other examples. Example 2 is more conducive to suppressing near-wellbore deposition. Example 3 verifies that the lower parameter end is still feasible. Example 4 verifies that mineralization and storage can also be achieved at the higher parameter end.

[0024] The above are merely specific embodiments of the present invention and are not intended to limit the present invention in any other way. Any person skilled in the art may make changes or modifications to the above-disclosed technical content to create equivalent embodiments for application in other fields. However, any conventional modifications, equivalent changes and modifications made to the above embodiments based on the technical essence of the present invention without departing from the technical solution of the present invention shall still fall within the protection scope of the technical solution of the present invention.

Claims

1. A method for CO2 mineralization and sequestration based on deep co-injection of high-salinity mine water, characterized in that, include: Step (1) Pre-enrichment and heating treatment: High-mineralized mine water is subjected to chemical precipitation to remove sulfate, acid stripping to remove bicarbonate, and neutralization to adjust pH in sequence to obtain pretreated mine water; Pretreated mine water is concentrated by electrodialysis, and the resulting concentrated water is heated to obtain a mineralization reaction base liquid; Step (2) Preparation of injection fluid: Add amino acid catalyst, chelating agent and inorganic base to the mineralization reaction base liquid. Set the amount of inorganic base according to the pH drop after CO2 dissolution and the principle of neutralizing excess carbonic acid based on the target reservoir conditions. Set the amount of catalyst in combination with the amphoteric dissociation buffering effect so that the microenvironment pH of the mixed fluid is maintained at 7.0-8.5 during in-situ mineralization in the reservoir pores. Mix to obtain homogeneous injection fluid; Step (3) Mixing and segmented depressurization injection: Supercritical CO2 and the homogeneous injection fluid are reinjected to the target reservoir depth through concentric double pipes via inner and outer pipes respectively; after mixing by downhole gas-liquid mixer, segmented depressurization is performed and injected into the pores of the target reservoir for mineralization and storage; Step (4) Extraction and treatment: Extract the mineralized and sealed formation water and purify it a second time to remove residual suspended solids and meet the water quality requirements of pretreated mine water. As a supplementary water source, it can continue to participate in the preparation of CO2 mineralized and sealed fluid to realize the recycling of water resources.

2. The CO2 mineralization and sequestration method based on deep co-injection of high-salinity mine water as described in claim 1, characterized in that: In step (1), the electrodialysis concentration treatment increases the concentration of calcium and magnesium ions in the concentrated water to 2-4 times the concentration of calcium and magnesium ions in the pretreated mine water.

3. The CO2 mineralization and sequestration method based on deep co-injection of high-salinity mine water as described in claim 2, characterized in that: In step (1), the temperature of the heat treatment is controlled between 40℃ and 80℃.

4. The CO2 mineralization and sequestration method based on deep co-injection of high-salinity mine water as described in claim 1, characterized in that: In step (2), the amino acid catalyst is selected from at least one of glycine, N-methylalanine, and arginine, and the mass fraction of the amino acid catalyst in the homogeneous injection fluid is 0.1%-5%.

5. The CO2 mineralization and sequestration method based on deep co-injection of high-salinity mine water as described in claim 1, characterized in that: In step (2), the chelating agent is selected from at least one of sodium citrate, sodium gluconate, and polyaspartic acid, and the mass fraction of the chelating agent in the homogeneous injection fluid is 0.05%-2.5%; the inorganic base is sodium carbonate.

6. The CO2 mineralization and sequestration method based on deep co-injection of high-salinity mine water as described in claim 1, characterized in that: In step (3), the injection pressure of the supercritical CO2 is controlled at 14MPa-25MPa.

7. The CO2 mineralization and sequestration method based on deep co-injection of high-salinity mine water as described in claim 1, characterized in that: In step (3), gas-liquid mixing is performed downhole using a gas-liquid mixer; the segmented pressure reduction is performed downhole using a multi-stage throttle valve, which includes 3-5 pressure reduction gradients, with the pressure drop of each gradient controlled between 0.5 MPa and 2.0 MPa.

8. The CO2 mineralization and sequestration method based on deep co-injection of high-salinity mine water as described in claim 1, characterized in that: In step (2), the amino acid catalyst is glycine with a mass fraction of 0.4%-0.6%; the chelating agent is sodium citrate with a mass fraction of 0.2%-0.4%; and the inorganic base has a mass fraction of 0.05%-0.15%.

9. The CO2 mineralization and sequestration method based on deep co-injection of high-salinity mine water as described in claim 1, characterized in that: In step (2), the amino acid catalyst is N-methylalanine with a mass fraction of 0.7%-0.9%; the chelating agent is polyaspartic acid with a mass fraction of 0.5%-0.7%; and the inorganic base has a mass fraction of 0.05%-0.15%.