Exploitation method for promoting replacement of natural gas hydrate through liquid carbon dioxide fracturing

Abstract

The invention discloses an exploitation method for promoting natural gas hydrate replacement through liquid carbon dioxide fracturing. According to the replacement mining method, carbon dioxide-containing mixed gas is adopted as replacement gas, and a thickening agent is added into the carbon dioxide-containing mixed gas; the mining method is used for a natural gas hydrate reservoir with the hydrate saturation not lower than 40%. The carbon dioxide-containing mixed gas is a mixed gas of carbon dioxide and nitrogen, and the molar content of the nitrogen is not more than 10%; the mixing pressure of the mixed gas containing carbon dioxide is not lower than 15 MPa. According to the liquid carbon dioxide two-stage pressure regulating method provided by the invention, natural gas hydrate reservoir fracturing is realized, and nitrogen and polydimethylsiloxane in the liquid carbon dioxide enter internal pores of the natural gas hydrate reservoir through pressure drop in the first stage; the thickening of liquid carbon dioxide in pores by polydimethylsiloxane in the subsequent fracturing process is facilitated, and meanwhile, the nitrogen is promoted to penetrate into the natural gas hydrate reservoir to participate in the reinforcement of the replacement reaction process.

Description

Technical Field

[0001] The invention relates to a method for promoting natural gas hydrate replacement exploitation by liquid carbon dioxide fracturing, and belongs to the technical field of unconventional oil and gas exploitation. Background Art

[0002] Natural gas hydrate is a solid crystalline substance formed by water and methane under high pressure and low temperature conditions. It is considered by countries around the world to be the most promising clean energy to replace fossil energy. It is widely distributed in sea areas and terrestrial permafrost areas with suitable temperature and pressure conditions, of which more than 90% of natural gas hydrates are distributed in sea areas. The proven reserves of natural gas hydrates are 2×105 billion tons of oil equivalent, which is roughly equivalent to twice the global reserves of fossil fuel resources. In addition, the energy density of natural gas hydrates is 2 to 5 times that of conventional natural gas. It is a clean and efficient energy source and the most likely new energy to replace coal and oil. It has a high research and mining value.

[0003] At present, the main technology for gas hydrate extraction is the depressurization method, which is used to extract gas hydrates by in-situ decomposition of hydrates into free water and natural gas under low pressure. In the crystal structure of gas hydrates, water molecules are connected to each other through hydrogen bonds and form a cage structure to encapsulate gas molecules, while gas molecules act as guest molecules to stabilize the cage structure of water molecules. Since gas molecules and water molecules are not chemically connected to each other, gas hydrates are sensitive to the thermodynamic environment in which they are located and are very likely to undergo endothermic decomposition in temperature and pressure fluctuations to form water and natural gas. Due to its simple principle and low energy consumption, the depressurization extraction technology has been rapidly developed and applied. The United States, Canada, Japan and China have successively used the depressurization method to complete trial extraction of natural gas hydrates on land and in the sea. However, from the analysis of the process of multiple trial extractions, it can be seen that the depressurization extraction technology still faces some technical difficulties that need to be overcome in the entire extraction cycle. For example, in the early stage of depressurization extraction, a large amount of free gas and water produced by the rapid decomposition of hydrates will entrain a large amount of sediment in the flow, and the amount of sediment will increase with the increase of gas production rate. Excessive sand-water production ratio not only limits the gas production rate of a single well, but also threatens the safety of gas flow in the well. Hydrate depressurization test production in the Mackenzie Delta in Canada in 2008 and in the eastern waters of the Nankai Trough in Japan in 2014 were both forced to be interrupted due to sand production accidents. In the middle and late stages of production, the depressurization mining technology also needs to face the downhole pressure fluctuations and reduced gas recovery rate caused by the reduction in hydrate decomposition. In addition, a large amount of adsorbed and free natural gas in the hydrate reservoir cannot be mined due to insufficient diffusion and seepage pressure in the late stage of mining. Similar to traditional coalbed methane mining technology, only 20% to 60% of methane in the reservoir can be recovered by relying solely on depressurization mining. Therefore, although the depressurization mining technology has been used many times in the trial mining stage of natural gas hydrates, the mining process limits it to areas with relatively stable geological structures and high hydrate saturation.

[0004] Carbon dioxide replacement exploitation of natural gas hydrates utilizes the methane-carbon dioxide replacement reaction of hydrates to obtain natural gas components, which can effectively inhibit the production of water and sand during the gas production process. Both carbon dioxide hydrates and methane hydrates are type I hydrates, but in an environment below 12°C, carbon dioxide hydrates have better thermodynamic stability. Therefore, when methane hydrates are in a carbon dioxide environment, carbon dioxide will replace the methane molecules in the hydrate cage structure to form a more stable carbon dioxide hydrate, that is, a methane-carbon dioxide replacement reaction, completing the extraction of natural gas and the storage of carbon dioxide while maintaining the stability of the reservoir structure environment.

[0005] However, there are still a lot of technical bottlenecks in the carbon dioxide replacement mining technology, making it difficult to achieve large-scale application. First, in the study of the mechanism of methane-carbon dioxide replacement reaction, it was found that carbon dioxide tends to replace methane in large cages of hydrates. In a closed system, the maximum replacement amount of carbon dioxide for methane in hydrates is only 64%. Secondly, the replacement reaction is constrained by the specific surface area of ​​hydrates. The replacement rate of large block hydrates will be much lower than that of porous dispersed hydrates. The methane replacement amount ranges from 15% in 800 hours to 50% in 5 hours. In addition, clay expansion and gas channeling caused by pressure gradient fluctuations during the replacement reaction will also cause problems for cementing technology. Therefore, it is necessary to further strengthen the process of carbon dioxide replacement for natural gas hydrates. Summary of the invention

[0006] The purpose of the present invention is to provide a method for promoting the replacement and exploitation of natural gas hydrates by liquid carbon dioxide fracturing, which combines oil and gas reservoir fracturing technology with natural gas hydrate replacement and exploitation technology. According to the basic characteristics of hydrate occurrence, polydimethylsiloxane is added to carbon dioxide as a thickener to improve the viscosity and fracturing performance of liquid carbon dioxide. At the same time, a small amount of nitrogen is added to carbon dioxide to reduce the thermodynamic stability of natural gas hydrates in sediments, accelerate the replacement rate and total replacement amount of methane in hydrates, and finally adopt a two-stage pressure-regulating fracturing method in the fracturing stage, so that the thickener and nitrogen in the liquid carbon dioxide can deeply adhere to the hydrate reservoir around the well wall, which helps to improve the action area of ​​the fracturing network and the replacement reaction.

[0007] The present invention can better solve the problem of low efficiency of current natural gas hydrate replacement mining, and is of great significance to the commercial application of natural gas hydrate replacement mining in the future.

[0008] The present invention provides a method for promoting replacement production of natural gas hydrates by liquid carbon dioxide fracturing, wherein a mixed gas containing carbon dioxide is used as replacement gas, and a thickener is added to the mixed gas containing carbon dioxide;

[0009] The mining method is used for natural gas hydrate reservoirs with a hydrate saturation of not less than 40%.

[0010] Preferably, the carbon dioxide-containing mixed gas is a mixed gas of carbon dioxide and nitrogen, and the molar content of the nitrogen does not exceed 10%;

[0011] The mixed pressure of the carbon dioxide-containing mixed gas is not less than 15 MPa.

[0012] Preferably, the thickener is octamethyltrisiloxane, and the molar concentration of the thickener is not less than 5%.

[0013] Preferably, the mining method comprises a carbon-nitrogen mixing stage, a well injection and fracturing stage, and a well sealing and recovery stage;

[0014] Specifically, the carbon-nitrogen mixing stage comprises the following steps: injecting nitrogen and the thickener into liquid carbon dioxide to mix and keep the carbon dioxide in a liquefied state;

[0015] Preferably, the well injection and fracturing stage comprises the following steps: injecting the modulated liquid carbon dioxide into the natural gas hydrate reservoir and performing reservoir fracturing by adopting two-stage pressure regulation;

[0016] Preferably, the well sealing recovery stage comprises the following steps: gradually controlling the downhole pressure within a specific pressure range of liquid carbon dioxide, gradually reducing it to the reservoir pressure during the recovery stage and completing gas recovery.

[0017] Preferably, in the first stage of the two-stage pressure regulation of the injection well fracturing stage, the pressure of the liquid carbon dioxide is reduced from 15 MPa to 5-8 MPa, and in the second stage, the pressure of the liquid carbon dioxide is increased to the reservoir fracturing pressure;

[0018] The two-stage pressure regulation process in the well injection and fracturing stage is mainly used to accelerate the diffusion of nitrogen in liquid carbon dioxide into the hydrate reservoir. In the first stage pressure regulation process, the liquid carbon dioxide is reduced from 15MPa to 5-8MPa, resulting in a decrease in the solubility of nitrogen in the liquid carbon dioxide, driving the nitrogen to escape from the liquid carbon dioxide and diffuse into the hydrate reservoir. At the same time, due to the amphiphilic properties of polydimethylsiloxane, polydimethylsiloxane follows the nitrogen and adheres to the sediment reservoir, which helps to enhance the fracturing effect of the liquid carbon dioxide on the reservoir after the two-stage pressure regulation.

[0019] The liquid carbon dioxide in the well-blocking recovery stage should not be lower than the pressure of the first stage in the well injection fracturing stage. Although it will sacrifice some recovery efficiency, it plays an important role in ensuring the methane recovery rate during multiple recovery processes. First, the pressure drop during the recovery process will cause part of the nitrogen diffused in the hydrate reservoir to flow back into the liquid carbon dioxide again, causing the liquid bubble point pressure to rise and causing the liquid carbon dioxide to vaporize, which is not conducive to the secondary fracturing. Secondly, the rapid seepage of gas at the edge of the fracture network under the pressure gradient will impact the irregular fracture structure, which is not conducive to maintaining the mechanical stability of the wellbore structure. In addition, the "water lock" effect caused by the rapid escape of pore water gas will gradually reduce the migration of gas in the pores, and block the pores after multiple recovery, resulting in a rapid decrease in methane recovery.

[0020] Research on the mechanism of natural gas hydrate replacement reaction shows that the methane-carbon dioxide replacement reaction in hydrates is mainly affected by the replacement surface area and the driving force of the replacement reaction. Since the methane-carbon dioxide replacement reaction starts from the surface of the hydrate and gradually advances into the interior of the hydrate, the specific surface area of ​​the hydrate is proportional to the rate of the hydrate replacement reaction. In addition, the replacement reaction uses the difference between the fugacity of the gas inside the hydrate phase and its gas phase as the driving force. Maintaining a low methane concentration in the gas phase on the surface of the hydrate helps to accelerate the replacement reaction. However, in actual natural gas hydrate reservoirs, hydrate crystals are tightly packed and attached to the surface of sediment particles, resulting in a significant reduction in the contact area between hydrates and gas. Natural gas hydrates formed naturally by the hydrate replacement reaction are distributed in the pores of the sediments. The flow and diffusion of gas in the sediments are restricted by capillary action and adsorption, resulting in the inability of CH4 produced by hydrate decomposition to be discharged from the pores in time, and CO2 to be replenished in time to the pores where hydrates are stored, further affecting the rate of hydrate replacement reaction.

[0021] The present invention applies liquid carbon dioxide fracturing technology to natural gas hydrate displacement exploitation, and its main advantages are reflected in two aspects. First, reservoir fracturing can greatly increase the contact area between carbon dioxide and natural gas hydrates, thereby improving the displacement rate. Since the methane-carbon dioxide displacement reaction starts from the hydrate surface and gradually advances into the interior of the hydrate, increasing the specific surface area of ​​the hydrate can directly increase the hydrate displacement reaction rate. At the same time, the changes in the concentrations of each gas component on the hydrate surface determine the gas partial pressure, further affecting the driving force for the gas to diffuse into the hydrate phase. Therefore, increasing the carbon dioxide concentration on the hydrate surface helps to strengthen the displacement reaction process.

[0022] The main advantage of the present invention of using liquid carbon dioxide to fractur e the natural gas hydrate reservoir is that the temperature range applicable to the liquid carbon dioxide fracturing technology can better cover the natural gas hydrate reservoir. Natural gas hydrate reservoirs are usually confined to a temperature environment below 10°C, which is not within the temperature applicable range of supercritical carbon dioxide fracturing technology, and hydraulic fracturing is subject to the influence of unfavorable factors such as low-temperature freezing and secondary formation of hydrates.

[0023] The present invention adds nitrogen to liquid carbon dioxide, and its main effects are reflected in two aspects: on the one hand, low concentrations of nitrogen can strongly interfere with the stability of hydrates. The smaller molecular diameter and stronger non-polar characteristics of nitrogen enable it to diffuse rapidly in the hydrate phase driven by the concentration gradient. However, the stabilizing effect of nitrogen molecules on the hydrate cage structure is weak, and its replacement of methane molecules in the small cage structure of the hydrate can not only increase the amount of methane replacement, but also weaken the thermodynamic stability of the hydrate, providing a main and stronger reaction driving force for carbon dioxide to enter and stabilize the hydrate crystal structure. On the other hand, nitrogen has a strong diffusion capacity in the micropores of the sediment, which is conducive to expanding the coverage of the fracture network and the replacement reaction. In the irregular pore network of the sediment, the diffusion rate of nitrogen molecules is 3 to 5 times that of carbon dioxide, and the nitrogen and carbon dioxide mixed gas will form a chromatographic effect and separate. Therefore, nitrogen molecules can quickly expand and connect the pore channels in the sediment, greatly improving the range of reservoir fracturing.

[0024] The present invention mixes nitrogen and polydimethylsiloxane with a molar concentration of no more than 10% into liquid carbon dioxide at a pressure of no less than 15MPa to prevent high concentrations of nitrogen from causing the liquid carbon dioxide to approach the bubble point pressure. At the same time, excess nitrogen will inhibit the exchange of methane and carbon dioxide in the pores of the sediment and reduce the reaction rate. Since the viscosity of liquid carbon dioxide is further reduced by the addition of nitrogen, polydimethylsiloxane needs to be added to the liquid carbon dioxide as a thickener to improve the anti-filtration property of liquid carbon dioxide during the fracturing process. The effect of polydimethylsiloxane on the thermal properties of hydrates is extremely weak, and it will not have a significant inhibitory effect on the methane-carbon dioxide replacement reaction in hydrates.

[0025] The method for promoting natural gas hydrate replacement exploitation by liquid carbon dioxide fracturing of the present invention is applied to hydrate reservoirs with a hydrate saturation of not less than 40%, and is mainly aimed at the blockage of the migration channels of methane and carbon dioxide in the sediments caused by excessive free water in the sediments, which results in the formation of carbon dioxide hydrates by part of the free water and liquid carbon dioxide in the pores or cracks. When the hydrate saturation is not less than 40%, the free water in the sediment pores is mainly attached to the surface of the sediment particles by adsorption or hydrogen bonding, and will not cause the free flow of pore water, thereby ensuring the smooth migration of gas in the pore and crack networks.

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

[0027] (1) The present invention proposes a technical method for enhancing the displacement production of natural gas hydrates based on the basic principle of the methane-carbon dioxide displacement reaction in hydrates.

[0028] (2) The present invention adopts liquid carbon dioxide fracturing technology to increase the gas-solid two-phase contact area during the hydrate replacement reaction by building a natural gas hydrate reservoir fracture network, thereby enhancing the natural gas hydrate replacement production rate.

[0029] (3) The present invention proposes dissolving nitrogen and polydimethylsiloxane into liquid carbon dioxide, weakening the thermal stability of natural gas hydrates through nitrogen, enhancing the total amount of natural gas hydrate replacement production, and increasing the spatial range of the natural gas hydrate reservoir fracture network.

[0030] (4) The present invention proposes a two-stage pressure regulation method for liquid carbon dioxide to achieve natural gas hydrate reservoir fracturing. The pressure drop in the first stage allows nitrogen and polydimethylsiloxane in the liquid carbon dioxide to enter the internal pores of the natural gas hydrate reservoir, which is beneficial for the polydimethylsiloxane to thicken the liquid carbon dioxide in the pores during the subsequent fracturing process, and at the same time promotes nitrogen to penetrate into the natural gas hydrate reservoir to participate in the strengthening of the replacement reaction process. BRIEF DESCRIPTION OF THE DRAWINGS

[0031] Figure 1 The present invention is a flow chart of the method for promoting natural gas hydrate replacement production by liquid carbon dioxide fracturing.

[0032] Figure 2 Phase equilibrium of CH4 and CO2 hydrate in quartz sand with a water saturation of 30% and a CO2 thickener of 5.5wt%.

[0033] Figure 3 is the recovery rate of CH4 in the CH4-CO2 replacement reaction.

[0034] Figure 4 Schematic diagram of the geometric boundary of CO2 storage simulation.

[0035] Figure 5 This is the distribution cloud diagram of CO2 injected into the reservoir at different N2 concentrations after 5 years.

[0036] Figure 6 The change of CO2 Darcy velocity field before and after CO2 seepage fracturing.

[0037] Figure 7 The change of Darcy velocity in sediment fractures and pores before and after CO2 fracturing. DETAILED DESCRIPTION

[0038] Unless otherwise specified, the experimental methods used in the following examples are conventional methods.

[0039] Unless otherwise specified, the materials and reagents used in the following examples can be obtained from commercial sources.

[0040] like Figure 1 The figure shows a flow chart of the method for promoting replacement and exploitation of natural gas hydrates by liquid carbon dioxide fracturing of the present invention, which includes three stages: carbon-nitrogen mixing, well injection fracturing and well blocking recovery. In the carbon-nitrogen mixing stage, a certain amount of nitrogen and thickener are injected into the liquid carbon dioxide to fully mix and keep the carbon dioxide in a liquefied state; in the well injection fracturing stage, the modulated liquid carbon dioxide is injected into the natural gas hydrate reservoir and the reservoir fracturing is completed by two-stage pressure regulation; in the well blocking recovery stage, the downhole pressure is gradually controlled within the specific pressure range of the liquid carbon dioxide, and in the recovery stage, it is gradually reduced to the reservoir pressure and the gas recovery is completed.

[0041] The method of the present invention adopts a carbon dioxide-containing mixed gas as a replacement gas, and adds a thickener to the carbon dioxide-containing mixed gas, wherein the carbon dioxide-containing mixed gas is a mixed gas of carbon dioxide and nitrogen, the molar content of the nitrogen does not exceed 10%, and the thickener is polydimethylsiloxane, and the molar concentration of the thickener in the carbon dioxide-containing mixed gas is not less than 5%.

[0042] The method of the present invention mixes nitrogen and polydimethylsiloxane with a molar concentration of no more than 10% into liquid carbon dioxide at a pressure of no less than 15MPa to prevent high concentrations of nitrogen from causing the liquid carbon dioxide to approach the bubble point pressure. At the same time, excess nitrogen will inhibit the exchange of methane and carbon dioxide in the pores of the sediment and reduce the reaction rate. Since the viscosity of liquid carbon dioxide is further reduced by the addition of nitrogen, polydimethylsiloxane needs to be added to the liquid carbon dioxide as a thickener to improve the anti-filtration property of liquid carbon dioxide during the fracturing process. The effect of polydimethylsiloxane on the thermal properties of hydrates is extremely weak, and it will not have a significant inhibitory effect on the methane-carbon dioxide replacement reaction in hydrates.

[0043] The second-stage pressure regulation process in the well injection and fracturing stage is mainly used to accelerate the diffusion of nitrogen in liquid carbon dioxide into the hydrate reservoir. In the first-stage pressure regulation process, the liquid carbon dioxide is reduced from 15MPa to 5-8MPa, resulting in a decrease in the solubility of nitrogen in liquid carbon dioxide, driving nitrogen to escape from the liquid carbon dioxide and diffuse into the hydrate reservoir. At the same time, due to the amphiphilic properties of polydimethylsiloxane, polydimethylsiloxane follows nitrogen and adheres to the sediment reservoir, which helps to enhance the fracturing effect of liquid carbon dioxide on the reservoir after the second-stage pressure regulation.

[0044] The downhole pressure of liquid carbon dioxide in the well-blocking recovery stage is not lower than the downhole pressure in the first stage of the injection and fracturing stage. First, the pressure drop during the recovery process will cause part of the nitrogen diffused in the hydrate reservoir to flow back into the liquid carbon dioxide again, causing the liquid bubble point pressure to rise and causing the liquid carbon dioxide to vaporize, which is not conducive to the secondary fracturing. Secondly, the rapid seepage of gas at the edge of the fracture network under the pressure gradient will impact the irregular fracture structure, which is not conducive to maintaining the mechanical stability of the wellbore structure. In addition, the "water lock" effect caused by the rapid escape of pore water gas will gradually reduce the migration of gas in the pores, and block the pores after multiple recovery, resulting in a rapid decrease in methane recovery.

[0045] According to the test of the present invention, thickeners DL-lactic acid, polyvinyl acetate, ethyl trifluoroacetate and octamethyltrisiloxane all have a promoting effect on CO2 displacement production, among which octamethyltrisiloxane has the best promoting effect on the displacement production rate. Figure 2 The thermodynamic effects of DL-lactic acid, polyvinyl acetate, ethyl trifluoroacetate and octamethyl trisiloxane on CH4 hydrate and CO2 hydrate. In the presence of polyvinyl acetate, ethyl trifluoroacetate and octamethyl trisiloxane, the equilibrium of CH4 or CO2 hydrate overlaps with the equilibrium without CO2 thickener, indicating that polyvinyl acetate, ethyl trifluoroacetate and octamethyl trisiloxane have no inhibitory effect on CH4 or CO2 hydrate. In the presence of DL-Lactic acid, the equilibrium curves of CH4 and CO2 hydrates shift to the left, indicating the thermodynamic inhibitory effect of DL-Lactic acid on CH4 and CO2 hydrates. However, the temperature reduction caused by the addition of 5.5wt% DL-lactic acid has only about 0.52 and 0.48K on CH4 and CO2 hydrates, respectively, which is equivalent to the inhibitory effect of about 1.0wt% NaCl solution. Therefore, the CO2 thickener tested in the present invention has limited thermodynamic effect on CH4-CO2 replacement in the hydrate phase.

[0046] Figure 3 The CH4 produced from hydrates under different concentrations of thickeners varies with time. For the system containing DL-lactic acid, the total CH4 production decreased from 53% to 46% as the DL-lactic acid concentration increased to 5.5wt%, indicating that DL-lactic acid is not suitable for enhancing CH4-CO2 replacement. For the system containing polyvinyl acetate, ethyl trifluoroacetate and octamethyltrisiloxane, the CH4 recovery rate increased from about 55% to 74% and above, which is much higher than the traditional theoretical value (64%). Specifically, it was found that the total CH4 production increased linearly with the concentration of polyvinyl acetate and ethyl trifluoroacetate, while the addition of 3.5wt% octamethyltrisiloxane was sufficient to increase the total CH4 production to 74%. Therefore, octamethyltrisiloxane is considered to be more suitable for improving CH4 recovery, especially at low concentrations.

[0047] Example 1: Gas component preparation

[0048] This example simulates the process of changing the seepage of mixed gas in hydrate-containing reservoirs by changing the gas component allocation. According to the porous medium multiphase flow model, the gas-liquid seepage control equation in heterogeneous sediments is established, and the hydrate growth kinetic equation is used as the source term of the gas-liquid seepage control equation, where the basic equation of methane in liquid phase A and gas phase G can be expressed as:

[0049]

[0050] The mass conservation equation of pore water in liquid phase A and gas phase G without considering the effects of its own gravity and capillary adsorption can be expressed as:

[0051]

[0052] where q H is the hydrate generation rate, which can be expressed as follows based on the gas consumption rate during the hydrate growth process:

[0053]

[0054] in, is the porosity of porous media, S j is the saturation of phase j in the porous medium, ρ j is the density of phase j, X j is the mole fraction of CO2 in phase j, υ j is the volume flow rate of CO2 in phase j, J j is the diffusion flux of methane in phase j, q m and q w are the mass source and sink of CO2 and water molecules respectively. Formula (2,3) is expressed by P and S j The parameters such as , are coupled with each other to achieve a comprehensive description of gas-liquid migration in porous media. The basic physical properties of the reaction system are shown in Table 1.

[0055] Table 1 Basic physical properties and initial conditions of each phase in the reaction system

[0056]

[0057]

[0058] The effect of N2 concentration in liquid CO2 on the hydrate phase equilibrium pressure can be determined based on the van der Waals-Platteeuw model. Based on the fitting curve and combined with the PR gas state equation, the hydrate phase equilibrium fugacity f in formula (3) is obtained: eq (MPa) and N2 concentration:

[0059]

[0060] At the same time, the effect of N2 concentration on the viscosity of liquid CO2 The following formula is used to express:

[0061]

[0062] This example simulates the diffusion and hydrate growth of CO2 in a reservoir with a radius of 5500m and a thickness of 100m. The basic geometric boundary settings are as follows: Figure 4 shown.

[0063] Figure 5 This is a distribution cloud map of CO2 injected into the reservoir for 5 years at different N2 concentrations. It can be seen that with the increase of the N2 mole fraction in the liquid CO2, the diffusion range of CO2 increases rapidly. The main reason is that the rapid generation of CO2 hydrates near the wellbore inhibits the CO2 seepage, making it difficult for CO2 to diffuse rapidly in the horizontal direction. The addition of N2 inhibits the formation of hydrates in the seepage channel, especially after the gas components are separated during the seepage process. The enrichment of N2 at the seepage front and the displacement of pore water not only reduce the seepage resistance but also further increase the phase equilibrium pressure required for hydrate formation, thereby inhibiting the formation of hydrates.

[0064] Example 2: Injection and Fracturing

[0065] This example simulates the process of changing the seepage of mixed gas in a hydrate-containing reservoir by increasing the injection pressure of liquid CO2. The model includes seepage stress coupling of fractured rock mass under triaxial stress state. The basic physical property parameters of each phase in the reaction system are the same as those in Implementation Example 1. The geometric dimensions and initial conditions of the reaction system are shown in Table 2.

[0066] Table 2 Basic physical parameters and initial conditions of each phase in the reaction system

[0067]

[0068]

[0069] In this embodiment, the injection pressure was increased from 7MPa to 15MPa and then decreased to 7MPa, and the change in the Darcy velocity of CO2 in the sediment was observed to determine the change in the seepage performance of the sediment caused by liquid CO2 fracturing. Figure 6 It can be seen that as the CO2 injection pressure increases, the Darcy seepage rate of CO2 is greatly improved. At the same time, when the injection pressure returns to the initial pressure, the flow rate of CO2 in the sediment is also improved. Figure 7It can be further seen that the CO2 fracturing effect increases the Darcy seepage rate of CO2 in the sediment pores by about 13 times, from 5×10 -6 m / s increased to 6.7×10 -5 m / s, while the Darcy seepage rate of CO2 in the fracture is only 7×10 -6 m / s increased to 2.2×10 -5 m / s. After the injection pressure returned to the initial pressure, the Darcy seepage rate of CO2 in the sediment pores could still reach 2.4×10 -5 m / s, which is about 5 times that before fracturing, and the Darcy seepage rate of CO2 in the fractures can also be increased to 3 times. Therefore, liquid CO2 injection and fracturing can improve reservoir permeability and increase CO2 storage density.

[0070] Embodiment 3,

[0071] The reservoir conditions suitable for the growth of CO2 hydrates are formation temperature of 4°C, pore pressure of 7MPa, and sediment permeability of 80mD. Before the injection of liquid CO2, lactic acid or polyethyl acetate with a mass concentration of 5wt% is injected into the liquid CO2. Since the permeability of the sediment is higher than 800mD, air is injected into the liquid CO2 at this time to make the molar fraction of air in the liquid CO2 reach 3%. Subsequently, the prepared liquid CO2 is injected into the reservoir suitable for the growth of CO2 hydrates along the wellbore at a pressure of 10MPa. In the reservoir near the injection wellbore, air has three effects. First, the presence of air makes the liquid CO2 have lower viscosity, which is conducive to the seepage and diffusion of liquid CO2 in the sediment. Secondly, the presence of air increases the formation pressure of CO2 hydrates, making it difficult for CO2 hydrates to form near the wellbore. Therefore, liquid pore water will not solidify near the wellbore to form hydrates and block the gas seepage channels in the sediment. Third, the diffusion rate of air is much higher than that of liquid CO2. After seeping for a certain distance, it will gradually separate from liquid carbon dioxide and be enriched at the front of the gas seepage diffusion area driven by the seepage pressure, participating in the displacement of pore water in the sediment. The decrease in the pore water content in the sediment reduces the water saturation of the sediment, increases the phase equilibrium pressure of the hydrate, and makes it more difficult for CO2 hydrate to form in the sediment. The inhibitory effect on the growth of CO2 hydrate near the wellbore at this stage ensures that CO2 hydrate is unobstructed in the gas seepage channel near the wellbore, avoiding the problem of liquid CO2 being unable to be injected in the early stage of storage.

[0072] After the liquid carbon dioxide is injected for a certain period of time, at an injection pressure of 10 MPa, the injection flux Q of the liquid carbon dioxide is continuously recorded and combined with the following formula to solve the permeability K in the sediment.

[0073]

[0074] Q is the CO2 injection flux (kg / h), μ is the dynamic viscosity coefficient of the air-CO2 mixed gas ΔP is the difference between the current CO2 injection pressure and the injection pressure 1 hour before the flow rate Q changes (Pa), L is the effective gas seepage length (m), and A is the effective cross-sectional area of ​​the wellbore (m 2 ), Ka is the permeability. In practical applications, L, A and μ are all constants, while K is the permeability. a It is also a constant in a constant flow field. Therefore, based on formula (6), the CO2 permeability K of the sediment can be obtained by adjusting the injection pressure to obtain a linear relationship between the CO2 injection flux Q and ΔP, where K is the slope value between Q and ΔP.

[0075] When the K value is less than 120mD and the injection flux Q of liquid carbon dioxide is lower than 40-70% of the normal injection flux, it indicates that CO2 hydrates in the sediments begin to form inevitably and block the seepage channels. Therefore, based on the above situation, well fracturing is started, and the injection pressure of liquid carbon dioxide is increased to 16MPa and kept constant. After a period of pressure conduction, liquid carbon dioxide completes the fracturing of sediments with the help of a local higher pressure gradient difference and forms a fracture network in the sediment layer. At this time, the permeability in the sediment is greatly improved, and at the same time, the seepage flux is increased again. When the liquid carbon dioxide injection flux is 20-50% higher than the normal injection flux, fracturing is stopped and the injection pressure is adjusted to 10MPa again to avoid significant damage to the mechanical structure of the reservoir caused by fracturing. Well fracturing accompanies the entire process of subsequent liquid carbon dioxide injection until the set total amount of carbon dioxide storage is reached.

Claims

1. A method for promoting natural gas hydrate replacement and mining by liquid carbon dioxide fracturing, characterized in that: Using a mixed gas containing carbon dioxide as a replacement gas, and adding a thickener to the mixed gas containing carbon dioxide; The mining method is used for natural gas hydrate reservoirs with a hydrate saturation of not less than 40%.

2. The mining method according to claim 1, characterized in that: The carbon dioxide-containing mixed gas is a mixed gas of carbon dioxide and nitrogen, and the molar content of the nitrogen does not exceed 10%; The mixed pressure of the carbon dioxide-containing mixed gas is not less than 15 MPa.

3. The mining method according to claim 1 or 2, characterized in that: The thickener is octamethyltrisiloxane; In the carbon dioxide-containing mixed gas, the molar concentration of the thickener is not less than 5%.

4. The mining method according to any one of claims 1 to 3, characterized in that: The mining method comprises a carbon-nitrogen mixing stage, a well injection and fracturing stage and a well sealing and recovery stage.

5. The mining method according to claim 4, characterized in that: The carbon-nitrogen mixing stage comprises the following steps: injecting nitrogen and the thickener into liquid carbon dioxide to mix and keep the carbon dioxide in a liquefied state; The well injection and fracturing stage comprises the following steps: injecting the modulated liquid carbon dioxide into the natural gas hydrate reservoir and performing reservoir fracturing by adopting two-stage pressure regulation; The well sealing recovery stage includes the following steps: gradually controlling the downhole pressure within the specific pressure range of liquid carbon dioxide, gradually reducing it to the reservoir pressure during the recovery stage and completing gas recovery.

6. The mining method according to claim 5, characterized in that: In the first stage of the two-stage pressure regulation of the injection and fracturing stage, the pressure of the liquid carbon dioxide is reduced from 15 MPa to 5-8 MPa, and in the second stage, the pressure of the liquid carbon dioxide is increased to the reservoir fracturing pressure.

7. The mining method according to claim 6, characterized in that: The pressure of liquid carbon dioxide in the well sealing recovery stage should not be lower than the pressure of the first stage in the well injection and fracturing stage.

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