A method for CO2 injection to extract natural hydrogen reservoirs and carbon sequestration

Abstract

The present application relates to the field of natural hydrogen exploitation and carbon sequestration, and particularly relates to a method for CO2 injection to exploit natural hydrogen reservoir and carbon sequestration. The method can effectively inhibit water invasion and significantly improve hydrogen recovery by optimizing the initial injection rate of CO2, injecting CO2 at the appropriate time according to the formation characteristics, continuously monitoring the CO2 content of the production well during the injection process, and adjusting the injection rate according to the gas-water ratio and CO2 content. The recovery rate can be increased by 20-40% before and after injection in different formations. The present application can achieve CO2 geological sequestration and provide carbon emission reduction environmental benefits.

Description

Technical Field

[0001] This invention relates to the field of natural hydrogen extraction and carbon sequestration, specifically to a method for CO2 injection extraction of natural hydrogen reservoirs and carbon sequestration. Background Technology

[0002] With the global energy transition towards low-carbon energy, hydrogen energy is receiving increasing attention as a clean energy carrier. Traditionally, hydrogen is mainly produced through water electrolysis or natural gas reforming, but the discovery of natural hydrogen reservoirs in recent years has provided new avenues for hydrogen energy development.

[0003] Natural hydrogen reservoirs are primarily formed through serpentinization, a process involving the hydration and oxidation of ultramafic rocks in the Earth's crust and upper mantle. These reservoirs represent a vast and untapped potential energy resource. Pressure exhaustion is a method of extraction that utilizes the reservoir's own pressure energy. It does not require additional fluid injection to maintain reservoir pressure or the application of other energy sources, thus resulting in relatively low extraction costs. Furthermore, this method is highly adaptable to various reservoir types, and may be a particularly effective extraction method for reservoirs with low permeability and poor water injection performance.

[0004] However, the development of natural hydrogen reservoirs faces a serious problem of water intrusion during pressure depletion extraction. When reservoir pressure decreases, surrounding water intrudes into the gas zone, reducing gas flow capacity, trapping large amounts of hydrogen, and ultimately reducing production efficiency. Currently, research on water intrusion in natural hydrogen reservoirs is relatively limited, and there is a lack of effective solutions to enhance hydrogen recovery while controlling water intrusion. Therefore, there is an urgent need to develop a technological approach that can effectively address this problem while considering environmental sustainability. Summary of the Invention

[0005] This invention provides a method for CO2 injection and carbon sequestration in natural hydrogen reservoirs to improve hydrogen recovery. This invention effectively inhibits water intrusion, increases hydrogen recovery, and simultaneously achieves CO2 geological sequestration, thus achieving the dual goals of energy development and environmental protection.

[0006] To achieve the above objectives, the present invention adopts the following technical solution:

[0007] A method for CO2 injection to extract natural hydrogen reservoirs and for carbon sequestration includes the following steps:

[0008] (1) Conduct characteristic analysis of the reservoir, including measuring reservoir depth, temperature, initial pressure, porosity, permeability, initial hydrogen saturation and water saturation, and establish a benchmark for the exploitation of natural hydrogen reservoir pressure depletion; start natural hydrogen production through pressure depletion method, and monitor reservoir pressure changes, hydrogen production and water production.

[0009] (2) Determine the timing of CO2 injection: Injection should begin when a significant increase in water production is detected;

[0010] (3) Determine the initial CO2 injection rate: The initial CO2 injection rate is 10%-25% of the daily hydrogen production;

[0011] (4) Inject CO2 into the reservoir through the injection well according to the injection timing and initial injection volume determined in steps (2) and (3);

[0012] (5) Maintain the injection-production ratio within the range of 0.8-1.2, continuously monitor hydrogen production, water production and CO2 breakthrough, and dynamically adjust the CO2 injection rate based on the monitoring results;

[0013] (6) During the injection process, the CO2 content of the production well is continuously monitored. When the CO2 content in the production well reaches 10% of the hydrogen content, the injection is stopped.

[0014] Preferably, in step (2), the criterion for judging a significant increase in water production is: when the water-air ratio is continuously monitored to increase by more than 200% within 60 days (for example, from 0.1 cubic meters / 10,000 cubic meters to more than 0.3 cubic meters / 10,000 cubic meters), and the daily water production growth rate exceeds twice the average growth rate of the previous 30 days, it is considered that the water production has increased significantly.

[0015] Preferably, in step (3), for reservoirs with permeability in the range of 500-2000 mD, the initial injection rate is between 16% and 25% of the daily hydrogen production; for reservoirs with permeability in the range of 200-500 mD (excluding 500), the initial injection rate is usually between 12% and 16% of the daily hydrogen production; and for low-permeability reservoirs with permeability <200 mD, the initial injection rate is 10%-12% of the daily hydrogen production.

[0016] Preferably, the injection well in step (4) is located between the aquifer and the gas zone to maximize CO2 displacement efficiency and mitigate water intrusion.

[0017] Preferably, in step (5), when the water-to-gas ratio continues to rise to more than 20% of the average value of the previous period (the time before the significant rise in the gas-to-water ratio, i.e. before this), the CO2 injection rate is increased by 5-10%; when the CO2 content of the production well reaches 5%, the injection rate is reduced by 10-15%; when the hydrogen production decreases by more than 10% and the CO2 content does not exceed 3%, the injection rate is increased by 15-20%.

[0018] Preferably, the injection-production ratio of CO2 and hydrogen in step (6) is 1:1.

[0019] The CO2 injection of this invention has a dual interfacial effect: the CO2 and H2 mixture significantly reduces the gas-water interfacial tension, reduces capillary resistance, and fundamentally inhibits water intrusion; CO2 preferentially adsorbs on the surface of dolomite, forming a CO2-rich barrier layer to block the migration of water molecules; the adsorption strength of CO2 is greater than that of H2, which can displace adsorbed hydrogen molecules and enhance their fluidity; it achieves a multiphase synergistic effect of gas-liquid-solid phase: simultaneously regulating the properties of the gas-water interface and the properties of the rock surface.

[0020] The beneficial effects of this invention are:

[0021] (1) By injecting CO2 at the appropriate time, water intrusion can be effectively suppressed and hydrogen recovery rate can be significantly improved; depending on the different formations, the recovery rate can be increased by 20-40% before and after injection.

[0022] (2) After CO2 is mixed with hydrogen, the interfacial tension between gas and water is reduced, the capillary resistance is reduced, and the water intrusion is further slowed down.

[0023] (3) CO2 preferentially adsorbs on the rock surface, forming a CO2-rich adsorption layer, which serves as a barrier against water intrusion;

[0024] (4) Achieve CO2 geological sequestration and provide carbon emission reduction environmental benefits;

[0025] (5) By optimizing the injection rate and timing, a balance between hydrogen harvesting and CO2 sequestration can be achieved, maximizing economic and environmental benefits. Attached Figure Description

[0026] Figure 1 This graph shows the relationship between hydrogen recovery rate and average reservoir pressure during different extraction processes.

[0027] Figure 2 Comparison of water production changes before and after CO2 injection;

[0028] Figure 3 A comparison chart of cumulative hydrogen production at different CO2 injection rates;

[0029] Figure 4 A comparison chart of hydrogen recovery rate and CO2 sequestration under different CO2 injection timings. Detailed Implementation

[0030] The present invention will be further described in detail below with reference to specific embodiments.

[0031] In this embodiment, the natural hydrogen reservoir has a depth of 250 meters, a temperature of 100°C, an initial pressure of 30 MPa, a porosity of 0.3, a permeability of 1000 mD, and initial conditions of 50% hydrogen saturation and 50% water saturation. (As per the attached...) Figure 1 The flowchart shown illustrates the process of CO2 extraction from natural hydrogen reservoirs and carbon sequestration.

[0032] (1) Establish a benchmark for the exploitation of natural hydrogen reservoirs under pressure depletion, start natural hydrogen production through the pressure depletion method, and monitor reservoir pressure changes, hydrogen production and water production.

[0033] In the initial stage of production, hydrogen production stabilized at approximately 100,000 m³. 3 With almost no water production per day, the reservoir pressure is high enough to effectively promote hydrogen extraction while limiting water intrusion. As production progresses, water production and water intrusion gradually increase, accompanied by a slow decrease in reservoir pressure.

[0034] (2) Determine the timing of CO2 injection:

[0035] After about 1,500 days of production, water production and water intrusion volume increase significantly. At this point, reservoir pressure drops rapidly, requiring CO2 injection to improve recovery.

[0036] Based on the results of reservoir numerical simulation verification Figure 4 For different CO2 injection timings (when optimizing the injection timing, the initial CO2 injection volume is 20,000 m³), 3 A comparison chart of hydrogen recovery rate and CO2 sequestration (d) is shown. Figure 4 It can be seen that injecting CO2 too early (e.g., at 1,600 or 1,800 days) wastes CO2 and results in poor performance due to the short breakthrough time. Although early CO2 injection inhibits water intrusion, it also reduces hydrogen production. Injecting too late, on the other hand, makes it difficult to reverse the already formed severe water intrusion channels. By day 2,200, water saturation increases to the point that hydrogen production completely stops. CO2 injection is most effective when pressure depletion production begins at day 1,980. At this time, the reservoir pressure drops to 7.41 MPa, and the water-to-gas ratio increases from 0.05 m³ / 10,000 m³ in the initial stage to 0.26 m³ / 10,000 m³, an increase of more than 500%. The daily water production exceeds 30% of the production well's designed drainage capacity (1,000 m³ / day), reaching 1,300 m³ / day.

[0037] Based on the results of reservoir numerical simulation verification, the timing for CO2 injection is determined as follows: CO2 injection should begin when water production increases significantly, that is, when the water-gas ratio rises from 0.1 cubic meters per 10,000 cubic meters to more than 0.3 cubic meters per 10,000 cubic meters within 60 days (an increase of more than 200%), and the daily water production growth rate exceeds twice the average growth rate of the previous 30 days.

[0038] At this point, the reservoir pressure dropped rapidly: the pressure drop rate exceeded 0.5 MPa / month, more than three times higher than the previous average pressure drop rate (0.15 MPa / month). This indicates that the reservoir is about to enter the water intrusion runaway stage, and without intervention, a large amount of hydrogen will be trapped in the flooded area and cannot be extracted.

[0039] Injecting CO2 at this time can effectively control water invasion in the initial acceleration stage, achieving the best recovery rate enhancement effect.

[0040] (3) Determine the initial CO2 injection rate:

[0041] Based on reservoir numerical simulation, the effects of different initial CO2 injection rates on hydrogen recovery, water intrusion suppression, and CO2 sequestration are evaluated. Figure 3 A comparison chart of cumulative hydrogen production at different CO2 injection rates. Figure 3 It can be seen that a lower initial injection rate (e.g., 10,000 m) 3 / d) is insufficient to adequately prevent water intrusion, leading to persistent water intrusion. Higher injection rates (30,000 m) are also insufficient. 3 (at a rate of 20,000 m³ / d and above), an excessive initial CO2 injection rate begins to negatively impact hydrogen production. 3 At a rate of / d, CO2 production remained at a minimum, indicating optimal CO2 retention in the reservoir. When the initial injection rate increased to 30,000 m³ / d, CO2 production remained at a minimum. 3 When the CO2 production rate is 1 / d or higher, the CO2 production rate increases significantly, indicating that excess CO2 begins to overflow rather than be effectively used to control water intrusion or CO2 sequestration.

[0042] Based on reservoir numerical simulation, this embodiment selects a depth of 20,000 m. 3 An initial CO2 injection rate of / d (at which point the injection rate is 20% of the daily hydrogen production) can achieve the highest hydrogen production.

[0043] The results show that, for different reservoir conditions, the initial injection rate should be determined according to the following principles: for reservoirs with permeability in the range of 500-2000 mD, the initial injection rate is usually between 16% and 25% of the daily hydrogen production; for reservoirs with permeability in the range of 200-500 mD (excluding 500 mD), the initial injection rate is usually between 12% and 16% of the daily hydrogen production; and for low-permeability reservoirs (permeability <200 mD), the initial injection rate is between 10% and 12% of the daily hydrogen production.

[0044] (4) Inject CO2

[0045] When hydrogen extraction has been underway for 1,980 days, the initial injection rate of 20,000 m³ / h was determined in step (3). 3 / d CO2 injection. At this point, severe water intrusion had significantly reduced hydrogen production, indicating that CO2 injection effectively inhibited water intrusion and enhanced hydrogen recovery.

[0046] Depend on Figure 1It can be seen that after CO2 injection, the recovery rate increased from 45% to over 65%, an increase of 20%.

[0047] (5) Continuously monitor all parameters and dynamically adjust the injection parameters.

[0048] Maintain the injection-production ratio within the range of 0.8-1.2, and dynamically adjust the CO2 injection parameters. When the water-gas ratio continues to rise to more than 20% above the previous average, increase the CO2 injection rate by 5-10% based on the initial injection rate. When the CO2 content in the production well reaches 5%, decrease the CO2 injection rate by 10-15%. When the daily hydrogen production decreases by more than 10% compared to the previous day, and the CO2 content does not exceed 3%, increase the CO2 injection rate by 15-20%.

[0049] The preferred injection-to-production ratio is 1. When the CO2 utilization efficiency (increased hydrogen production / CO2 injection rate) is lower than expected, i.e., when the CO2 utilization efficiency (increased hydrogen production / CO2 injection rate) is lower than 0.5 m³, a further decrease is expected. 3 Hydrogen / m 3 When CO2 is present, reduce the injection-production ratio to 0.8; when the water intrusion rate is not effectively controlled, increase the injection-production ratio to 1.2.

[0050] Depend on Figure 2 It can be seen that the method of the present invention curbs the growth trend of water production and avoids it getting out of control.

[0051] (6) During the injection process, the CO2 content of the production well is continuously monitored. When the CO2 content in the production well reaches 10% of the hydrogen content, the injection is stopped.

[0052] This invention investigates the interaction mechanism of CO2, H2, and water molecules in dolomite nanopores using molecular dynamics simulations. Simulation results show that water and CO2 molecules are adsorbed onto the pore walls of the dolomite, while hydrogen molecules are distributed in the pore centers. The radial distribution function (RDF) values ​​between the rock-water and rock-CO2 pairs are the highest and relatively close, indicating that both water and CO2 molecules are adsorbed on the rock surface. The RDF between CO2 and water molecules follows closely, while the RDF values ​​between hydrogen molecules and other molecules are lower.

[0053] The evolution of interaction energies between different molecules shows that the interaction energies of rock-water and rock-CO2 pairs are negative, and the absolute values ​​increase as the simulation progresses, indicating that the attraction between these pairs is strengthening. In contrast, the interaction energy between rock and hydrogen molecules is smaller, indicating a weaker interaction. Initially, the interaction energy between water and CO2 molecules is negative, indicating mutual attraction. However, as the simulation progresses, this interaction weakens and eventually becomes positive.

[0054] Hydrogen bond kinetics analysis revealed that the number of hydrogen bonds between rock and water molecules increased over time, while the number of hydrogen bonds between CO2 and water molecules decreased. This indicates that CO2 adsorption on the dolomite surface disrupts the hydrogen bond network between water molecules, effectively inhibiting water intrusion by reducing the cohesive forces and mobility of water molecules. As the adsorption sites of CO2 molecules on the dolomite surface become dominant, the shift in molecular interactions leads to the formation of a CO2-rich adsorption layer, acting as a barrier against further water intrusion.

[0055] The interaction between CO2 and the rock surface is significantly stronger than that between H2 and the rock surface, highlighting the competitive adsorption advantage of CO2. This stronger interaction indicates a higher affinity of CO2 for the dolomite surface, allowing CO2 to displace previously adsorbed H2 molecules. This displacement enhances hydrogen mobility and promotes its flow to the production well, ultimately improving hydrogen recovery efficiency. This aligns with the application effects of this invention.

Claims

1. A method for CO2 injection to extract natural hydrogen reservoirs and for carbon sequestration, characterized in that, Includes the following steps: (1) Conduct characteristic analysis of the reservoir, including measuring reservoir depth, temperature, initial pressure, porosity, permeability, initial hydrogen saturation and water saturation, and establish a benchmark for the exploitation of natural hydrogen reservoir pressure depletion; start natural hydrogen production through pressure depletion method, and monitor reservoir pressure changes, hydrogen production and water production. (2) Determine the timing of CO2 injection: Injection should begin when a significant increase in water production is detected; (3) Determine the initial CO2 injection rate: The initial CO2 injection rate is 10%-25% of the daily hydrogen production; (4) Inject CO2 into the reservoir through the injection well according to the injection timing and initial injection volume determined in steps (2) and (3); (5) Maintain the injection-production ratio within the range of 0.8-1.2, continuously monitor hydrogen production, water production and CO2 breakthrough, and dynamically adjust the CO2 injection rate based on the monitoring results; (6) During the injection process, the CO2 content of the production well is continuously monitored. When the CO2 content in the production well reaches 10% of the hydrogen content, the injection is stopped.

2. The method for CO2 injection for natural hydrogen reservoir extraction and carbon sequestration according to claim 1, characterized in that, In step (2), the criteria for judging a significant increase in water production are: when the water-air ratio is continuously monitored to increase by more than 200% within 60 days, and the daily water production growth rate exceeds twice the average growth rate of the previous 30 days.

3. The method for CO2 injection extraction and carbon sequestration of natural hydrogen reservoirs according to claim 1, characterized in that, In step (3), for reservoirs with permeability in the range of 500-2000 mD, the initial injection rate is between 16% and 25% of the daily hydrogen production.

4. The method for CO2 injection for natural hydrogen reservoir extraction and carbon sequestration according to claim 1, characterized in that, In step (3), for reservoirs with permeability less than 500 mD and permeability less than 200 mD, the initial injection rate is 12-16% of the daily hydrogen production.

5. The method for CO2 injection extraction and carbon sequestration of natural hydrogen reservoirs according to claim 1, characterized in that, In step (3), for low-permeability reservoirs with permeability <200mD, the initial injection rate is 10%-12% of the daily hydrogen production.

6. The method for CO2 injection for natural hydrogen reservoir extraction and carbon sequestration according to claim 1, characterized in that, In step (4), the injection well is located between the aquifer and the gas zone.

7. The method for CO2 injection extraction and carbon sequestration of natural hydrogen reservoirs according to claim 1, characterized in that, In step (5), when the water-to-gas ratio continues to rise to more than 20% above the previous average, the CO2 injection rate is increased by 5-10%.

8. The method for CO2 injection extraction and carbon sequestration of natural hydrogen reservoirs according to claim 1, characterized in that, In step (5), when the CO2 content in the production well reaches 5%, the CO2 injection rate is reduced by 10-15%.

9. The method for CO2 injection for natural hydrogen reservoir extraction and carbon sequestration according to claim 1, characterized in that, In step (5), when the hydrogen production decreases by more than 10% and the CO2 content does not exceed 3%, the CO2 injection rate is increased by 15-20%.

10. The method for CO2 injection extraction and carbon sequestration of natural hydrogen reservoirs according to claim 1, characterized in that, In step (6), the injection-production ratio of CO2 and hydrogen is 1:1.

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