A method for enhancing hydrate production and carbon dioxide storage through dual horizontal well injection-production coupling

Abstract

The present invention discloses a method for enhancing hydrate production and carbon dioxide storage through dual-horizontal well injection-production coupling, comprising: measuring and confirming target reservoir characteristic data, laying production wells and injection wells at different reservoir depths or in different saturation areas; reducing the reservoir pressure to a set bottom hole pressure through the production well to carry out production; alternately injecting flue gas and a kinetic promoter solution, and controlling the injection rate to maintain the temperature and pressure near the injection well below the methane hydrate phase equilibrium line, displacing natural gas in the pores and stimulating hydrate decomposition; producing to the lower limit of the hydrate saturation for reservoir mechanical safety, and shutting down the production well; if the lower limit is not reached, monitoring the output composition, and shutting down the production well and stopping the alternating injection when a serious CO2 breakthrough occurs or the methane content in the produced gas is lower than a preset lower limit; injecting CO2-rich flue gas or liquid CO2 through the injection well to restore the reservoir pressure to the pre-production pressure, generating a mixed hydrate to solid-state seal CO2, and repairing the reservoir sediment skeleton.

Description

Technical Field

[0001] The present invention relates to the field of natural gas hydrate exploitation, and in particular to a method for enhancing hydrate exploitation and carbon dioxide sequestration through dual-horizontal well injection-production coupling. Background Art

[0002] Natural gas hydrates are unconventional natural gas reservoirs buried in seafloor sediments around continental margins. Due to their widespread distribution, low pollution, and high energy density, they are considered one of the most promising alternative clean energy sources. Over the past decades, researchers have proposed various methods for gas hydrate extraction, including pressure reduction, heat injection, inhibitor injection, CO2 displacement, and solid-state fluidization. However, current research suggests that the efficiency of gas hydrate extraction using these conventional methods is too low, with daily / annual gas production still significantly below industrial and commercial standards. Furthermore, gas hydrate extraction involves melting the sediment pore framework (hydrates), which raises uncertainties regarding the mechanical safety of the extraction process.

[0003] Depressurization is considered the most efficient and feasible method for gas hydrate production and has been the primary approach used in several previous hydrate recovery trials. However, its efficiency is still limited by two key factors: low permeability and slow heat replenishment. Furthermore, the depressurization process is prone to sand production, leading to cessation of gas production, and melting of the sediment pore structure, resulting in formation instability and damage. Natural gas hydrates often produce rapidly during the initial depressurization phase, but these factors lead to a rapid decline in production later in the process.

[0004] Heat injection involves injecting hot fluids into the hydrate reservoir, or using downhole electromagnetic and microwave heating methods, to directly decompose the hydrates and produce gas. The advantage of this method is that it can manipulate the reservoir's ambient temperature to control hydrate production. However, its disadvantages include significant heat losses, high production costs, and severe sand and water production.

[0005] The inhibitor injection method involves adding hydrate inhibitors to disrupt the physical and chemical equilibrium of hydrates, thereby destabilizing and decomposing them. However, this method consumes expensive chemical reagents, is difficult to recover, and poses a risk of marine ecological pollution.

[0006] The CO2 displacement method involves injecting CO2 gas into a hydrate reservoir to displace methane from the hydrate cages. Its advantages include simultaneous hydrate extraction and CO2 geological storage, without decomposing the hydrates or damaging the sedimentary framework during extraction. However, the CO2 displacement method's low extraction efficiency makes its extraction efficiency far lower than the other three methods mentioned above, making it economically unfeasible. Summary of the Invention

[0007] To this end, the present invention proposes a method for enhancing hydrate production and carbon dioxide storage through dual horizontal well injection-production coupling to alleviate and solve the economic and safety issues in the above-mentioned hydrate production method.

[0008] The technical solutions proposed by the present invention are as follows:

[0009] A method for enhancing hydrate production and carbon dioxide storage by coupling injection and production with dual horizontal wells, comprising the following steps: S1, laying production wells and injection wells at different reservoir depths or in different saturation areas based on pre-measured target reservoir characteristic data; S2, depressurizing the reservoir through the production well to a set bottom hole pressure, and recovering natural gas; S3, alternately injecting flue gas and a kinetic promoter solution through the injection well, and controlling the injection rate to maintain the temperature and pressure near the injection well below the natural gas hydrate phase equilibrium line, displacing the natural gas in the pores and Stimulate the decomposition of natural gas hydrates; S4, extract through the production well to the lower limit of the hydrate saturation of the mechanical safety of the reservoir, and shut down the production well; if the lower limit of the hydrate saturation of the mechanical safety of the reservoir is not reached, monitor the output composition through the production well, when CO2 breakthrough occurs and exceeds the preset upper limit, or the methane content in the produced gas is lower than the preset lower limit, shut down the production well and stop the alternating injection; S5, inject CO2-rich flue gas or liquid CO2 through the injection well to restore the reservoir pressure to the pressure before extraction, generate mixed hydrates to seal CO2 in the solid state, and repair the reservoir sediment skeleton.

[0010] Compared with the existing technology, the beneficial effects of the above technical solution of the present invention are reflected in: the present invention uses dual horizontal wells to systematically carry out integrated and continuous natural gas extraction and CO2 injection and storage in the natural gas hydrate reservoir, so that the hydrate extraction, carbon storage and geological remediation technologies are coupled and strengthened with each other, thereby enhancing the natural gas hydrate decomposition efficiency, natural gas recovery rate and CO2 storage efficiency, and improving the reservoir and ecological safety during and after the extraction process.

[0011] Furthermore, the target reservoir characteristic data in step S1 include: temperature, pressure, phase saturation distribution and spatial occurrence characteristics of the target reservoir at different depths, wherein the phase saturation distribution includes hydrate saturation, gas saturation and water saturation at different depths.

[0012] Furthermore, step S1 lays the production well and the injection well at different reservoir depths or different saturation areas, specifically including: laying the production well in the upper reservoir area with higher hydrate saturation, and laying the injection well in the lower reservoir area with lower hydrate saturation, so as to improve the production efficiency; or laying the production well in the lower reservoir area with lower hydrate saturation, and laying the injection well in the upper reservoir area with higher hydrate saturation, so as to improve the CO2 storage efficiency. Natural gas hydrate deposits have the characteristic that the saturation or abundance of natural gas hydrates is higher in the upper part of the reservoir and lower in the lower part. This is a reservoir-forming characteristic determined by the geothermal gradient of the formation. For this reason, in this further technical solution, the production wells are laid in the upper area of ​​the reservoir and the injection wells are laid in the lower area of ​​the reservoir. This "upper production and lower injection" well layout is beneficial to the decompression and decomposition of natural gas hydrates and the improvement of production efficiency; while the production wells are laid in the lower area of ​​the reservoir and the injection wells are laid in the upper area of ​​the reservoir. This "lower production and upper injection" well layout is beneficial to accelerate the migration of gas and liquid and the discharge of pore water in the reservoir, which is beneficial to the subsequent generation of mixed hydrates and the improvement of CO2 storage efficiency.

[0013] Furthermore, in step S2, the production well is depressurized to a bottom hole flow pressure of 5 MPa to 7 MPa.

[0014] Furthermore, in step S2, the reservoir is depressurized through the production wells to drain the pore water within the reservoir, leaving pore space for the subsequent alternating injection and CO2 storage, as well as space for the growth of mixed hydrates. In this further technical solution, depressurizing the production wells not only produces natural gas, but also extracts and drains the pore water within the reservoir. Reducing water saturation leaves pore space for the subsequent alternating injection in step S3 and CO2 storage in step S5, and also leaves space for the growth of mixed hydrates in step S5.

[0015] Furthermore, in step S3, when the injection well monitoring equipment detects that the pressure reduction has spread to the vicinity of the injection well and is lower than the phase equilibrium pressure, the pressure reduction production continues, and flue gas and kinetic promoter solution are alternately injected into the injection well to drive the decomposed natural gas and the original free natural gas in the pores toward the production well, thereby improving the natural gas recovery rate and delaying CO2 breakthrough.

[0016] Furthermore, the flue gas in step S3 comprises 8%-15% CO2 gas and 85%-92% nitrogen by mole fraction; the kinetic promoter solution is a 1wt% mixed solution of sodium dodecyl sulfate and sodium dodecylbenzene sulfonate; the injected flue gas and kinetic promoter solution stimulate the decomposition of natural gas hydrates, thereby increasing the natural gas recovery rate. In this further technical solution, sodium dodecyl sulfate and sodium dodecylbenzene sulfonate have the dual functions of a foaming agent and a hydrate kinetic promoter. As a foaming agent, they achieve foam drainage gas recovery, improve the recovery rate, and delay CO2 breakthrough; and as kinetic promoters, they create favorable conditions for the formation of mixed hydrates after the CO2 injection in the subsequent step S5.

[0017] Furthermore, in step S5, if CO2-rich flue gas containing CO2 gas and nitrogen with a CO2 mole fraction greater than 75% is injected, the mixed hydrate generated is CH4 / CO2 / N2 mixed hydrate; if liquid CO2 is injected, the mixed hydrate generated is CH4 / CO2 mixed hydrate.

[0018] Furthermore, in step S5, the type of injected CO2-rich flue gas or liquid CO2 is related to the temperature and pressure conditions at different depths of the reservoir. By adjusting the ratio of CO2 to N2 in the CO2-rich flue gas, the phase equilibrium of CH4 / CO2 / N2 mixed hydrate or CH4 / CO2 mixed hydrate is controlled to be under conditions suitable for hydrate formation and growth.

[0019] Furthermore, the method further includes the following step: S6, during the process of injecting CO2-rich flue gas or liquid CO2, real-time monitoring of reservoir characteristic data is performed, and CO2-rich flue gas or liquid CO2 is injected multiple times in multiple stages to replenish pressure, and each well is sealed after the data tends to be stable. BRIEF DESCRIPTION OF THE DRAWINGS

[0020] Figure 1 This is a flow chart of a method for enhancing hydrate production and carbon dioxide storage through dual horizontal well injection-production coupling according to an embodiment of the present invention.

[0021] Figure 2 This is a schematic diagram of laying out a production well in the upper portion of a reservoir and an injection well in the lower portion of the reservoir according to target reservoir characteristic data in an embodiment of the present invention.

[0022] Figure 3 It is a pressure evolution curve of the production-injection-displacement-storage process simulated in a pilot-scale hydrate reactor according to an embodiment of the present invention.

[0023] Figure 4 This is a comparison diagram of reservoir settlement / expansion displacement caused by pilot-scale production and complete depressurization production in an embodiment of the present invention.

[0024] Figure 5This is a schematic diagram of an embodiment of the present invention in which an injection well is laid in the upper part of the reservoir and a production well is laid in the lower part of the reservoir according to target reservoir characteristic data.

[0025] Figure 6 This is a comparison of the methane recovery ratio and recovery rate of Example 1 and Example 2 compared with conventional pressure reduction mining.

[0026] Figure 7 This is a schematic diagram of an exemplary dual-horizontal well installation according to the present invention. DETAILED DESCRIPTION

[0027] The present invention will be further described below with reference to the accompanying drawings and specific embodiments.

[0028] The present invention proposes a method for enhancing hydrate production and carbon dioxide storage by coupling injection and production with dual horizontal wells. This method simultaneously achieves natural gas production, carbon storage and geological remediation. Figure 1 , the method comprises the following steps:

[0029] Step 1: Select the target hydrate reservoir for exploration. Then, measure and confirm the temperature, pressure, phase saturation distribution, and spatial distribution characteristics of the target hydrate reservoir area. Parameters for exploration / displacement, storage, and reservoir remediation are then developed. Specifically, hydrate saturation, gas saturation, and water saturation at various depths in the target reservoir are measured, as well as temperature and pressure at various depths. This data is used to formulate subsequent strategies for bottomhole pressure, injected gas composition, injected gas phase, and injection rate.

[0030] In a preferred embodiment, the selected natural gas hydrate reservoir should have a high hydrate abundance (natural gas hydrate saturation greater than 30%), preferably in areas of hydrate sediments with high gas saturation (preferably greater than 30%) and low water saturation (preferably less than 40%). Furthermore, the selected natural gas hydrate reservoir should have well-sealed boundaries, a low number of historical earthquakes, and low seismic intensity.

[0031] Step 2: Drilling. After drilling, the production well and injection well are laid out at different reservoir depths or different saturation areas according to the reservoir characteristic data measured and confirmed in step 1. Based on the research results of the present invention, a well layout scheme for hydrate reservoir production and storage is provided to achieve different technical goals. Specifically, the production well can be laid out in the upper part of the reservoir with higher hydrate saturation, and the injection well can be laid out in the lower part of the reservoir with lower hydrate saturation, such as Figure 2 As shown in , this “upper production and lower injection” well layout method is conducive to improving production efficiency; alternatively, the production wells can be laid in the lower reservoir with lower hydrate saturation, while the injection wells can be laid in the upper reservoir with higher hydrate saturation, as shown in Figure 5As shown in the figure, this "downward mining and upward injection" well layout method is conducive to improving the CO2 storage efficiency.

[0032] At present, the hot hydrate deposits studied and tested in the industry all have the characteristics of higher natural gas hydrate saturation or abundance in the upper part of the reservoir and lower in the lower part. This is a reservoir-forming characteristic determined by the geothermal gradient of the formation. For this reason, the embodiment of the present invention lays the production wells in the upper area of ​​the reservoir and the injection wells in the lower area of ​​the reservoir. The "upper production and lower injection" well layout is conducive to the decompression and decomposition of hydrates and the improvement of production efficiency. If the production wells are laid in the lower area of ​​the reservoir and the injection wells are laid in the upper area of ​​the reservoir, the "lower production and upper injection" well layout is conducive to accelerating the migration of gas and liquid and the discharge of pore water in the reservoir, which is conducive to the subsequent generation of mixed hydrates and the improvement of CO2 storage efficiency.

[0033] In some exemplary embodiments, the distance between the production well and the injection well is 60 to 200 meters, and the two horizontal wells are laid in parallel. The slope formed by the two horizontal wells is inclined with respect to the reservoir thickness, and the angle formed by the slope with respect to the reservoir thickness is less than 90 degrees. However, this is merely exemplary and does not imply that the dual horizontal wells of the present invention can only be arranged in this manner and with this parameter. The present invention should not be limited to this example.

[0034] Step 3: Depressurize the reservoir through the production well to the set bottomhole pressure for natural gas recovery. In this step, the reservoir is depressurized through the production well to drain pore water, leaving pore space for subsequent alternating injection and CO2 storage, as well as space for mixed hydrate growth. In a preferred embodiment, the production well is depressurized to a bottomhole flowing pressure of 5 MPa to 7 MPa.

[0035] Step 4: Alternately inject flue gas and kinetic promoter solution through the injection well, and control the injection rate to maintain the temperature and pressure near the injection well below the natural gas hydrate phase equilibrium line, displacing the natural gas in the pores and stimulating the decomposition of natural gas hydrates.

[0036] Specifically, when the injection well monitoring equipment detects a pressure drop near the injection well and below the equilibrium pressure, depressurized production continues, and flue gas and a kinetic accelerator solution are alternately injected into the injection well (referred to as "alternating water-gas injection") to drive decomposed natural gas and existing free natural gas in the pores toward the production well, improving natural gas recovery and delaying CO2 breakthrough. In this alternating water-gas injection step, the flue gas is a mixture of CO2 and N2, with a molar fraction of 8%-15% CO2 and 85%-92% nitrogen. The kinetic accelerator solution is a 1wt% mixed solution of sodium dodecyl sulfate and sodium dodecylbenzene sulfonate.

[0037] In this step, the alternating water and gas injection rate is controlled to maintain the temperature and pressure near the injection well below the methane hydrate phase equilibrium line. At this time, the three factors of pressure reduction (changing the methane hydrate phase equilibrium), flue gas stimulation (reducing the methane partial pressure in the sediment environment), and water erosion (increasing the fugacity difference) simultaneously stimulate the decomposition of methane hydrates, synergistically improving the hydrate decomposition efficiency and mining efficiency. The gas and liquid components of the alternating water and gas injection are laid in the porous flow channels of the mining and displacement process in the hydrate decomposition area, increasing the range of CO2 and kinetic promoters, and completing the preparation work for the subsequent large-scale injection and storage of CO2 and the production of mixed hydrates.

[0038] Step 5: During the mining process, when the lower limit of the hydrate saturation for mechanical safety of the reservoir is reached, the mining well is shut down to prevent severe deformation or collapse. 80% of the hydrates in the sediments with a hydrate saturation of 65% do not experience severe collapse after decomposition. This method of mechanical state control and early warning of specific hydrate sediments will ensure that hydrate decomposition and mining are completed to the maximum extent possible while ensuring safety. If the lower limit of the hydrate saturation for mechanical safety of the reservoir is not reached, the output composition is monitored through the mining well. When a severe CO2 breakthrough occurs (for example, exceeding a preset upper limit) or the methane content in the produced gas falls below a preset lower limit (no longer economically viable for mining), the mining well is shut down and the alternating water and gas injection is stopped.

[0039] Step 6: Inject CO2-rich flue gas or liquid CO2 at high pressure through the injection well to restore the reservoir pressure to the pressure before mining, generate mixed hydrates to store CO2 in a solid state, and repair the reservoir sediment skeleton. During this process, monitor the reservoir characteristic data, timely inject CO2-rich flue gas or liquid CO2 multiple times to replenish the pressure, and after the data tends to be stable, seal each well. The multi-stage injection of CO2-rich flue gas or liquid CO2 will discharge the N2 (92%) in the originally injected N2-rich flue gas out of the hydrate reservoir area, prevent the inhibitory N2 from threatening the stability of the formed mixed hydrate, and increase the CO2 storage capacity.

[0040] In this step, the carbon dioxide injected for storage can be a CO2-rich flue gas containing CO2 gas and nitrogen with a CO2 mole fraction greater than 75%, or it can be liquid CO2. Accordingly, the mixed hydrate generated is a CH4 / CO2 / N2 mixed hydrate or a CH4 / CO2 mixed hydrate. Mixed hydrates are generated to repair the sediment skeleton and restore the mechanical properties of the reservoir. The type of injected CO2-rich flue gas or liquid CO2 is related to the temperature and pressure conditions at different depths of the reservoir. By adjusting the ratio of CO2 to N2 in the CO2-rich flue gas, the phase equilibrium of CH4 / CO2 / N2 mixed hydrate or CH4 / CO2 mixed hydrate is controlled to be under conditions suitable for hydrate formation and growth. For the lower temperature area in the upper part of the reservoir, liquid CO2 can be injected without hydrate blockage to improve the efficiency of injection storage and mixed hydrate generation. In the higher temperature region (>11°C to 15°C) in the lower reservoir, liquid CO₂ cannot reach the equilibrium pressure for hydrate formation at reservoir pressure, even in the presence of methane, and is therefore not suitable. By injecting a CO₂ / N₂ mixture with a reasonable composition (e.g., CO₂ / N₂ = 82 / 18) in the presence of N₂, the equilibrium pressure can be lowered, allowing mixed hydrate formation.

[0041] In addition, in step 6, a low-dose kinetic inhibitor (PVP-15, luvicap EG, etc.) that inhibits hydrate nucleation can be injected to prevent mixed hydrates from forming blockages during the injection process. By regulating the injection concentration and the evolved concentration after injection (concentration effect), hydrate nucleation and blockage can be suppressed in the injection pipeline.

[0042] The effectiveness of the method of the present invention is verified by two specific examples below.

[0043] Example 1

[0044] This embodiment provides a method for enhancing hydrate production and CO2 storage through dual horizontal well injection and production coupling. The steps are as follows: The hydrate reservoir selected is the SHSC-4 reservoir in the Shenhu area of ​​the South China Sea, the first hydrate production trial area in China in 2017. The reservoir has a water depth of 1266m, 201-251mbsf, a top temperature of 12.89°C and a pressure of 14.72MPa, a bottom temperature of 14.53°C and a pressure of 15.07MPa, and an average hydrate saturation of 31%. Figure 2 As shown, a horizontal production well 1 is laid in the upper portion of the hydrate reservoir area 15 (220 mbsf), and a horizontal injection well 2 is laid in the lower portion of the storage area (250 mbsf), with a well spacing of 60 meters. Temperature, pressure, and displacement sensors are used to monitor the hydrate reservoir area in real time. Figure 3The following is a pressure evolution curve for the production-injection-displacement-storage process simulated in a pilot-scale hydrate reactor using this method. An electric submersible pump (ESP) was activated to depressurize the reservoir for gas production and dewatering, with the outlet pressure (i.e., the desired bottomhole pressure) set at 5 MPa. Subsequently, pressure propagation gradually occurred within the reservoir. When the pressure reduction reached the injection well and dropped below 12.0 MPa (the methane hydrate equilibrium pressure corresponding to the reservoir temperature at the injection well), injection horizontal well 2 was opened to alternately inject flue gas (CO₂ / N₂ = 13% / 87%, hydrate equilibrium pressure 41.3 MPa to 51.4 MPa) and a kinetic enhancer solution (sodium dodecyl sulfate, 1.0 wt%). Continuous pumping through the production horizontal well reduced the reservoir pressure to 5 MPa. The maximum bottomhole flowing pressure in injection horizontal well 2 was 12.0 MPa. The water-gas slug volume ratio was 1:2, and the injection cycle was 0.005 HCPV. The injection rate and intensity were designed to ensure that the bottomhole temperature and pressure conditions remained below the methane hydrate equilibrium. In the above-mentioned depressurization-displacement process, flue gas stimulation and water flow erosion decompose hydrates, assisting depressurization production to enhance the efficiency of hydrate decomposition and inhibit the occurrence of secondary hydrate formation in the reservoir. Alternating water and gas injection displaces free methane in the pores and the methane produced after decomposition to migrate to the production well to improve the recovery rate, and completes the laying of CO2-containing flue gas and kinetic promoters in the depleted hydrate reservoir. When 80% of the hydrates in the mining area are decomposed, that is, when the average hydrate saturation reaches 6%, the depressurization extraction and water and gas alternating injection process are stopped, such as Figure 4 In the pilot-scale experiment shown, the reservoir did not experience significant subsidence at this level of exploitation, while complete exploitation caused severe subsidence. CO2-rich flue gas (CO2 / N2=80% / 20%) was injected through horizontal well 2 to increase the bottomhole flow pressure to the original reservoir pressure until the pressure in the depressurized exploitation area was fully restored to the level before exploitation. At this time, there is a mixed gas component (CH4 / CO2 / N2) suitable for the formation of mixed hydrates in the gas phase space of the exploitation area. Under the induction of the pore water memory effect, kinetic promoters and residual methane hydrates, the mixed gas completes nucleation and gradual growth. The mixed hydrate gradually fills the reservoir pores, reconstructs the sediment skeleton, and repairs the mechanical properties of the reservoir. The CO2 in the flue gas injected in the two stages is preferentially enriched and captured by the mixed hydrate, and the greenhouse gas CO2 is stored in a hydrated solid state on the seabed. As shown Figure 4In the pilot-scale experiment shown, the sediment pores expanded after filling, demonstrating the effectiveness of the geological remediation process. The formation of mixed hydrates consumes the inter-pore gas phase, causing a drop in reservoir pressure. At this point, liquid CO2 is injected multiple times through horizontal wells to supplement and increase reservoir pressure. The liquid CO2 injection process displaces the remaining N2 in the flue gas out of the hydrate reservoir, or reduces the N2 component in the gas phase, preventing the inhibitory N2 from threatening the thermodynamic stability of the mixed hydrates. The injected liquid CO2 further increases the CO2 storage capacity of the reservoir, and the formed mixed hydrates are trapped within the pores of the reservoir sediment, inhibiting their potential leakage or diffusion. The horizontal injection well is closed, and the technical process of coupling dual horizontal well injection and production to enhance hydrate recovery and carbon dioxide storage is completed.

[0045] Example 2

[0046] like Figure 5As shown, an injection horizontal well 2 is laid in the upper portion of the hydrate reservoir region 15 (220 mbsf), and a production horizontal well 1 is laid in the lower portion of the storage region (250 mbsf), with a well spacing of 60 m. Temperature, pressure, and displacement sensors are activated to monitor the hydrate reservoir in real time. An electric submersible pump is activated to depressurize the reservoir for gas production and dewatering, with the outlet pressure (i.e., the desired bottomhole pressure) set at 5 MPa. Subsequently, pressure gradually propagates within the reservoir. When the pressure reduction reaches the vicinity of injection horizontal well 2 and drops below 10.0 MPa (the methane hydrate equilibrium pressure corresponding to the reservoir temperature at the injection well), injection horizontal well 2 is opened to alternately inject flue gas (CO2 / N2 = 8% / 92%, hydrate equilibrium pressure 46.86 MPa to 56.94 MPa) and a kinetic enhancer solution (sodium lauryl sulfate, 1.0 wt%). Continuous pumping in production horizontal well 1 reduces the reservoir pressure to 5 MPa. Injection horizontal well 2 achieves a maximum bottomhole flowing pressure of 10.0 MPa. The water-gas slug volume ratio is 1:2, and the injection cycle is 0.005 HCPV. The injection rate and intensity are designed to ensure that bottomhole temperature and pressure conditions are below the methane hydrate phase equilibrium. During this depressurization-displacement process, flue gas stimulates hydrate decomposition and water erosion erodes hydrates, assisting depressurization production to enhance hydrate decomposition efficiency and suppress secondary hydrate formation within the reservoir. Alternating water-gas injection displaces free methane in the pores and the resulting methane from decomposition, migrating toward the production well to enhance recovery and complete the deployment of CO2-containing flue gas and kinetic accelerators within the depleted hydrate reservoir. Depressurization and alternating water-gas injection are terminated when 80% of the hydrates in the production area have decomposed, i.e., when the average hydrate saturation reaches 6%. By injecting CO2-rich flue gas (CO2 / N2=80% / 20%) through horizontal well 2, the bottomhole pressure is increased to the original reservoir pressure until the pressure in the depressurized production area is fully restored to the level before production. At this time, the gas phase space in the production area contains a mixed gas component (CH4 / CO2 / N2) suitable for the formation of mixed hydrates. The mixed gas hydrates are generated to fill the reservoir pores, repair the mechanical properties of the reservoir, and achieve hydrated solid storage of greenhouse gas CO2 on the seabed. Figure 4 In the pilot-scale experiments shown, the sediment pores filled and expanded, demonstrating the effectiveness of the georemediation process. Hydrate formation consumes the inter-pore gas phase, causing a drop in reservoir pressure. This pressure was then supplemented by multiple injections of liquid CO2 through horizontal wells. The liquid CO2 injection process displaced the remaining N2 in the flue gas out of the hydrate reservoir, or reduced the N2 content in the gas phase. The injected liquid CO2 further increased the CO2 storage capacity of the reservoir. Injection well 2 was closed, completing the technical process.

[0047] Figure 6The comparison of methane recovery rate and recovery rate of Example 1 and Example 2 compared with conventional depressurization mining is shown. Example 1 (upper mining and lower injection) increased the methane recovery rate and recovery rate by 22.7% and 47.2%, respectively. Example 2 (lower mining and upper injection) increased the methane recovery rate and recovery rate by 18.8% and 22.4%, respectively. The mixed hydrate production in Example 2 (lower mining and upper injection) during the CO2 storage and geological remediation stage was 12.6% higher than that in Example 1 (upper mining and lower injection). The difference between the two examples is that depressurization mining in the low methane hydrate saturation area in the lower part of the reservoir will extract a larger amount of pore water, increase the gas saturation in the sediment, and reduce the methane recovery rate. However, the high gas saturation caused by the large-scale extraction of pore water is conducive to the mixed gas injection and mixed hydrate formation in the subsequent CO2 storage stage.

[0048] The above is a further detailed description of the present invention in conjunction with specific preferred embodiments, and the specific implementation of the present invention should not be considered to be limited to these descriptions. Those skilled in the art will recognize that several equivalent substitutions or obvious variations can be made without departing from the scope of the present invention, and that any equivalent performance or application should be considered to fall within the scope of protection of the present invention.

Claims

1. A method for enhancing hydrate production and carbon dioxide storage by coupling injection and production with dual horizontal wells, characterized in that: The following steps are involved: S1. Based on the target reservoir characteristic data confirmed in advance, production wells and injection wells are laid out in different reservoir depths or different saturation areas; S2. Depressurize the reservoir through the production well to the set bottom hole pressure, and then produce and recover natural gas; S3. Alternately injecting flue gas and a kinetic accelerator solution through the injection wells, and controlling the injection rate to maintain the temperature and pressure near the injection wells below the natural gas hydrate phase equilibrium line, thereby displacing the natural gas in the pores and stimulating the decomposition of the natural gas hydrates; S4. Exploiting the gas through the production wells to the lower limit of hydrate saturation for reservoir mechanical safety, and shutting down the production wells; if the lower limit of hydrate saturation for reservoir mechanical safety is not reached, monitoring the output composition through the production wells; if CO2 breakthrough occurs and exceeds a preset upper limit, or if the methane content in the produced gas is lower than a preset lower limit, shutting down the production wells and stopping the alternating injection; S5. Inject CO2-rich flue gas or liquid CO2 through the injection well to restore the reservoir pressure to the pressure before extraction, generate mixed hydrates to store CO2 in the solid state, and repair the reservoir sediment skeleton; In step S3, when the injection well monitoring equipment detects that the pressure drop has reached the vicinity of the injection well and is lower than the phase equilibrium pressure, the pressure reduction production continues, and flue gas and kinetic accelerator solution are alternately injected into the injection well to drive the decomposed natural gas and the original free natural gas in the pores toward the production well, thereby improving the natural gas recovery rate and delaying CO2 breakthrough. The flue gas in step S3 includes 8% to 15% of CO2 gas and 85% to 92% of nitrogen by mole fraction; the kinetic accelerator solution is a mixed solution of sodium dodecyl sulfate and sodium dodecylbenzenesulfonate; In step S5, if CO2-rich flue gas containing CO2 gas and nitrogen with a CO2 mole fraction greater than 75% is injected, the mixed hydrate generated is CH4 / CO2 / N2 mixed hydrate; if liquid CO2 is injected, the mixed hydrate generated is CH4 / CO2 mixed hydrate.

2. The method for enhancing hydrate production and carbon dioxide storage by coupling injection and production with dual horizontal wells according to claim 1, characterized in that: The target reservoir characteristic data in step S1 include: temperature, pressure, phase saturation distribution and spatial occurrence characteristics of the target reservoir at different depths, wherein the phase saturation distribution includes hydrate saturation, gas saturation and water saturation at different depths.

3. The method for enhancing hydrate production and carbon dioxide storage by coupling injection and production with dual horizontal wells according to claim 2, wherein: Step S1: laying out production wells and injection wells at different reservoir depths or in different saturation areas, specifically including: Placing production wells in the upper reservoir with higher hydrate saturation and injection wells in the lower reservoir with lower hydrate saturation to improve production efficiency; or The production wells are laid in the lower part of the reservoir with lower hydrate saturation, and the injection wells are laid in the upper part of the reservoir with higher hydrate saturation to improve the CO2 storage efficiency.

4. The method for enhancing hydrate production and carbon dioxide storage by coupling injection and production with dual horizontal wells according to claim 1, wherein: In step S2, the production well is depressurized to a bottom hole pressure of 5 MPa to 7 MPa.

5. The method for enhancing hydrate production and carbon dioxide storage by coupling injection and production with dual horizontal wells according to claim 1, wherein: In step S2, the reservoir pressure is reduced through the production well to drain the pore water in the reservoir to reserve pore space for the subsequent alternating injection and CO2 storage, as well as space for the growth of mixed hydrates.

6. The method for enhancing hydrate production and carbon dioxide storage by coupling injection and production with dual horizontal wells according to claim 1, wherein: The kinetic accelerator solution is a 1 wt% mixed solution of sodium dodecyl sulfate and sodium dodecylbenzene sulfonate; the injected flue gas and kinetic accelerator solution displace natural gas recovery and stimulate the decomposition of natural gas hydrates, thereby improving the natural gas recovery rate.

7. The method for enhancing hydrate production and carbon dioxide storage by coupling injection and production with dual horizontal wells according to claim 1, wherein: In step S5, the type of injected CO2-rich flue gas or liquid CO2 is related to the temperature and pressure conditions at different depths of the reservoir. By adjusting the ratio of CO2 to N2 in the CO2-rich flue gas, the phase equilibrium of CH4 / CO2 / N2 mixed hydrate or CH4 / CO2 mixed hydrate is controlled to be under conditions suitable for hydrate formation and growth.

8. The method for enhancing hydrate production and carbon dioxide storage by coupling injection and production with dual horizontal wells according to claim 1, wherein: Also includes the steps: S6. Monitor reservoir characteristic data and inject CO2-rich flue gas or liquid CO2 in real time and multiple stages to replenish pressure. Once the data stabilizes, seal each well.

Images