Method for natural gas production and carbon storage by alternately injecting phase change materials and phase change emulsions

Abstract

The present invention discloses a method for alternating the injection of phase change material and phase change emulsion into marine gas hydrate reservoirs to enhance natural gas extraction and carbon sequestration. The method comprises: alternately injecting phase change material and phase change emulsion into the overlying layer of the marine gas hydrate reservoir to produce a modified overlying layer; exploiting the marine gas hydrate reservoir; and injecting CO2 into the natural gas goaf of the marine gas hydrate reservoir to sequester the CO2 in the form of CO2 hydrates. This method can improve natural gas extraction efficiency and increase CO2 sequestration density by preventing CO2 from diffusing upward.

Description

Technical Field

[0001] The present invention belongs to the technical field of natural gas hydrate exploitation and carbon sequestration, and specifically relates to a method for transforming marine natural gas hydrate reservoirs by alternately injecting phase change materials and phase change emulsions to enhance natural gas exploitation and carbon sequestration. Background Art

[0002] Natural gas hydrates are ice-like substances formed by natural gas and water under certain conditions of high pressure and low temperature. They are primarily found in deep-sea sediments or terrestrial permafrost. They are characterized by large reserves, shallow burial depths, and cleanliness. It is estimated that the methane reserves contained in natural gas hydrates are twice the current global reserves of natural gas, coal, and oil, and their total organic carbon content is as high as 10 trillion tons, making them an important alternative energy source.

[0003] Unlike traditional oil and gas reservoirs, natural gas hydrates are mostly found in submarine sediments. The overlying layers of natural gas hydrate reservoirs in submarine environments are generally diagenetic sediments with moderate mechanical strength and high permeability. Hydrate extraction typically requires stimulation measures, such as pressure reduction, hot water injection, and inhibitor injection, to disrupt the hydrate phase equilibrium and promote hydrate decomposition. For example, pressure reduction primarily stimulates hydrate decomposition by reducing reservoir pressure to below the hydrate phase equilibrium pressure. The sustainability of this method depends on the pressure range, hydrate saturation, and formation permeability. Marine hydrate reservoirs are mostly water-saturated systems. When using pressure reduction extraction, pore water migration reduces reservoir pressure by discharging free pore water. However, in the absence of low-permeability overburden, it is difficult to reduce the water saturation within the hydrate reservoir, meaning that it is difficult to reduce the reservoir pressure to below the phase equilibrium pressure to stimulate hydrate decomposition. Even if depressurization is successfully achieved to decompose hydrates, continued, high-volume water seepage from the overburden will significantly impact subsequent gas production, ultimately leading to a low gas-to-liquid ratio throughout the extraction process. This is highly detrimental to large-scale commercial hydrate development. Therefore, to improve the success rate and efficiency of offshore hydrate extraction, reservoir modification prior to extraction is urgently needed. Furthermore, it is noteworthy that reservoir modification also enhances the overall hydrate reservoir's resilience to geological risks.

[0004] Conventional and unconventional oil and gas reservoirs usually undergo reservoir transformation and pretreatment operations before exploitation. Currently, reservoir transformation technology has become an indispensable measure in the development process of oil and gas reservoirs and a core technology supporting efficient exploration and development. In the case of natural gas hydrates, reservoir transformation is a proactive artificial transformation that improves the porosity (porosity, permeability) and mechanical properties of the original reservoir to provide good conditions for subsequent pressure transmission and gas-water seepage production, thereby achieving increased production and efficiency. Against this background, hydrate reservoir transformation technology has developed rapidly in recent years. For example, liquid CO2 (CN106761589B) and emulsion CO2 (CN111271033B) have been proposed for natural gas hydrate reservoir transformation. The purpose of reservoir transformation based on CO2 injection is to reduce mining risks and improve mining efficiency by generating a low-permeability CO2 hydrate cap layer with a certain mechanical consolidation strength above the hydrate reservoir.

[0005] However, these reservoir reconstruction technologies present several challenges: 1. The generated CO2 hydrate caprock will be continuously eroded and degraded during contact with seawater, posing a long-term risk of instability. 2. CO2 hydrate formation is primarily controlled by temperature and pressure, and reservoir conditions are complex, making it very easy for hydrates to form during injection, causing wellbore blockage and placing high demands on the injection process. 3. When the overlying layer of a natural gas hydrate reservoir is thin, the temperature and pressure conditions for CO2 hydrate formation may not be met. 4. The formation of the CO2 hydrate caprock is significantly affected by reservoir water saturation, and low CO2 water saturation can easily occur due to localized low water saturation, resulting in thinner areas of the caprock. This poses a significant production safety hazard for subsequent depressurization of the hydrate reservoir. 5. The CO2 phase equilibrium conditions are relatively fixed, resulting in a small range within the overlying layer suitable for caprock formation, making it impossible to generate multiple dense caprocks vertically. 6. The stability of the CO2 hydrate caprock is highly susceptible to reservoir temperature and pressure conditions, and in the event of extreme geological disasters, the caprock is prone to instability and collapse. In addition, during the CO2 storage process, CO2 short-circuiting is prone to occur. After CO2 is stored in the goaf, as CO2 hydrates continue to degrade in the complex environment within the sedimentary layer and the CO2 cap layer itself has degradation problems, a large amount of CO2 gas will migrate to the sea, resulting in a significant reduction in CO2 storage density and a huge impact on the environment.

[0006] In summary, to improve natural gas extraction efficiency and CO2 storage density, there is an objective need to transform the overlying layers of marine natural gas hydrate reservoirs. However, currently proposed reservoir transformation technologies are primarily based on injecting CO2 to create a dense hydrate caprock. This technology is characterized by high instability risk, demanding injection processes, and low tolerance for reservoir conditions. Therefore, selecting suitable materials with good migration performance within seafloor sediments for reservoir transformation is a bottleneck issue that urgently needs to be addressed in this field. Furthermore, avoiding CO2 short-circuiting during the storage process and the upward diffusion of gas generated by degraded CO2 hydrates after CO2 solidification and storage in goafs, which leads to storage failure, are also urgent issues that need to be addressed in this field. Summary of the Invention

[0007] In light of the aforementioned shortcomings of the prior art, the present invention aims to provide a method for enhancing natural gas recovery and carbon sequestration by alternating the injection of phase change materials and phase change emulsions into marine natural gas hydrate reservoirs. This method improves natural gas recovery efficiency and increases CO2 storage density by preventing upward CO2 diffusion.

[0008] To achieve the above objectives, the present invention provides a method for transforming marine natural gas hydrate reservoirs by alternately injecting phase change materials and phase change emulsions to produce natural gas and store carbon. The method comprises the following steps:

[0009] (1) deploying production wells in a marine natural gas hydrate reservoir and deploying injection wells in an overburden layer above the marine natural gas hydrate reservoir;

[0010] (2) alternately injecting a phase change material and a phase change emulsion through the injection well, and when the total diffusion range of the phase change material and the phase change emulsion is 10-30% of the thickness of the overburden in the thickness direction and 100-150% of the plane area of ​​the lower marine natural gas hydrate reservoir in the plane direction, stopping the injection of the phase change material and the phase change emulsion and closing the injection well; when the permeability of the overburden is 0.1-10 mD or the porosity is 10-15%, obtaining a transformed overburden;

[0011] (3) exploiting the marine natural gas hydrate reservoir through the production well using a pressure reduction method, and when the volume content of methane gas in the fluid produced by the production well is less than 10%, closing the production well to complete the exploitation of the natural gas;

[0012] (4) CO2 is injected through the production well and stored in the form of CO2 hydrate in the natural gas goaf of the marine natural gas hydrate reservoir after mining.

[0013] According to a specific embodiment of the present invention, preferably, the phase change material is a liquid-solid phase change material, and the liquid-solid phase change temperature of the phase change material under normal pressure conditions is 3 to 12°C; the phase change material is insoluble in water; and after the solid phase change material is immersed in liquid CO2 at 5MPa and 3°C for 48 hours, its mass loss rate is 0 to 0.5%.

[0014] According to a specific embodiment of the present invention, preferably, the phase change material includes a combination of a first normal alkane and a second normal alkane, the first normal alkane includes n-hexadecane, and the second normal alkane includes one or both of n-tridecane and n-tetradecane; based on the total mass of the phase change material as 100%, the content of the first normal alkane is 55-70%, and the content of the second normal alkane is 30-45%.

[0015] According to a specific embodiment of the present invention, preferably, based on the total mass of the phase change emulsion as 100%, it includes: 40-60% phase change material, 0.1-2% surfactant and 38-59.9% water; wherein, the phase change material is a liquid-solid phase change material, and the liquid-solid phase change temperature of the phase change material under normal pressure conditions is 3-12°C; the phase change material is insoluble in water; and after the solid phase change material is immersed in liquid CO2 at 5MPa and 3°C for 48 hours, its mass loss rate is 0-0.5%.

[0016] According to a specific embodiment of the present invention, preferably, in the phase change emulsion, the phase change material includes a combination of a first normal alkane and a second normal alkane, the first normal alkane includes n-hexadecane, and the second normal alkane includes one or both of n-tridecane and n-tetradecane; based on the total mass of the phase change material as 100%, the content of the first normal alkane is 55-70%, and the content of the second normal alkane is 30-45%.

[0017] According to a specific embodiment of the present invention, preferably, in the phase change emulsion, the surfactant includes one or more of sodium alkyl sulfate, sorbitan fatty acid ester (Span) and polyoxyethylene sorbitan fatty acid ester (Tween).

[0018] According to a specific embodiment of the present invention, preferably, the phase change emulsion is an oil-in-water emulsion. More preferably, the phase change emulsion is prepared by at least the following steps: uniformly mixing the surfactant with water to obtain an aqueous phase; and adding the aqueous phase to the phase change material in batches and shearing the mixture to obtain the phase change emulsion.

[0019] According to a specific embodiment of the present invention, preferably, when the phase change material and the phase change emulsion are alternately injected through the injection well, the volume of the phase change material and the volume of the phase change emulsion injected each time are the same, and the volume of the phase change material and the volume of the phase change emulsion injected each time are respectively 1 to 5% of the total injection volume of the two.

[0020] According to a specific embodiment of the present invention, preferably, when the phase change material and the phase change emulsion are alternately injected through the injection well, the injection temperature is higher than the phase change temperature of the phase change material, and the injection pressure is lower than the fracture pressure of the overlying layer.

[0021] According to a specific embodiment of the present invention, preferably, the production well is a vertical well, and the injection well is a horizontal well.

[0022] According to a specific embodiment of the present invention, preferably, the production pressure when the marine natural gas hydrate reservoir is produced through the production well using the pressure reduction method is 1 to 4 MPa lower than the phase equilibrium pressure corresponding to the temperature of the marine natural gas hydrate reservoir.

[0023] According to a specific embodiment of the present invention, preferably, the CO2 injected through the production well includes liquid carbon dioxide or emulsion carbon dioxide.

[0024] According to a specific embodiment of the present invention, preferably, the injection temperature when injecting CO2 through the production well is higher than the formation temperature of CO2 hydrate under the formation pressure conditions corresponding to the injection depth, and the injection pressure is higher than the formation pressure corresponding to the injection depth and lower than the fracture pressure of the overlying layer after the transformation.

[0025] According to a specific embodiment of the present invention, preferably, when the injection amount of CO2 reaches 0.2 to 0.4 times the pore volume of the marine natural gas hydrate reservoir after mining, the injection of CO2 is stopped.

[0026] The present invention has at least the following beneficial effects:

[0027] (1) Compared with the process of injecting liquid carbon dioxide or emulsified carbon dioxide into the overlying layer of the marine natural gas hydrate reservoir for transformation, the injection conditions of the alternate injection of phase change material and phase change emulsion in the present invention are easier to control. Basically, it is sufficient to control the injection temperature, thereby avoiding the complex temperature and pressure conditions that need to be considered when injecting CO2 for reservoir transformation.

[0028] (2) By adopting the method of alternately injecting phase change material and phase change emulsion of the present invention, the phase change emulsion displaces the phase change material to migrate and diffuse over a wider range. At the same time, by utilizing the characteristics of ultra-low permeability and high mechanical strength of the phase change material of the present invention after the liquid-solid phase change, the present invention transforms the overlying layer of the hydrate reservoir to form a large-scale, stable, and high-mechanical-strength artificial low-permeability layer, which significantly improves the efficiency and safety of natural gas extraction. The artificial low-permeability layer of the present invention is not easily degraded by seawater erosion and has almost no risk of instability. In addition, the artificial low-permeability layer of the present invention can effectively prevent short circuits during the CO2 storage process and the upward migration and diffusion of CO2 hydrates into the atmosphere after degradation, thereby enhancing the storage stability and storage density of CO2.

[0029] (3) The present invention has relatively low requirements on the overlying layer conditions of the marine natural gas hydrate reservoir. In the case of the existence of an overlying layer, the method of the present invention can be used to transform it without considering the thickness and water content of the overlying layer. BRIEF DESCRIPTION OF THE DRAWINGS

[0030] Figure 1 Schematic diagram of mining before and after alternate injection of phase change material and phase change emulsion;

[0031] Figure 2 This is a comparison diagram of the solid phase change material of Example 1 before and after being immersed in liquid CO2 for 48 hours;

[0032] Figure 3 The optical images of the phase change emulsion of Example 1 after being placed at room temperature for 24 hours and after being cured in a 3°C environment;

[0033] Figure 4 A schematic structural diagram of a simulation experiment device used in the embodiment;

[0034] Figure 5 The temperature and pressure curves of the hydrate formation process of Comparative Example 1 and Example 1 change with time;

[0035] Figure 6 The temperature and pressure curves change with time during the depressurization mining process in Comparative Example 1 and Example 1;

[0036] Figure 7 The curves of gas-liquid ratio, gas production and liquid production of comparative example 1 and example 1 change over time.

[0037] Description of Figure Numbers:

[0038] 1-gas cylinder; 2-pressure reducing valve; 3-stop valve; 4-low-temperature circulating water bath; 5-reactor; 6-MCGS data acquisition system; 7-phase change emulsion injection piston tank; 8-phase change material injection piston tank; 9-constant speed and constant pressure pump; 10-liquid CO2 injection piston tank; 11-gas collecting tank; 12-gas-liquid separation tank; 13-back pressure valve. DETAILED DESCRIPTION

[0039] In order to have a clearer understanding of the technical features, objectives and beneficial effects of the present invention, the present invention is now described in detail below with reference to the embodiments and drawings, but this should not be construed as limiting the scope of implementation of the present invention.

[0040] The present invention provides a method for transforming marine natural gas hydrate reservoirs by alternately injecting phase change materials and phase change emulsions to enhance natural gas production and carbon sequestration. The method comprises the following steps:

[0041] (1) deploying production wells in a marine natural gas hydrate reservoir and deploying injection wells in an overburden layer above the marine natural gas hydrate reservoir;

[0042] (2) alternately injecting a phase change material and a phase change emulsion through the injection well, and when the total diffusion range of the phase change material and the phase change emulsion is 10-30% of the thickness of the overburden in the thickness direction and 100-150% of the plane area of ​​the lower marine natural gas hydrate reservoir in the plane direction, stopping the injection of the phase change material and the phase change emulsion and closing the injection well; when the permeability of the overburden is 0.1-10 mD or the porosity is 10-15%, obtaining a transformed overburden;

[0043] (3) exploiting the marine natural gas hydrate reservoir through the production well using a pressure reduction method, and when the volume content of methane gas in the fluid produced by the production well is less than 10%, closing the production well to complete the exploitation of the natural gas;

[0044] (4) CO2 is injected through the production well and stored in the form of CO2 hydrate in the natural gas goaf of the marine natural gas hydrate reservoir after mining.

[0045] At present, the exploitation of natural gas hydrates in the sea faces at least the problem of low exploitation efficiency due to the downward penetration of water from the overlying layer, as well as the problem of easy short circuit during CO2 solidification and storage and the problem of CO2 hydrate degradation over time. The existing reservoir transformation methods are difficult to solve the above three problems at the same time.

[0046] like Figure 1As shown, when the phase change material and phase change emulsion are not injected alternately, the natural gas hydrate reservoir in the sea is mined. Due to the high permeability and general mechanical strength of the overlying layer, the natural gas extraction efficiency is low (low gas-liquid ratio) and there are high safety risks.

[0047] The present invention transforms the reservoir by alternately injecting phase change materials and phase change emulsions into the overburden of marine natural gas hydrate deposits, solving the above three problems at the same time. While improving the efficiency of natural gas extraction (high gas-liquid ratio), it also improves the CO2 storage density by preventing premature short-circuiting of CO2 and the upward diffusion of hydrate degradation. The inventors found that phase change emulsions have good fluidity and diffusivity in porous media and can change the wettability of sand particles. At the same time, it was found that the phase change material of the present invention has higher mechanical strength than the phase change emulsion after solidification (i.e., after liquid-solid phase transition). The present invention utilizes the above characteristics of the phase change emulsion and the phase change material, adopts an alternating injection method, so that the phase change emulsion displaces the phase change material for a wider range of migration and diffusion. At the same time, taking advantage of the high mechanical strength of the phase change material after solidification, a large-scale artificial low permeability layer formed by the phase change material and the phase change emulsion is constructed in the overburden. The artificial low permeability layer has high mechanical strength, which significantly enhances the stability of the overburden after transformation. In the transformed overlying layer, the phase change material and phase change emulsion are transformed from liquid phase to solid phase, forming an artificial low-permeability layer. This enables the subsequent depressurization method to be used to exploit the offshore natural gas hydrate reservoir in a closed (or nearly closed) system. This effectively avoids the seepage of seawater in the overlying layer and the migration of sand particles that destroy the original stable structure of the reservoir and cause reservoir instability. It also significantly improves the efficiency of natural gas extraction and ensures sufficient mining safety.

[0048] Furthermore, after natural gas extraction, the present invention stores CO2 in the form of CO2 hydrates within the natural gas goaf, achieving integrated natural gas extraction and CO2 storage. Furthermore, the artificial low-permeability layer constructed by the present invention effectively prevents premature short-circuiting of CO2 and the upward migration and diffusion of CO2 hydrates into the atmosphere after degradation, thereby enhancing the CO2 storage stability and density.

[0049] It is understood by those skilled in the art that the overlying layer of the marine natural gas hydrate reservoir is generally a region with a relatively high permeability, and the permeability of the overlying layer is generally higher than 10 mD.

[0050] In some embodiments, the phase change material is a liquid-solid phase change material, the liquid-solid phase change temperature of the phase change material under normal pressure is 3 to 12°C; the phase change material is insoluble in water; and after the solid phase change material is immersed in liquid CO2 at 5 MPa and 3°C for 48 hours, its mass loss rate is 0 to 0.5%. It should be noted that the mass loss rate is calculated as follows: mass loss rate (%) = (mass of the solid phase change material before immersion in liquid CO2 - mass of the solid phase change material after immersion in liquid CO2) ÷ mass of the solid phase change material before immersion in liquid CO2 × 100%.

[0051] In some embodiments, the phase change material includes a combination of a first normal alkane and a second normal alkane, the first normal alkane includes n-hexadecane, and the second normal alkane includes one or both of n-tridecane and n-tetradecane; based on the total mass of the phase change material as 100%, the content of the first normal alkane is 55-70%, and the content of the second normal alkane is 30-45%.

[0052] In some embodiments, based on the total mass of the phase change emulsion as 100%, it includes: 40-60% phase change material, 0.1-2% surfactant, preferably 0.1-0.3% and 38-59.9% water, preferably 39.7-59.9%.

[0053] In some embodiments, in the phase change emulsion, the phase change material includes a combination of a first normal alkane and a second normal alkane, the first normal alkane includes n-hexadecane, and the second normal alkane includes one or both of n-tridecane and n-tetradecane; based on the total mass of the phase change material as 100%, the content of the first normal alkane is 55-70%, and the content of the second normal alkane is 30-45%.

[0054] In some embodiments, the phase change material injected alternately is the same as the phase change material in the phase change emulsion.

[0055] In some embodiments, in the phase change emulsion, the surfactant includes one or more of sodium alkyl sulfate, sorbitan fatty acid ester (Span), and polyoxyethylene sorbitan fatty acid ester (Tween). Specifically, the surfactant includes one or more of sodium lauryl sulfate (SDS), sorbitan monostearate (Span 60), and polyoxyethylene sorbitan monostearate 60 (Tween 60).

[0056] In some embodiments, the phase change emulsion has a liquid-solid phase transition temperature of 3 to 12° C. under normal pressure.

[0057] In some embodiments, the phase change emulsion is an oil-in-water emulsion. Preferably, the phase change emulsion is prepared by at least the following steps: uniformly mixing the surfactant with water to obtain an aqueous phase; adding the aqueous phase to the phase change material in batches and shearing to obtain the phase change emulsion. More preferably, the aqueous phase is added in 2 to 4 batches (those skilled in the art can make routine adjustments to the amount of aqueous phase added to each batch, for example, the amount of aqueous phase added each time can be evenly distributed); the shearing speed is 10,000 to 20,000 rpm, and the time is 5 to 15 minutes.

[0058] The phase-change emulsion formulated by the present invention using the aforementioned phase-change material, surfactant, and water through emulsification exhibits excellent fluidity and diffusivity in porous media, can alter the wettability of sand particles, and exhibits excellent heat transfer properties. The alternating injection method of the present invention allows the phase-change emulsion to displace the phase-change material for wider migration and diffusion. By utilizing the ultra-low permeability and high mechanical strength of the phase-change material after the liquid-solid phase transition, the overlying layer of the hydrate reservoir is transformed to form a large-scale, stable, and highly mechanically strong artificial low-permeability layer, significantly improving the efficiency and safety of natural gas extraction.

[0059] At the same time, the inventors unexpectedly discovered that the phase change material (i.e., the combination of the first normal alkane and the second normal alkane) preferably used in the present invention has a high resistance to CO2 erosion. After using the phase change material of the present invention and the phase change emulsion containing the phase change material to form an artificial low permeability layer, not only the efficiency and safety of natural gas extraction are improved, but also, due to the insensitivity of the phase change material to CO2 after solidification, it can effectively prevent the solidified and sealed CO2 hydrate from degrading and escaping into the atmosphere in the complex environment of the seabed. Therefore, the artificial low permeability layer constructed by the present invention can effectively prevent CO2 hydrate from migrating upward and diffusing into the atmosphere after degradation, thereby enhancing the storage stability and storage density of CO2.

[0060] In some embodiments, when the phase change material and the phase change emulsion are alternately injected through the injection well, the volume of the phase change material and the volume of the phase change emulsion injected each time are the same, and the volume of the phase change material and the volume of the phase change emulsion injected each time are respectively 1-5% of the total injected volume of the phase change material and the phase change emulsion. Preferably, the total amount of the phase change material and the total amount of the phase change emulsion injected are the same.

[0061] In some embodiments, the injection temperature when the phase change material and the phase change emulsion are alternately injected through the injection well is higher than the phase change temperature of the phase change material, and the injection pressure is lower than the bursting pressure of the overlying layer. When injecting the phase change material and the phase change emulsion, they can be preheated to ensure that the injection temperature is higher than the phase change temperature of the phase change material, thereby ensuring that no liquid-solid phase change occurs to produce a solid state during the injection process. In addition, when injecting the phase change material and the phase change emulsion, the injection pressure is lower than the bursting pressure of the overlying layer to prevent the overlying layer from being broken due to excessive pressure, leading to seawater erosion. The bursting pressure of the overlying layer can be obtained by a person skilled in the art through testing using methods in the prior art, and the present invention does not impose any special restrictions on it.

[0062] In some embodiments, the production wells are vertical wells and the injection wells are horizontal wells. The number and size of the production wells and injection wells can be adjusted routinely by those skilled in the art and are not particularly limited in the present invention.

[0063] In some embodiments, the production pressure of the marine natural gas hydrate reservoir using the depressurization method through the production well is 1-4 MPa lower than the phase equilibrium pressure corresponding to the temperature of the marine natural gas hydrate reservoir. The present invention does not impose any particular limitation on the production temperature, which can be determined by those skilled in the art based on the temperature of the marine natural gas hydrate reservoir. The specific steps of the depressurization method can be carried out according to the procedures in the prior art and are not particularly limited by the present invention.

[0064] In some embodiments, the CO2 injected through the production well comprises liquid carbon dioxide or emulsion carbon dioxide.

[0065] In some embodiments, the injection temperature of CO2 injected through the production well is higher than the formation temperature of CO2 hydrate under the formation pressure corresponding to the injection depth, and the injection pressure is higher than the formation pressure corresponding to the injection depth and lower than the fracture pressure of the modified overburden. The fracture pressure of the modified overburden can be determined by those skilled in the art through testing using methods known in the art and is not particularly limited in the present invention.

[0066] In some embodiments, when the injection volume of CO2 reaches 0.2 to 0.4 times the pore volume of the marine natural gas hydrate reservoir after extraction, the injection of CO2 is stopped.

[0067] The present invention will be specifically described below with reference to Examples. However, the present invention is not limited to these Examples and can be implemented with various modifications within the scope of the gist of the present invention.

[0068] Comparative Example 1

[0069] Preparation of the natural gas hydrate reservoir and its overlying layer: 2.11 kg of quartz sand was weighed and thoroughly mixed with 0.422 kg of water at a mass ratio of 5:1. The mixture was then filled into a reactor and compacted. 2.065 kg of dry sand was then filled on top and compacted. After the reactor was installed, methane gas was introduced to 12 MPa for a leak test. If there was no significant pressure drop within 12 hours, the reactor was considered to be airtight and the methane gas was discharged. A low-temperature circulating water bath was then opened to cool the reactor, set to 1°C. When the reactor reached equilibrium, the temperature was 2.7°C. Once the temperature stabilized, methane gas was introduced to the reactor until the pressure reached 10 MPa. Hydrate formation was considered complete after the pressure in the reactor stopped decreasing. Methane gas was introduced again until the pressure reached 10 MPa, and hydrate formation was considered complete. To generate more hydrates, deionized water was added to the reactor until the pressure reached 12 MPa. After a period of waiting, hydrate formation was complete. To simulate more realistic reservoir conditions, the temperature of the low-temperature circulating water bath was adjusted to 6°C, completing the preparation of the natural gas hydrate reservoir and its overlying layer.

[0070] Natural gas production process: To create a non-closed system similar to a real-world environment, a constant-speed, constant-pressure pump in constant pressure mode supplies a constant pressure of 10 MPa of overlying water to the reactor's top inlet. The backpressure valve is pre-adjusted to 3 MPa. The backpressure valve is then connected between the outlet of the production well at the bottom of the reactor and the gas-liquid separator tank. The shutoff valves between the constant-speed, constant-pressure pump and the reactor, as well as the shutoff valves between the reactor and the backpressure valve, are then opened to initiate depressurized production of the overlying water system. During the depressurized production process, the pressure changes in the separator tank and its connected gas collection tank must be monitored. When the pressure approaches 3 MPa, the tank must be disconnected. Furthermore, the liquid in the separator tank must be regularly drained until the reactor temperature returns to its original temperature of 6°C. After the water phase in the separator tank is evacuated, the produced methane content can be calculated based on the temperatures, pressures, and volumes of the gas collection tank and separator tank.

[0071] Example 1

[0072] Taking the total mass of the phase change material used in this embodiment as 100%, it includes: 70% of n-hexadecane and 30% of n-tridecane.

[0073] The phase change material has a liquid-to-solid phase transition temperature of 9°C under normal pressure. The phase change material is insoluble in water. When the solid phase change material is immersed in liquid CO2 at 5MPa and 3°C for 48 hours, its mass loss rate is 0.2%. Figure 2The following image compares the solid phase-change material before and after immersion in liquid CO2 for 48 hours. It can be seen that after immersion in liquid CO2 for 48 hours, the solidified phase-change material has not changed significantly, and its mass loss rate is very low. This indicates that the phase-change material is insensitive to CO2 and has high resistance to CO2 corrosion. This effectively prevents CO2 from escaping from the sediment, enhancing the CO2 storage stability and density.

[0074] Taking the total mass of the phase change emulsion used in this embodiment as 100%, it includes: 44.95% of the above-mentioned phase change material (ie, 70% n-hexadecane + 30% n-tridecane), 0.11% of Tween 60, and 54.94% of water.

[0075] The preparation steps of the phase change emulsion include: uniformly mixing Tween 60 and water to obtain an aqueous phase; adding the aqueous phase to the phase change material in three equal batches and rapidly shearing the phase change material through a homogenizer at a shearing speed of 15,000 rpm for 10 minutes to obtain the phase change emulsion.

[0076] The liquid-solid phase transition temperature of the phase change emulsion under normal pressure is 7.5°C.

[0077] Figure 3 The optical image of the phase change emulsion after being placed at room temperature for 24 hours (left) and the optical image after being cured in a 3°C environment (right).

[0078] It can be seen that the phase change emulsion of this embodiment has good fluidity and displacement ability, and can displace the phase change material in the overburden layer to migrate over a large range. Moreover, the phase change material changes from liquid to solid with certain mechanical strength as the temperature changes. By transforming the overburden layer, the infiltration of overlying water during the mining process can be reduced, and the gas-liquid ratio of the mining process can be improved. In addition, after the phase change material and phase change emulsion of this embodiment undergo liquid-solid phase change, a relatively closed environment can be constructed for the hydrate reservoir in the original non-closed system, which is conducive to quickly reaching the mining pressure during decompression, providing a larger decomposition driving force for the hydrate, and accelerating the hydrate decomposition process. In addition, the phase change material of this embodiment is insensitive to CO2 after solidification, so that the constructed cap layer can effectively prevent premature short-circuiting during the CO2 injection process and the escape of CO2 hydrates from the sedimentary layer after degradation.

[0079] By comparison, the liquid-to-solid phase transition temperature of n-hexadecane tested at atmospheric pressure was 18°C, which is too high and easily solidifies in the pipeline during injection. Furthermore, the liquid-to-solid phase transition temperature of n-tridecane tested at atmospheric pressure was around -5°C, which is too low to solidify under submarine reservoir conditions. This embodiment, however, uses a combination of n-hexadecane and n-tridecane in a specific ratio, which not only has a suitable phase transition temperature but is also resistant to CO2 corrosion.

[0080] The simulation experiment device used in this embodiment is as follows Figure 4 As shown, the simulation experimental device includes: a gas cylinder 1, a pressure reducing valve 2, a stop valve 3, a low-temperature circulating water bath 4, a reactor 5, an MCGS data acquisition system 6, a phase change emulsion injection piston tank 7, a phase change material injection piston tank 8, a constant speed and constant pressure pump 9, a liquid CO2 injection piston tank 10, a gas collecting tank 11, a gas-liquid separation tank 12 and a back pressure valve 13 and other components.

[0081] Slightly different from Comparative Example 1, phase change material and phase change emulsion were injected alternately: 2.11 kg of quartz sand was weighed, mixed thoroughly with 0.422 kg of water in a mass ratio of 5:1, and then filled into the reactor 5 and compacted. Then, 2.065 kg of dry sand was filled on top and compacted. After the reactor 5 was installed, methane gas was introduced into the gas cylinder 1 to 12 MPa for leak testing. If there was no obvious pressure drop within 12 hours, it was considered that the reactor 5 was airtight, and the methane gas was discharged. Subsequently, the low-temperature circulating water bath 4 was turned on to cool the reactor 5. The temperature of the water bath was set to 1°C. When the temperature was balanced, the temperature in the reactor 5 was 2.7°C. After the temperature stabilized, methane gas was introduced into the reactor 5 to a pressure of 10 MPa. After the pressure in the reactor 5 stopped decreasing, the first hydrate formation was considered to be complete. Methane gas was introduced into the reactor 5 again until the pressure reached 10 MPa. The hydrate formation was continued to be completed. In order to generate more hydrates, deionized water was then added to the reactor 5 to raise the pressure in the reactor 5 to 12 MPa. After a period of waiting, the hydrate formation in the reactor 5 was completed. Then, through a horizontal well drilled from the top of reactor 5 into the dry sand layer (simulating the overburden), 0.21 kg of phase-change material and 0.21 kg of phase-change emulsion were alternately injected into the dry sand layer at a rate of 5 mL each (injection was performed using phase-change emulsion injection piston tank 7, phase-change material injection piston tank 8, and constant-speed, constant-pressure pump 9). To simulate more realistic reservoir conditions, the temperature of low-temperature circulating water bath 4 was subsequently adjusted to bring the temperature within reactor 5 to 6°C. Because the temperature within reactor 5 was lower than the phase transition temperature of the phase-change material and phase-change emulsion, the liquid-solid phase transition process was completed in the dry sand layer, forming an artificial low-permeability layer in the overburden above the hydrate reservoir.

[0082] In this embodiment, the total diffusion range of the phase change material and phase change emulsion is 30% of the thickness of the overlying layer in the thickness direction and 100% of the plane area of ​​the lower natural gas hydrate reservoir in the plane direction. The permeability of the overlying layer after transformation is 0.28 mD.

[0083] The subsequent natural gas production process is the same as that in Comparative Example 1.

[0084] Figure 5 For comparative example 1 (the upper covering layer was not modified, Figure 5 (a)) and Example 1 (reforming the upper cover, Figure 5(b) shows the change of temperature and pressure curves over time during the hydrate formation process. Figure 6 For comparative example 1 (the upper covering layer was not modified, Figure 6 (a)) and Example 1 (reforming the upper cover, Figure 6 The temperature and pressure curves change with time during the depressurization process of (b)). It can be seen that in Example 1, when the overburden was not modified, the pressure dropped very slowly during the natural gas production process. This is because the pressure of the overburden water is 10 MPa, which has a large pressure difference with the production pressure. Therefore, during the production process, the overburden water will continue to seep into the hydrate reservoir and occupy the pore volume of the hydrate reservoir, making it difficult to reduce the pressure. The higher pressure in the reactor 5 will lead to a decrease in the decomposition driving force, which will reduce the hydrate decomposition rate and ultimately affect the gas-liquid ratio of the produced fluid. Figure 6 As can be seen from (a) in Comparative Example 1, during the mining process, the pressure gradually decreased until it reached the lowest point at the end of mining. After the production well was closed, the pressure began to gradually rise because the overlying water continued to penetrate into the hydrate reservoir until the hydrate reservoir pressure recovered to the same level as the overlying water pressure. Figure 6 It can be found from (b) in Example 1 that after the modification, the pressure in the reactor drops rapidly at the beginning of the pressure reduction, and a relatively low production pressure is always maintained throughout the entire production process. After the production well is closed at the end of the production process, the pressure change in the reactor 5 is still small. This is because the artificial low permeability layer generated by the phase change material and the phase change emulsion can effectively establish a closed pressure reduction environment. With its excellent low permeability performance, it can greatly reduce the permeability of the overlying water, effectively improve the decomposition driving force of the hydrate production process, accelerate gas production, and reduce water output.

[0085] Figure 7 For comparative example 1 (the upper covering layer was not modified, Figure 7 (a)) and Example 1 (reforming the upper cover, Figure 7 The gas-liquid ratio of production in (b) Figure 7 gas-water ratio), gas production and liquid production ( Figure 7 The curve of gas production (referred to as water production) changes over time. It can be seen that the gas production curves of Comparative Example 1 and Example 1 both rise rapidly in the early stage of mining, and then gradually slow down. This is because a large amount of free gas is produced in the early stage, and in the later stage it mainly comes from hydrate decomposition gas, which also makes the gas-liquid ratio larger at the beginning. In the same time, the liquid production of Comparative Example 1 is much more than that of Example 1. When the mining time is not much different, the liquid production of Comparative Example 1 is about 2.53 times that of Example 1. At the same time, in the hydrate decomposition stage, the gas-liquid ratio of Example 1 is increased by 69% compared with Comparative Example 1, which greatly improves the mining efficiency. At 166min, the gas-liquid ratio of the output fluid of the reactor 5 of this embodiment is 233STm3 CH4 / m 3 H2O, with higher natural gas extraction efficiency.

[0086] After the mining process is completed, the back pressure valve 13 on the top of the reactor 5 is set to 5MPa to drive water outward during the liquid CO2 injection process. The liquid CO2 in the piston tank 10 is then pushed into the reactor 5 by the constant speed and constant pressure pump 9. At the same time, the stop valve between the top of the reactor 5 and the back pressure valve 13 is opened. The injection temperature is 9°C and the injection pressure is 6MPa. When the CO2 short-circuits, the injection of liquid CO2 is stopped. In this embodiment, when the injection amount of CO2 reaches 0.35 times the pore volume of the natural gas hydrate deposit after mining, that is, 431.2mL of liquid CO2, a large amount of CO2 is produced at the back pressure valve 13, and the CO2 short-circuit phenomenon occurs. The injection of liquid CO2 is stopped, and the CO2 is sealed in the natural gas goaf in the form of CO2 hydrate and free CO2. The CO2 storage density of this embodiment is 161.54kg / m 3 Sequestration density = CO2 mass sealed in the reservoir ÷ volume of reactor 5. Those skilled in the art will appreciate that during simulations, the displaced fluid contained a large amount of CO2, a phenomenon known as CO2 short-circuiting, whereby CO2 formed pathways within reactor 5.

[0087] Example 2

[0088] This embodiment is basically the same as embodiment 1, except that the phase change material and phase change emulsion are different. The remaining steps are the same as embodiment 1.

[0089] Taking the total mass of the phase change material used in this embodiment as 100%, it comprises 70% n-hexadecane and 30% n-tetradecane. The liquid-to-solid phase transition temperature of this phase change material at normal pressure is 11°C. This phase change material is insoluble in water. After immersing the solid phase change material in liquid CO₂ at 5 MPa and 3°C for 48 hours, its mass loss rate is 0.4%.

[0090] The phase-change emulsion used in this example, calculated as 100% by total mass, comprises: 44.95% of the aforementioned phase-change material (i.e., 70% n-hexadecane + 30% n-tetradecane), 0.11% Tween 60, and 54.94% water. The preparation steps for this phase-change emulsion are the same as those in Example 1. The liquid-to-solid phase transition temperature of this phase-change emulsion at normal pressure is 8.7°C.

[0091] At 166 min, the gas-liquid ratio of the output fluid of the reactor 5 of this embodiment is 214 STm 3 CH4 / m 3 H2O, with a higher natural gas extraction efficiency. The CO2 storage density of this embodiment is 155.47kg / m3 .

[0092] Comparative Example 2

[0093] This comparative example is compared with Example 1 and is basically the same as Example 1, except that: no phase change emulsion is injected, 0.42 kg of phase change material is injected, and the rest of the steps are the same as Example 1. The phase change material used is the same as in Example 1.

[0094] At 166 min, the gas-liquid ratio of the output fluid of the reactor of this comparative example is 126 STm 3 CH4 / m 3 The CO2 storage density of this comparative example is 124.35 kg / m 3 .

[0095] Comparative Example 3

[0096] This comparative example is compared with Example 1 and is basically the same as Example 1, except that no phase change material is injected, 0.42 kg of phase change emulsion is injected, and the rest of the steps are the same as Example 1. The phase change emulsion used is the same as that in Example 1.

[0097] At 166 min, the gas-liquid ratio of the output fluid of the reactor of this comparative example is 115 STm 3 CH4 / m 3 The CO2 storage density of this comparative example is 102.28 kg / m 3 .

[0098] Finally, it should be understood that the above embodiments are merely illustrative of the technical concepts and features of the present invention. Their purpose is to enable those skilled in the art to understand the contents of the present invention and implement them accordingly, and they are not intended to limit the scope of protection of the present invention. Those skilled in the art may make various modifications and improvements without departing from the principles and essence of the present invention, and such modifications and improvements are also considered to be within the scope of protection of the present invention.

Claims

1. A method for natural gas production and carbon sequestration by alternately injecting phase change material and phase change emulsion, comprising the following steps: (1) deploying production wells in a marine natural gas hydrate reservoir and deploying injection wells in an overburden layer above the marine natural gas hydrate reservoir; (2) alternately injecting a phase change material and a phase change emulsion through the injection well, and when the total diffusion range of the phase change material and the phase change emulsion is 10-30% of the thickness of the overburden in the thickness direction and 100-150% of the plane area of ​​the lower marine natural gas hydrate reservoir in the plane direction, stopping the injection of the phase change material and the phase change emulsion and closing the injection well; when the permeability of the overburden is 0.1-10 mD or the porosity is 10-15%, obtaining a transformed overburden; (3) exploiting the marine natural gas hydrate reservoir through the production well using a pressure reduction method, and when the volume content of methane gas in the fluid produced by the production well is less than 10%, closing the production well to complete the exploitation of the natural gas; (4) injecting CO2 through the production well to store CO2 in the form of CO2 hydrate in the natural gas goaf of the marine natural gas hydrate reservoir after extraction; The phase change material is a liquid-solid phase change material, and the liquid-solid phase change temperature of the phase change material under normal pressure is 3 to 12°C; the phase change material is insoluble in water; and after the solid phase change material is immersed in liquid CO2 at 5MPa and 3°C for 48 hours, its mass loss rate is 0 to 0.5%; the phase change material includes a combination of a first normal alkane and a second normal alkane, the first normal alkane includes n-hexadecane, and the second normal alkane includes one or both of n-tridecane and n-tetradecane; based on the total mass of the phase change material as 100%, the content of the first normal alkane is 55 to 70%, and the content of the second normal alkane is 30 to 45%; The phase change emulsion comprises, based on the total mass of the phase change emulsion being 100%, 40-60% of a phase change material, 0.1-2% of a surfactant, and 38-59.9% of water; wherein the phase change material is a liquid-solid phase change material, and the liquid-solid phase change temperature of the phase change material under normal pressure is 3-12° C.; the phase change material is insoluble in water; and after the solid phase change material is immersed in liquid CO2 at 5 MPa and 3° C. for 48 hours, its mass loss rate is 0-0.5%; In the phase-change emulsion, the phase-change material includes a combination of a first normal alkane and a second normal alkane, the first normal alkane includes n-hexadecane, and the second normal alkane includes one or both of n-tridecane and n-tetradecane; based on the total mass of the phase-change material as 100%, the content of the first normal alkane is 55-70%, and the content of the second normal alkane is 30-45%; In the phase change emulsion, the surfactant includes one or more of sodium alkyl sulfate, sorbitan fatty acid ester and polyoxyethylene sorbitan fatty acid ester; The phase change emulsion is an oil-in-water emulsion; The phase change emulsion is prepared by at least the following steps: uniformly mixing the surfactant with water to obtain an aqueous phase; and adding the aqueous phase to the phase change material in batches and shearing the mixture to obtain the phase change emulsion.

2. The method for natural gas production and carbon sequestration by alternately injecting phase change materials and phase change emulsions according to claim 1, wherein: When the phase change material and the phase change emulsion are alternately injected through the injection well, the volume of the phase change material and the volume of the phase change emulsion injected each time are the same, and the volume of the phase change material and the volume of the phase change emulsion injected each time are 1 to 5% of the total injection volume of the two.

3. The method for natural gas production and carbon sequestration by alternately injecting phase change materials and phase change emulsions according to claim 1, wherein: When the phase change material and the phase change emulsion are alternately injected through the injection well, the injection temperature is higher than the phase change temperature of the phase change material, and the injection pressure is lower than the fracture pressure of the overlying layer.

4. The method for natural gas production and carbon sequestration by alternately injecting phase change materials and phase change emulsions according to claim 1, wherein: The production well is a vertical well, and the injection well is a horizontal well.

5. The method for natural gas production and carbon sequestration by alternately injecting phase change materials and phase change emulsions according to claim 1, wherein: When the marine natural gas hydrate reservoir is mined through the production well using the pressure reduction method, the mining pressure is 1 to 4 MPa lower than the phase equilibrium pressure corresponding to the temperature of the marine natural gas hydrate reservoir.

6. The method for natural gas production and carbon sequestration by alternately injecting phase change materials and phase change emulsions according to claim 1, wherein: The CO2 injected through the production well includes liquid carbon dioxide or emulsion carbon dioxide.

7. The method for natural gas production and carbon sequestration by alternately injecting phase change materials and phase change emulsions according to claim 1, wherein: The injection temperature when injecting CO2 through the production well is higher than the formation temperature of CO2 hydrate under the formation pressure conditions corresponding to the injection depth, and the injection pressure is higher than the formation pressure corresponding to the injection depth and lower than the fracture pressure of the overlying layer after the transformation.

8. The method for natural gas production and carbon sequestration by alternately injecting phase change materials and phase change emulsions according to claim 1, wherein: When the injection volume of CO2 reaches 0.2 to 0.4 times the pore volume of the marine natural gas hydrate reservoir after extraction, the injection of CO2 is stopped.

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