Method for enhancing natural gas exploitation and carbon sequestration by alternately injecting phase-change material and phase-change emulsion to reform natural gas hydrate reservoir in sea area

Abstract

The invention discloses a method for enhancing natural gas exploitation and carbon sequestration by alternately injecting a phase-change material and a phase-change emulsion to modify a sea-area natural gas hydrate reservoir. The method comprises the following steps: alternately injecting a phase-change material and a phase-change emulsion into an overlying layer of the natural gas hydrate reservoir in a sea area to obtain a modified overlying layer; natural gas hydrate reservoirs in the sea area are mined; cO2 is injected into the natural gas goaf of the natural gas hydrate reservoir in the sea area to be sealed and stored in a CO2 hydrate mode. The natural gas extraction efficiency can be improved, and the CO2 storage density can be improved by preventing upward diffusion of CO2.

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 high pressure and low temperature conditions. They are mainly found in deep-sea sediments or permafrost on land. They have the characteristics of large reserves, shallow burial depth, and cleanliness. It is estimated that the methane reserves contained in natural gas hydrates are twice the global reserves of existing natural gas, coal, and oil, and the total organic carbon content is as high as 10 trillion tons, making them an important successor energy source.

[0003] Unlike traditional oil and gas reservoirs, natural gas hydrates are mostly found in seafloor sediments. The overlying layers of natural gas hydrate reservoirs in seafloor environments are generally diagenetic sediments with general mechanical strength and high permeability. The exploitation of hydrate reservoirs usually requires some stimulating measures, such as pressure reduction, hot water injection, and inhibitor injection, to break the hydrate phase equilibrium state and promote the decomposition of hydrates. Taking the depressurization method as an example, this method mainly stimulates the decomposition of hydrates by reducing the reservoir pressure to below the hydrate phase equilibrium pressure. The sustainability of the depressurization method depends on the pressure range, hydrate saturation, and formation permeability. Most marine hydrate reservoirs are water-saturated systems. When the depressurization method is used for exploitation, the migration of pore water will be reduced by discharging pore free water. However, in the absence of low-permeability overburden, it will be difficult to reduce the water saturation in the hydrate reservoir, that is, it is difficult to reduce the pressure of the hydrate reservoir to below the phase equilibrium pressure to stimulate the decomposition of hydrates. If the decomposition of hydrates is successfully achieved using the pressure reduction method, the continuous large-scale water seepage of the overburden will greatly affect the subsequent gas production efficiency, and ultimately lead to a lower gas-liquid ratio in the entire mining process, which is extremely unfavorable for the large-scale commercial development of hydrates. Therefore, in order to improve the success rate and efficiency of marine hydrate mining, it is urgent to carry out relevant reservoir transformation operations before mining. In addition, it is worth noting that through reservoir transformation, the ability of the entire hydrate reservoir to resist geological risks will also be improved.

[0004] Conventional and unconventional oil and gas reservoirs usually carry out reservoir transformation pretreatment operations before exploitation. At present, reservoir transformation technology has become an indispensable measure in the development process of oil and gas reservoirs and a core technology to support efficient exploration and development. In terms of natural gas hydrates, reservoir transformation is a proactive artificial transformation. By improving the porosity (porosity, permeability) and mechanical properties of the original reservoir, it provides good conditions for subsequent pressure transmission and gas-water seepage exploitation processes, thereby achieving increased production and efficiency. Against the above 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 the risk of exploitation and improve the efficiency of exploitation by generating a low-permeability CO2 hydrate caprock with a certain mechanical consolidation strength on the upper part of the hydrate reservoir.

[0005] However, the above reservoir transformation technology has the following problems: 1. The generated carbon dioxide hydrate cap layer will be continuously eroded and degraded during the contact with seawater. In the long run, the carbon dioxide cap layer has a certain risk of instability; 2. The formation of CO2 hydrate is mainly controlled by temperature and pressure conditions. The reservoir conditions are complex. It is very easy to generate hydrates during the injection process, causing wellbore blockage, and the injection process is required to be high; 3. When the overlying layer of the natural gas hydrate reservoir is thin, the temperature and pressure conditions for the formation of CO2 hydrate may not be met; 4. The carbon dioxide hydrate cap layer is greatly affected by the water saturation of the reservoir during the formation process. It is very easy to cause low CO2 water saturation due to low local water saturation, that is, there are thinner thickness areas in the cap layer, which will be a great production safety hazard for the subsequent depressurization exploitation of the hydrate reservoir; 5. The CO2 phase equilibrium conditions are relatively fixed, and the range suitable for the formation of the cap layer in the overlying layer of the hydrate reservoir is small, and multiple dense cap layers cannot be generated vertically; 6. The stability of the carbon dioxide hydrate cap layer is easily affected by the temperature and pressure conditions of the reservoir. If extreme geological disasters occur, the cap layer may be unstable 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 of 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, in order to improve the efficiency of natural gas extraction and the density of CO2 storage, there is an objective need to transform the overlying layers of marine natural gas hydrate reservoirs. However, the reservoir transformation technology currently proposed is mainly based on the injection of CO2 to generate dense hydrate caprocks. This technology has the characteristics of high risk of instability, harsh injection process, and low tolerance for reservoir conditions. Therefore, the selection of suitable materials that can have a good migration effect in the seabed sedimentary layer for reservoir transformation is a bottleneck problem that needs to be solved urgently in this field. In addition, how to avoid the short-circuiting phenomenon of CO2 during the storage process and the problem of upward diffusion of gas generated by degraded CO2 hydrates after CO2 solidification and sealing in the goaf, resulting in storage failure, is also a problem that needs to be solved urgently in this field. Summary of the invention

[0007] In view of the defects of the above-mentioned prior art, the purpose of the present invention is to provide a method for alternating injection of phase change materials and phase change emulsions to transform marine natural gas hydrate reservoirs to enhance natural gas production and carbon sequestration. The present invention can improve the efficiency of natural gas production and increase the CO2 sequestration density by preventing CO2 from diffusing upward.

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

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

[0010] (2) alternately injecting phase change material and phase change emulsion through the injection well, and when the total diffusion range of the phase change material and 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 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%, the transformed overburden is obtained;

[0011] (3) exploiting the marine natural gas hydrate reservoir through the production well by 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 void area of ​​the marine natural gas hydrate reservoir after exploitation.

[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 two 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 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 48h, 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 two 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; adding the aqueous phase to the phase change material in batches and shearing 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 transformed overlying layer.

[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 exploitation, 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 emulsion 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 only necessary to control the injection temperature, thus 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 in 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. When an overlying layer exists, 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 image of the phase change emulsion of Example 1 after being placed at room temperature for 24 hours and the optical image after being cured in a 3°C environment;

[0033] Figure 4 It is a structural schematic diagram of the 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 with 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 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, purposes and beneficial effects of the present invention, the present invention is now described in detail below in conjunction with 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 overlying layer above the marine natural gas hydrate reservoir;

[0042] (2) alternately injecting phase change material and phase change emulsion through the injection well, and when the total diffusion range of the phase change material and 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 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%, the transformed overburden is obtained;

[0043] (3) exploiting the marine natural gas hydrate reservoir through the production well by 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 void area of ​​the marine natural gas hydrate reservoir after exploitation.

[0045] At present, in the process of exploiting natural gas hydrates in the sea, there are at least problems such as the downward penetration of water from the overlying layer resulting in low exploitation efficiency, as well as the problem of short circuit during CO2 solidification and storage and the problem of CO2 hydrate degradation over a long period of time. However, 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 the phase change emulsion are not injected alternately, the exploitation of the marine natural gas hydrate reservoir will result in low natural gas extraction efficiency (low gas-liquid ratio) due to the high permeability and average mechanical strength of the overlying layer, and there will be high safety risks.

[0047] The present invention transforms the reservoir by alternately injecting phase change materials and phase change emulsions into the overlying layer of the marine natural gas hydrate reservoir, and solves the above three problems at the same time. While improving the natural gas extraction efficiency (high gas-liquid ratio), the CO2 storage density is improved by preventing the premature short circuit of CO2 and the upward diffusion of hydrate degradation. The inventors found that the phase change emulsion has good fluidity and diffusivity in porous media and can change the wettability of sand particles; at the same time, it is 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 change); the present invention utilizes the above characteristics of the phase change emulsion and the phase change material, adopts the method of alternating injection, so that the phase change emulsion drives the phase change material to migrate and diffuse in a wider range, and at the same time utilizes the advantage of the phase change material having higher mechanical strength after solidification, and constructs a large range of artificial low permeability layers formed by phase change materials and phase change emulsions in the overlying layer, and the artificial low permeability layer has higher mechanical strength, which significantly enhances the stability of the overlying layer 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, so that the subsequent depressurization method for the exploitation of marine natural gas hydrate reservoirs is carried out in a closed (or nearly closed) system, effectively avoiding 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, and significantly improving the efficiency of natural gas extraction, while ensuring sufficient extraction safety.

[0048] Moreover, after natural gas is mined, the present invention seals CO2 in the form of CO2 hydrate in the natural gas goaf, realizing the integration of natural gas mining and CO2 storage. At the same time, the artificial low permeability layer constructed by the present invention can effectively prevent CO2 from short-circuiting prematurely and CO2 hydrate from migrating upward and diffusing into the atmosphere after degradation, thereby enhancing the storage stability and storage density of CO2.

[0049] It can be 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 the mass loss rate of the solid phase change material after being immersed in liquid CO2 for 48 hours under 5MPa and 3°C is 0 to 0.5%. It should be noted that the calculation formula of the mass loss rate is: 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 being 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), etc. Specifically, the surfactant includes one or more of sodium dodecyl sulfate (SDS), sorbitan monostearate (Span 60) and polyoxyethylene sorbitan monostearate 60 (Tween 60), etc.

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

[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. Among them, 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 prepared by the present invention using the above phase change material, surfactant and water by emulsification has excellent fluidity and excellent diffusivity in porous media, can change the wettability of sand particles, and has excellent heat transfer. The alternating injection method of the present invention is adopted to enable the phase change emulsion to displace the phase change material for wider migration and diffusion. The phase change material of the present invention has the characteristics of ultra-low permeability and high mechanical strength after liquid-solid phase change. After the overlying layer of the hydrate reservoir is transformed, a large-scale, stable, and high-mechanical-strength artificial low-permeability layer is formed, which significantly improves 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 forming an artificial low permeability layer using the phase change material of the present invention and the phase change emulsion containing the phase change material, not only the natural gas extraction efficiency and extraction safety are improved, but also, due to the insensitivity of the phase change material to CO2 after solidification, the solidified and sealed CO2 hydrate can be effectively prevented from degrading and escaping into the atmosphere in a complex submarine environment. 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 1 to 5% of the total injection volume of the two, respectively. Preferably, the total amount of the phase change material injected is the same as the total amount of the phase change emulsion.

[0061] In some embodiments, 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 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 by methods in the prior art, and the present invention does not impose any special restrictions on it.

[0062] In some embodiments, the production well is a vertical well, and the injection well is a horizontal well. The number and size of the production well and the injection well can be conventionally adjusted by those skilled in the art, and the present invention does not specifically limit them.

[0063] In some embodiments, the production pressure when the marine gas hydrate reservoir is produced through the production well by using the pressure reduction method is 1 to 4 MPa lower than the phase equilibrium pressure corresponding to the temperature of the marine gas hydrate reservoir. The present invention does not impose any special restrictions on the production temperature, which can be determined by those skilled in the art based on the temperature of the marine gas hydrate reservoir. The specific steps of the pressure reduction method for production can be carried out according to the steps in the prior art, and the present invention does not impose any special restrictions on them.

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

[0065] In some embodiments, the injection temperature when injecting CO2 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 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.

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

[0067] The present invention will be specifically described below by way of examples, but the present invention is not limited to these examples and can of course 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 upper overlying layer: weigh 2.11 kg of quartz sand, mix it with 0.422 kg of water in a mass ratio of 5:1, fill it into the reactor and compact it, then fill 2.065 kg of dry sand on top of it and compact it. After the reactor is installed, introduce methane gas to 12 MPa for leak test. If there is no obvious pressure drop within 12 hours, it is considered that the reactor is airtight and intact, and the methane gas is discharged. Then, a low-temperature circulating water bath was turned on to cool down. The water bath was set to 1°C. When the temperature was balanced, the reactor was 2.7°C. After the temperature was stable, methane gas was introduced into the reactor to 10MPa. After the pressure in the reactor stopped decreasing, the first hydrate generation was considered to be completed. Methane gas was introduced into the reactor again until the pressure reached 10MPa. The hydrate generation was continued to be completed. In order to generate more hydrates, deionized water was then added to the reactor to make the pressure in the reactor reach 12MPa. After waiting for a period of time, the hydrate generation in the reactor was completed. In order to simulate more realistic reservoir conditions, the temperature of the low-temperature circulating water bath was then adjusted to make the temperature in the reactor reach 6°C. It was considered that the preparation process of the natural gas hydrate reservoir and the overlying layer above it was completed.

[0070] Natural gas extraction process: In order to build a non-closed system close to the real environment, the constant pressure mode of the constant speed and constant pressure pump is used to provide 10MPa of constant pressure overlying water to the top inlet of the reactor. The back pressure of the back pressure valve is pre-adjusted to 3MPa, and then the back pressure valve is connected between the outlet of the production well at the bottom of the reactor and the gas-liquid separation tank. Then open the stop valve between the constant speed and constant pressure pump and the reactor and the stop valve between the reactor and the back pressure valve to carry out pressure reduction extraction of the system containing overlying water. During the pressure reduction extraction process, it is necessary to pay attention to the pressure changes of the gas-liquid separation tank and the gas collecting tank connected to it. When it is about to reach 3MPa, the tank cutting operation needs to be carried out. In addition, during the pressure reduction extraction process, the liquid in the gas-liquid separation tank needs to be discharged regularly until the temperature in the reactor returns to the original temperature of 6°C. After the water phase in the gas-liquid separation tank is exhausted, the methane content produced can be calculated based on the temperature and pressure of the gas collecting tank and the gas-liquid separation tank and the volume of the two tanks.

[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 liquid-solid phase transition temperature of the phase change material under normal pressure is 9° C. The phase change material is insoluble in water. After the solid phase change material is immersed in liquid CO2 at 5MPa and 3° C. for 48 hours, its mass loss rate is 0.2%. Figure 2This is a comparison of the solid phase change material before and after being immersed in liquid CO2 for 48 hours. It can be seen that after being immersed in liquid CO2 for 48 hours, the solidified phase change material has no obvious changes, and its mass loss rate is very low, indicating that the phase change material is insensitive to CO2 and has high resistance to CO2 corrosion, which can effectively prevent CO2 from escaping from the sediment and enhance the storage stability and density of CO2.

[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% of n-hexadecane + 30% of 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 a water phase; adding the water phase to the phase change material in 3 batches and performing rapid shearing through a homogenizer, wherein the shearing speed is 15,000 rpm and the time is 10 minutes to obtain the phase change emulsion.

[0076] The liquid-to-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. 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] As a comparison, the liquid-solid phase transition temperature of n-hexadecane under normal pressure was tested to be 18°C. Its phase transition temperature is too high and it is easy to solidify in the pipeline during injection. In addition, the liquid-solid phase transition temperature of n-tridecane under normal pressure was tested to be around -5°C. Its phase transition temperature is too low and it cannot solidify under the conditions of the submarine reservoir. This embodiment uses a combination of n-hexadecane and n-tridecane in a specific ratio, which not only has a suitable phase transition temperature, but also is resistant to CO2 erosion.

[0080] The simulation experiment device used in this embodiment is as follows Figure 4 As shown, the simulation experiment 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, a 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 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 to 12 MPa using gas cylinder 1 for leak test. If there was no obvious pressure drop within 12 hours, it was considered that the reactor 5 was airtight and intact, and the methane gas was discharged. Subsequently, the low-temperature circulating water bath 4 is turned on to cool down, and the water bath is set to 1°C. When the temperature is balanced, the temperature in the reactor 5 is 2.7°C. After the temperature stabilizes, methane gas is introduced into the reactor 5 to 10 MPa. After waiting for the pressure in the reactor 5 to stop decreasing, it is considered that the first hydrate generation is completed. Methane gas is introduced into the reactor 5 again until the pressure reaches 10 MPa, and the hydrate generation is continued to be completed. In order to generate more hydrates, deionized water is then added into the reactor 5 to make the pressure in the reactor 5 reach 12 MPa. After waiting for a period of time, the hydrate generation in the reactor 5 is completed. Then, 0.21 kg of phase change material and 0.21 kg of phase change emulsion were alternately injected into the dry sand layer (simulating the overburden) at an injection volume of 5 mL each time through a horizontal well opened from the top of the reactor 5 to the dry sand layer (using the phase change emulsion injection piston tank 7, the phase change material injection piston tank 8 and the constant speed and constant pressure pump 9 for injection). In order to simulate more realistic reservoir conditions, the temperature of the low-temperature circulating water bath 4 was then adjusted to make the temperature in the reactor 5 reach 6°C. Since the temperature in the reactor 5 is lower than the phase change temperature of the phase change material and the phase change emulsion, the liquid-solid phase change process is completed in the dry sand layer, and an artificial low permeability layer is formed in the overburden above the hydrate reservoir.

[0082] In this embodiment, the total diffusion range of the phase change material and the 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 of Comparative Example 1.

[0084] Figure 5 For comparative example 1 (the upper overlying layer was not modified, Figure 5 (a)) and Example 1 (modification of the upper overlying layer, 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 overlying layer was not modified, Figure 6 (a)) and Example 1 (modification of the upper overlying layer, Figure 6 (b)) shows the change of temperature and pressure curves over time during the depressurization production process. It can be seen that in Example 1, when the overlying layer was not modified, the pressure reduction during the natural gas production process was very slow. This is because the pressure of the overlying water is 10MPa, which has a large pressure difference with the production pressure. Therefore, the overlying water will continue to infiltrate into the hydrate reservoir during the production process, occupying 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 the figure, during the production process of comparative example 1, the pressure gradually decreased until it reached the lowest level at the end of production. 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 pressure of the hydrate reservoir recovered to the same level as the overlying water pressure. Figure 6 It can be found from (b) that after the modification of Example 1, the pressure in the reactor drops rapidly at the beginning of the pressure reduction, and a relatively low production pressure is always maintained during 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, and accelerate gas production while reducing water output.

[0085] Figure 7 For comparative example 1 (the upper overlying layer was not modified, Figure 7 (a)) and Example 1 (modification of the upper overlying layer, Figure 7 (b)) The gas-liquid ratio of production ( Figure 7 gas-water ratio), gas production and liquid production ( Figure 7 The change of the gas production curve (referred to as water production) over time. It can be seen that the gas production curves of Comparative Example 1 and Example 1 both rise rapidly in the initial stage of exploitation, and then gradually slow down. This is because a large amount of free gas is produced in the initial stage, and the later stage mainly comes from the hydrate decomposition gas, which also makes the gas-liquid ratio larger at the beginning. In the same period of time, the liquid production of Comparative Example 1 is much more than that of Example 1. When the exploitation 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 exploitation efficiency. At 166min, the gas-liquid ratio of the output fluid of the reactor 5 of this embodiment is 233ST m3 CH4 / m 3 H2O, with higher natural gas extraction efficiency.

[0086] After the mining process is completed, the back pressure valve 13 at the top of the reactor 5 is set to 5MPa to drive water outward during the liquid CO2 injection process. After that, the liquid CO2 in the liquid CO2 injection piston tank 10 is pushed into the reactor 5 by the constant speed 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 reservoir 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 The sealing density = the mass of CO2 sealed in the reservoir ÷ the volume of the reactor 5. It can be understood by those skilled in the art that when conducting simulation experiments, the displaced fluid contains a large amount of CO2, which is called the CO2 short-circuit phenomenon, that is, CO2 forms a path in the reactor 5.

[0087] Example 2

[0088] This embodiment is basically the same as Embodiment 1, except that the phase change material and the phase change emulsion are different, and 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 includes: 70% of n-hexadecane and 30% of n-tetradecane. The liquid-solid phase transition temperature of the phase change material under normal pressure is 11°C. The phase change material is insoluble in water. After the solid phase change material is immersed in liquid CO2 at 5MPa and 3°C for 48h, its mass loss rate is 0.4%.

[0090] 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 (i.e. 70% of n-hexadecane + 30% of n-tetradecane), 0.11% of Tween 60 and 54.94% of water. The preparation steps of the phase change emulsion are the same as those in Example 1. The liquid-solid phase transition temperature of the phase change emulsion under 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 ST m 3 CH4 / m 3H2O has a higher natural gas extraction efficiency. The CO2 storage density of this embodiment is 155.47kg / m 3 .

[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 remaining steps are the same as Example 1. The phase change material used is the same as that in Example 1.

[0094] At 166 min, the gas-liquid ratio of the output fluid of the reactor of this comparative example is 126 ST m 3 CH4 / m 3 H2O. The CO2 storage density of this comparative example is 124.35kg / 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 remaining 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 ST m 3 CH4 / m 3 H2O. The CO2 storage density of this comparative example is 102.28kg / m 3 .

[0098] Finally, it can be understood that the above embodiments are only for illustrating the technical concept and features of the present invention, and the purpose is to enable ordinary technicians in the field to understand the content of the present invention and implement it accordingly, and it cannot be used to limit the protection scope of the present invention. For ordinary technicians in the field, various modifications and improvements can be made without departing from the principle and essence of the present invention, and these modifications and improvements are also regarded as the protection scope of the present invention.

Claims

1. 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 storage, comprising the following steps: (1) deploying production wells in a marine natural gas hydrate reservoir and deploying injection wells in an overlying layer above the marine natural gas hydrate reservoir; (2) alternately injecting phase change material and phase change emulsion through the injection well, and when the total diffusion range of the phase change material and 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 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%, the transformed overburden is obtained; (3) exploiting the marine natural gas hydrate reservoir through the production well by 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) CO2 is injected through the production well and stored in the form of CO2 hydrate in the natural gas void area of ​​the marine natural gas hydrate reservoir after exploitation.

2. The 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 according to claim 1, 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 5MPa and 3°C for 48 hours, its mass loss rate is 0-0.5%.

3. The 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 according to claim 2, wherein: 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%.

4. The 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 according to claim 1, wherein: Taking the total mass of the phase change emulsion as 100%, it includes: 40-60% of phase change material, 0.1-2% of 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 5MPa and 3° C. for 48 hours, its mass loss rate is 0-0.5%; Preferably, in the phase change emulsion, the phase change material comprises a combination of a first normal alkane and a second normal alkane, the first normal alkane comprises n-hexadecane, and the second normal alkane comprises 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%; Preferably, 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; Preferably, 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 the phase change emulsion to obtain the phase change emulsion.

5. The 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 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 1-5% of the total injection volume of the two respectively.

6. The 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 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.

7. The 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 according to claim 1, wherein: The production well is a vertical well, and the injection well is a horizontal well.

8. The 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 according to claim 1, wherein: When the marine natural gas hydrate reservoir is exploited through the production well by adopting the pressure reduction method, the exploitation pressure is 1 to 4 MPa lower than the phase equilibrium pressure corresponding to the temperature of the marine natural gas hydrate reservoir.

9. The 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 according to claim 1, wherein: The CO2 injected through the production well includes liquid carbon dioxide or emulsion carbon dioxide.

10. The method for reforming marine natural gas hydrate reservoirs by alternately injecting phase change materials and phase change emulsions to enhance natural gas production and carbon sequestration 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 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 overburden after the transformation; 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 exploitation, the injection of CO2 is stopped.

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