Method for exploiting natural hydrogen reservoir and carbon sequestration by injecting CO2

Abstract

The invention relates to the field of natural hydrogen exploitation and carbon sequestration, in particular to a method for natural hydrogen reservoir exploitation and carbon sequestration through CO2 injection. According to the method, the initial CO2 injection rate is optimized, CO2 is injected at a proper time according to stratum characteristics, the CO2 content of a production well is continuously monitored in the injection process, the injection rate is adjusted according to the gas-water ratio, the CO2 content and the like, water invasion can be effectively inhibited, and the hydrogen recovery rate is remarkably increased; and the recovery ratio of different stratums before and after injection can be increased by 20-40%. According to the invention, geological storage of CO2 can be realized, and environmental benefits of carbon emission reduction are provided.

Description

Technical Field

[0001] The present invention relates to the field of natural hydrogen exploitation and carbon sequestration, and in particular to a method for injecting CO2 to exploit natural hydrogen reservoirs and sequester carbon. Background Art

[0002] As the global energy transition toward low-carbon development progresses, hydrogen is gaining increasing attention as a clean energy carrier. Traditionally, hydrogen is produced primarily through water electrolysis or natural gas reforming, but the recent discovery of natural hydrogen reservoirs has provided new avenues for hydrogen energy development.

[0003] Natural hydrogen reservoirs, primarily formed through serpentinization—the hydration and oxidation of ultramafic rocks in the Earth's crust and upper mantle—represent a potentially vast and untapped energy resource. Pressure depletion exploits the reservoir's inherent pressure energy, requiring no additional fluid injection or energy to maintain reservoir pressure, resulting in relatively low extraction costs. Furthermore, this method is highly adaptable to various reservoir types, particularly those with low permeability and poor water injection response. Pressure depletion may be a more effective extraction method.

[0004] However, the development of natural hydrogen reservoirs faces a serious challenge: water intrusion during pressure depletion recovery. When reservoir pressure decreases, surrounding water invades the gas zone, reducing gas flow, 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 simultaneously controlling water intrusion. Therefore, there is an urgent need to develop a technical approach that can effectively address this issue while also considering environmental sustainability. Summary of the Invention

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

[0006] In order to achieve the above object, the present invention adopts the following technical solutions: A method for CO2 injection to exploit natural hydrogen reservoirs and carbon sequestration, comprising the following steps: (1) Analyze the reservoir characteristics, including measuring the reservoir depth, temperature, initial pressure, porosity, permeability, initial hydrogen saturation and water saturation, and establish a pressure depletion production benchmark for natural hydrogen reservoirs; start natural hydrogen production by the pressure depletion method, and monitor reservoir pressure changes, hydrogen production and water production; (2) Determine the timing of CO2 injection: start injection when the water production begins to increase significantly; (3) Determine the initial CO2 injection rate: The initial CO2 injection rate is 10%-25% of the daily hydrogen production; (4) Injecting 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 in the production well is continuously monitored. When the CO2 content in the production well reaches 10% of the hydrogen content, the injection is stopped.

[0007] Preferably, in step (2), the criterion for judging whether the water production has increased significantly is: when the water-gas ratio is continuously monitored to increase by more than 200% within 60 days (for example, from 0.1 cubic meters per 10,000 cubic meters to more than 0.3 cubic meters per 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.

[0008] Preferably, in step (3), for reservoirs with a 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 a permeability in the range of 200-500 mD (excluding 500), the initial injection rate is generally between 12 and 16% of the daily hydrogen production; and for low permeability reservoirs with a permeability <200 mD, the initial injection rate is 10% to 12% of the daily hydrogen production.

[0009] Preferably, the injection well in step (4) is located between the aquifer and the gas zone to maximize the CO2 displacement efficiency and mitigate water intrusion.

[0010] Preferably, in step (5), when the water-gas ratio continues to rise to more than 20% of the average value in the early stage (the time before the gas-water ratio rises significantly, that is, before this), the CO2 injection rate is increased by 5-10%; when the CO2 content in the production well reaches 5%, the injection rate is reduced by 10-15%; when the hydrogen production drops by more than 10% and the CO2 content does not exceed 3%, the injection rate is increased by 15-20%.

[0011] Preferably, the injection-production ratio of CO2 and hydrogen in step (6) is 1:1.

[0012] The CO2 injection of the present 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 is preferentially adsorbed on the dolomite surface, forming a CO2-rich barrier layer to block the migration of water molecules; the CO2 adsorption intensity is greater than that of H2, and it can replace the adsorbed hydrogen molecules and enhance their fluidity; a gas-liquid-solid multiphase synergistic effect is achieved: the gas-water interface properties and the rock surface properties are simultaneously regulated.

[0013] Beneficial effects of the present invention: (1) By injecting CO2 at the appropriate time, water intrusion can be effectively suppressed and the hydrogen recovery rate can be significantly improved; depending on the different formations, the recovery rate before and after injection can be increased by 20-40%.

[0014] (2) After CO2 is mixed with hydrogen, the air-water interfacial tension is reduced, the capillary resistance is reduced, and water intrusion is further slowed down; (3) CO2 preferentially adsorbs on the rock surface, forming a CO2-rich adsorption layer that acts as a barrier to water intrusion; (4) Achieve geological storage of CO2 and provide environmental benefits of carbon emission reduction; (5) By optimizing the injection rate and timing, a balance between hydrogen recovery and CO2 storage can be achieved to maximize economic and environmental benefits. BRIEF DESCRIPTION OF THE DRAWINGS

[0015] Figure 1 This is the relationship between hydrogen recovery rate and average reservoir pressure in different mining processes; Figure 2 This is a comparison chart of water production changes before and after CO2 injection; Figure 3 Comparison of cumulative hydrogen production at different CO2 injection rates; Figure 4 This is a comparison chart of hydrogen recovery rate and CO2 storage capacity at different CO2 injection timings. DETAILED DESCRIPTION

[0016] The present invention will be further described in detail below with reference to specific embodiments.

[0017] In this example, the natural hydrogen reservoir is 250 meters deep, the temperature is 100°C, the initial pressure is 30 MPa, the porosity is 0.3, the permeability is 1000 mD, the hydrogen saturation is 50%, and the water saturation is 50% under the initial conditions. Figure 1 Schematic diagram of the process for CO2 mining from natural hydrogen reservoirs and carbon sequestration.

[0018] (1) Establish a natural hydrogen reservoir pressure depletion mining benchmark, start natural hydrogen production through the pressure depletion method, and monitor reservoir pressure changes, hydrogen production, and water production.

[0019] In the early stages of production, hydrogen production stabilized at approximately 100,000 m 3 / d, with almost no water production, indicating that the reservoir pressure is high enough to effectively promote hydrogen production while limiting water intrusion. As production progresses, water production and water intrusion gradually increase, accompanied by a slow decline in reservoir pressure.

[0020] (2) Determine the timing of CO2 injection: After about 1,500 days of production, water production and water invasion volume increased significantly. At this time, the reservoir pressure dropped rapidly, and CO2 injection was required to improve the recovery rate.

[0021] According to the results of reservoir numerical simulation, Figure 4 The CO2 injection time is different (when optimizing the injection time, the initial CO2 injection volume is 20,000 m 3 / d) of hydrogen recovery rate and CO2 storage capacity. Figure 4 It can be seen that premature injection (for example, at 1,600 or 1,800 days) wastes CO2 and results in poor results due to a short breakthrough time. While early CO2 injection suppresses water intrusion, it also reduces hydrogen production. Injection too late, on the other hand, makes it difficult to reverse the already formed severe water intrusion pathways. By 2,200 days, water saturation has increased to a level that completely halts hydrogen production. The optimal effect was achieved when CO2 injection began on day 1,980 of pressure depletion production. At this point, the reservoir pressure dropped to 7.41 MPa, and the water-gas ratio increased from an initial 0.05 cubic meters per 10,000 cubic meters to 0.26 cubic meters per 10,000 cubic meters, an increase of over 500%. Daily water production exceeded the production well's designed drainage capacity (1,000 cubic meters per day) by 30%, reaching 1,300 cubic meters per day.

[0022] Based on the results of reservoir numerical simulation verification, the timing of CO2 injection is determined as follows: when water production increases significantly, that is, 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, CO2 injection is started.

[0023] At this point, reservoir pressure rapidly decreased, exceeding 0.5 MPa / month, more than three times the average pressure drop rate (0.15 MPa / month) in the previous period. This indicated that the reservoir was about to enter a phase of uncontrolled water intrusion. Without intervention, a large amount of hydrogen would be trapped in the flooded area and unable to be extracted.

[0024] At this time, injecting CO2 can effectively control water invasion in the initial acceleration stage of water invasion and achieve the best recovery rate improvement effect.

[0025] (3) Determine the initial CO2 injection rate: Based on reservoir numerical simulation, the effects of different initial CO2 injection rates on hydrogen recovery, water invasion inhibition and CO2 storage were evaluated. Figure 3 Comparison of cumulative hydrogen production at different CO2 injection rates. Figure 3 It can be seen that a lower initial injection rate (such as 10,000 m 3 / d) was not enough to prevent water intrusion, which resulted in continued water intrusion. 3 / d and above), excessive initial CO2 injection rate begins to have a negative impact on hydrogen production. 3 / d, the CO2 production rate remained at the lowest level, indicating the best retention of CO2 in the reservoir. When the initial injection rate increased to 30,000 m 3 / d and above, the CO2 production rate increases significantly, indicating that excess CO2 begins to break through rather than being effectively used to control water intrusion or CO2 storage.

[0026] Through reservoir numerical simulation, this example selects 20,000 m 3 The initial CO2 injection rate of / d (at this time the injection rate is 20% of the daily hydrogen production) can achieve the highest hydrogen production.

[0027] The results show that for different reservoir conditions, the initial injection rate should be determined according to the following principles: for reservoirs with a 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 a permeability of 200-500 mD (excluding 500 mD), the initial injection rate is usually between 12% and 16% of the daily hydrogen production; for low permeability reservoirs (permeability <200 mD), the initial injection rate is between 10% and 12% of the daily hydrogen production.

[0028] (4) CO2 injection On the 1,980th day of hydrogen production, the initial injection rate of 20,000 m was determined in step (3). 3 At this point, severe water invasion has significantly reduced hydrogen production. The results show that CO2 injection effectively inhibits water invasion and enhances hydrogen recovery.

[0029] Depend on Figure 1 It can be seen that after CO2 injection, the recovery rate increased from 45% to more than 65%, an increase of 20%.

[0030] (5) Continuously monitor various parameters and dynamically adjust injection parameters 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% of the previous average value, increase the CO2 injection rate by 5-10% on the basis of the initial injection rate; when the CO2 content in the production well reaches 5%, reduce the CO2 injection rate by 10-15%; when the daily hydrogen production drops by more than 10% compared with the previous day and the CO2 content does not exceed 3%, increase the CO2 injection rate by 15-20%.

[0031] The preferred injection-production ratio is 1. When the CO2 utilization efficiency (increased hydrogen production / CO2 injection volume) is lower than expected, that is, when the CO2 utilization efficiency (increased hydrogen production / CO2 injection volume) is lower than 0.5 m 3 Hydrogen / m 3 When CO2 is high, the injection-production ratio is reduced to 0.8; when the water invasion rate is not effectively controlled, the injection-production ratio is increased to 1.2.

[0032] Depend on Figure 2 It can be seen that the method of the present invention curbs the growth trend of water production and avoids loss of control.

[0033] (6) During the injection process, the CO2 content in the production well is continuously monitored. When the CO2 content in the production well reaches 10% of the hydrogen content, the injection is stopped.

[0034] This study used molecular dynamics simulations to investigate the interaction mechanisms among CO2, H2, and water molecules in dolomite nanopores. The simulation results show that water and CO2 molecules are adsorbed on the dolomite pore walls, 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 is closely followed, while the RDF between hydrogen and other molecules is relatively low.

[0035] The evolution of the interaction energies between different molecules shows that the interaction energies for rock-water and rock-CO₂ pairs are negative and increase in absolute value as the simulation progresses, indicating a growing attraction between these pairs. 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, eventually becoming positive.

[0036] Hydrogen bond dynamics 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 suggests that CO2 adsorption on the dolomite surface disrupts the hydrogen bond network between water molecules, effectively inhibiting water intrusion by reducing the cohesion and mobility of water molecules. As CO2 molecules dominate the adsorption sites on the dolomite surface, this shift in molecular interactions leads to the formation of a CO2-rich adsorption layer, which acts as a barrier to further water intrusion.

[0037] The interaction between CO2 and the rock surface is significantly stronger than that between H2 and the rock surface, highlighting CO2's competitive adsorption advantage. This stronger interaction indicates CO2's higher affinity for the dolomite surface, allowing CO2 to displace previously adsorbed H2 molecules. This displacement enhances hydrogen mobility and promotes its flow to production wells, ultimately improving hydrogen recovery efficiency. This is consistent with the application effects of the present invention.

Claims

1. A method for CO2 injection to exploit natural hydrogen reservoirs and carbon sequestration, characterized in that: The following steps are involved: (1) Analyze the reservoir characteristics, including measuring the reservoir depth, temperature, initial pressure, porosity, permeability, initial hydrogen saturation and water saturation, and establish a pressure depletion production benchmark for natural hydrogen reservoirs; start natural hydrogen production by the pressure depletion method, and monitor reservoir pressure changes, hydrogen production and water production; (2) Determine the timing of CO2 injection: start injection when the water production begins to increase significantly; (3) Determine the initial CO2 injection rate: The initial CO2 injection rate is 10%-25% of the daily hydrogen production; (4) Injecting 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 in 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 to exploit natural hydrogen reservoirs and carbon sequestration according to claim 1, characterized in that: In step (2), the criterion for judging whether water production has increased significantly is: when the water-gas 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 to exploit natural hydrogen reservoirs and carbon sequestration according to claim 1, characterized in that: In step (3), for reservoirs with permeabilities 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 to exploit natural hydrogen reservoirs and carbon sequestration according to claim 1, characterized in that: For reservoirs with a permeability of 200-500mD (excluding 500), the initial injection rate is 12-16% of the daily hydrogen production.

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

8. The method for CO2 injection to exploit natural hydrogen reservoirs and carbon sequestration 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 to exploit natural hydrogen reservoirs and carbon sequestration according to claim 1, characterized in that: In step (5), when the hydrogen production drops 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 to exploit natural hydrogen reservoirs and carbon sequestration according to claim 1, characterized in that: The injection-production ratio of CO2 and hydrogen in step (6) is 1:1.

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