A functional microemulsion and a method for preventing sand production in muddy silt hydrate reservoirs

Abstract

The present invention discloses a functional microemulsion and a method for preventing sand production in muddy silt hydrate reservoirs. The method includes the following steps: Step 1, matrix acidification and plugging removal of the reservoir; Step 2, injection of the functional microemulsion. On the basis of conventional matrix acidification and plugging removal, the present invention adds a functional microemulsion sand consolidation and sand prevention system, uses an exothermic external solution to control the cementation of the nanoscale internal cementation solution with the reservoir skeleton, strengthens the strength of the reservoir matrix skeleton, adsorbs free sand particles, and achieves the purpose of reservoir sand consolidation and sand prevention, thereby reducing the pollution of hydrates, increasing the permeability, and greatly improving the productivity. The functional microemulsion is composed of an exothermic external solution, an internal cementation solution, and a system stabilizer. Its nanoscale internal cementation solution forms dot-like cementation with the pore throats of the reservoir, avoiding the disadvantages of plugging the pore throats in conventional chemical sand prevention; at the same time, the exothermic external solution is used to control the demulsification and cementation timing of the system, providing convenience for on-site engineering applications.

Description

Technical Field

[0001] The present invention relates to the technical field of sand control in hydrate reservoirs, and specifically relates to a functional microemulsion and a method for sand control in argillaceous silt hydrate reservoirs. Background Art

[0002] Natural gas hydrate is an ice-like crystalline substance formed by natural gas and water under high pressure and low temperature conditions, and is mainly distributed in deep-sea sediments or permafrost regions on land. Because of its ice-like appearance and the ability to burn when encountering fire, it is also known as "flammable ice". Flammable ice has extremely high resource value due to its wide distribution range, huge reserve scale, and high energy density, and has attracted much attention from countries around the world. It is a hot topic of long-term research by experts and scholars at home and abroad.

[0003] In 2017 and 2020, China successfully carried out two natural gas hydrate production tests in the South China Sea, achieving remarkable results. The key technologies for horizontal well drilling and production in deep-sea shallow soft formations have been overcome, and the production period scale has been greatly improved, laying a technical foundation for production tests and industrial development, and making China the first country in the world to test the production of natural gas hydrates in the sea area using horizontal well drilling and production technology. Nevertheless, due to the high clay content and rich sensitive minerals in the natural gas hydrate reservoirs in China's sea areas, drilling pollution is inevitable; and during the long-term development process, the backflow of formation sand after the decomposition of hydrates is inevitable. For natural gas hydrate reservoirs, the main sand control processes at home and abroad are mainly mechanical sand control processes such as sand control screens and gravel packing. However, mechanical sand control has poor adaptability to fine silt formations and has a certain impact on reservoir productivity, restricting its on-site application effect. The conventional chemical sand consolidation method is a sand control method that squeezes chemical cementing fluid into the formation sand in the sand-producing section around the wellbore in a natural loose formation. However, since the chemical cementing fluid can block some of the reservoir matrix pores and throats while consolidating the sand, the reservoir permeability is reduced, affecting productivity. Summary of the Invention

[0004] The purpose of the present invention is to propose a method for sand control in argillaceous silt hydrate reservoirs.

[0005] Another purpose of the present invention is to provide a functional microemulsion.

[0006] To solve the above technical problems, the technical solutions adopted by the present invention are as follows:

[0007] A method for sand control in argillaceous silt hydrate reservoirs includes the following steps:

[0008] Step 1. Matrix acidizing and plugging removal of the reservoir: Inject the acidizing working fluid into the matrix area near the wellbore in the argillaceous silt hydrate reservoir, and use the acidizing working fluid to remove the solid particles in the drilling fluid in the matrix near the wellbore. At the same time, use the acidizing working fluid to etch the walls of the pores and pore throats in the argillaceous silt hydrate reservoir and dissolve the plugging particles in the pore throats to increase the radius of the pores and pore throats and improve the seepage capacity of the argillaceous silt hydrate reservoir.

[0009] Step 2. Injection of functional microemulsion: Inject the functional microemulsion into the matrix area near the wellbore in the argillaceous silt hydrate reservoir to ensure that the functional microemulsion seeps into the pore throats of the argillaceous silt hydrate reservoir; use the exothermic liquid in the functional microemulsion to undergo a chemical reaction in the pore throats to generate heat to increase the environmental temperature in the matrix pore throats. After the environmental temperature rises, the critical micelle concentration of the system stabilizer increases significantly, resulting in the concentration of the surfactant in the microemulsion system in the pore throats being lower than the critical micelle concentration under the current temperature conditions, and the functional microemulsion demulsifies; use the internal phase cementing liquid in the functional microemulsion to directly contact the walls of the pore throats and undergo cementing to enhance the strength of the matrix skeleton, prevent the pore throats from collapsing and sand production, and at the same time, the internal phase cementing liquid also undergoes cementing with the sediment particles in the pore throats to control and reduce the sand production volume.

[0010] Further, in the above Step 1, the dosage S of the acidizing working fluid is calculated by the following formula:

[0011] S = πr 2 Hφ, where r is the acidizing radius of the reservoir, H is the length of the acidizing interval, and φ is the porosity of the reservoir.

[0012] Further, in the above Step 1, if the drilling pollution radius < the sand consolidation radius of the reservoir, then select the sand consolidation radius of the reservoir as the acidizing radius of the reservoir; if the drilling pollution radius ≥ the sand consolidation radius of the reservoir, then select the drilling pollution radius as the acidizing radius of the reservoir.

[0013] Further, the injection pressures of both the acidizing working fluid and the functional microemulsion are lower than the fracture pressure of the argillaceous silt hydrate reservoir. The main purpose is to ensure that both the acidizing working fluid and the functional microemulsion can penetrate radially into the reservoir matrix, realizing uniform acidizing and plugging removal of the matrix near the wellbore of the reservoir and dispersed internal phase cementing for sand control, so as to avoid the formation of artificial fractures in the reservoir under high pressure, which may lead to non-uniform consolidation and sand control in the near-wellbore area during subsequent operations.

[0014] Further, in step 2, the heat generated by the chemical reaction of the exothermic liquid in the functional microemulsion in the pore throats causes the hydrates in the argillaceous silt hydrate reservoir to decompose, releasing free water. The free water dissolves in the exothermic liquid of the functional microemulsion, which will further reduce the concentration of the system stabilizer in the microemulsion system to accelerate demulsification. The dosage G of the functional microemulsion is calculated by the following formula:

[0015] G = πr 2 Hφ, where r is the acidification radius of the reservoir, H is the length of the acidified well section, and φ is the porosity of the reservoir.

[0016] Further, the acidification working fluid used is an aqueous solution containing 10% by weight of HCL and 3% of HF.

[0017] A functional microemulsion is composed of an exothermic liquid, an internal phase cementing liquid, and a system stabilizer. The internal phase cementing liquid is dispersed in the exothermic liquid in the form of nanoparticles. Among them, the percentage content of the internal phase cementing liquid by volume is 50%-70%, and the balance is the exothermic liquid and the system stabilizer. The system stabilizer is 1%-5% by weight percentage of the exothermic liquid; the exothermic liquid is the continuous phase, including a heat generating agent, a delayed heat generation control agent, a clay inhibitor, and a hydrate inhibitor. Among them, the weight percentage content of the heat generating agent is 5%-10%, the weight percentage content of the delayed heat generation control agent is 1%-5%, the weight percentage content of the clay inhibitor is 1%-5%, and the weight percentage content of the hydrate inhibitor is 1%-5%. The balance is water. The delayed heat generation control agent is used to control the heat generation timing of the heat generating agent to ensure that the heat generating agent generates heat in the pore throats of the argillaceous silt hydrate reservoir; the internal phase cementing liquid is the dispersed phase, mainly including a silane coupling agent, which is used to cement with mud sand particles and rock walls; the system stabilizer generally uses an amphoteric surfactant, which is used for demulsification and ensures that the internal phase cementing liquid is stably dispersed in the exothermic liquid in the form of nanoparticles.

[0018] Further, the particle size of the nanoparticles in which the internal phase cementing liquid is dispersed in the exothermic liquid is 0.1-1nm.

[0019] Further, the preparation method of the functional microemulsion is as follows: First, prepare the exothermic liquid, and add a clay inhibitor, a hydrate inhibitor, a heat generating agent, and a delayed heat generation control agent in proportion in a brine equivalent to the formation water salinity; Second, slowly add the system stabilizer to the exothermic liquid and mechanically stir to dissolve the system stabilizer in the exothermic liquid; Third, slowly add the internal phase cementing liquid to the exothermic liquid at a high stirring speed; Finally, after the addition of the internal phase cementing liquid is completed, continue to use a high-pressure homogenizer to break the internal phase cementing liquid into nanosize and uniformly disperse it in the exothermic liquid.

[0020] Furthermore, the content of the internal phase cementing liquid particles in the functional microemulsion satisfies that the sand production amount of the reservoir after consolidation is reduced to the lowest, and the reservoir permeability is not lower than the original permeability.

[0021] The beneficial effects of the present invention are as follows:

[0022] The present invention discloses a method for sand control in a muddy silt hydrate reservoir. Based on the conventional matrix acidizing and plugging removal, a functional microemulsion sand consolidation and sand control system is added. The external heat-generating liquid is used to control the cementation of the nanoscale internal phase cementing liquid with the reservoir skeleton, strengthen the strength of the reservoir matrix skeleton, adsorb free sand particles, and achieve the purpose of reservoir sand consolidation and sand control. Thereby, the migration and blockage of solid-phase particles in the near-wellbore zone of the hydrate reservoir are reduced, the reservoir seepage capacity is improved, and the single-well production capacity and stable production period are greatly increased.

[0023] Compared with the conventional chemical sand control, the present invention innovatively designs a functional microemulsion system. The nanoscale internal phase cementing liquid forms dot-like cementation with the pore throats of the reservoir, avoiding the disadvantages of blocking the pore throats in the conventional chemical sand control. At the same time, the external heat-generating liquid is used to control the demulsification and cementation timing of the system, providing convenience for on-site engineering applications. Description of the Drawings

[0024] The present invention is further described with reference to the accompanying drawings. However, the embodiments in the drawings do not constitute any limitation to the present invention. For those of ordinary skill in the art, without creative efforts, other drawings can also be obtained according to the following drawings:

[0025] Figure 1 It is a state diagram of a vertical well drilling through the hydrate layer before the implementation of the present invention;

[0026] Figure 2 It is a schematic diagram of the microscopic structure of a functional microemulsion according to the present invention;

[0027] Figure 3 It is a schematic diagram of the unconsolidated original matrix area of the muddy silt hydrate reservoir according to the present invention;

[0028] Figure 4 It is a schematic diagram of the cementation of the matrix area in the near-wellbore zone of the muddy silt hydrate reservoir according to the present invention.

[0029] In the figure: 1 - production casing; 2 - injection tubing; 3 - packer; 4 - perforation hole; 5 - external heat-generating liquid; 6 - internal phase cementing liquid; 7 - system stabilizer; 8 - rock skeleton; 9 - hydrate; 10 - pore throat; 11 - dot-like cementation state; 12 - decomposed gas. Detailed Embodiments

[0030] To enable those skilled in the art to better understand the technical solution of the present invention, the present invention will be further described in detail below in conjunction with the accompanying drawings and specific embodiments. It should be noted that, without conflict, the embodiments of the present application and the features in the embodiments may be combined with each other.

[0031] In the description of the present invention, it should be understood that the orientation or positional relationship indicated by the terms "center", "longitudinal", "transverse", "length", "width", "thickness", "upper surface", "lower surface", "front", "rear", "left", "right", "vertical", "horizontal", "top", "bottom", "inner", "outer", "forward rotation", "reverse rotation", "axial direction", "radial direction", "circumferential direction", etc. is based on the orientation or positional relationship shown in the accompanying drawings. It is only for the convenience of describing the present invention and simplifying the description, rather than indicating or implying that the device or element referred to must have a specific orientation, be constructed and operated in a specific orientation, and therefore should not be construed as a limitation to the present invention.

[0032] As Figure 1 shown, in a certain sea area, the burial depth of the natural gas hydrate reservoir is 300 mbsf, the reservoir thickness is 20 m, the porosity is 35%, the permeability is 20 mD, the reservoir temperature is 20 °C, and the reservoir pressure is 20 MPa. In order to effectively utilize the production capacity of the natural gas hydrate reservoir, a vertical well is drilled through the hydrate layer. First, a vertical well is established. After the production casing 1 is installed, an injection tubing 2 and a packer 3 are lowered into the vertical well production casing 1. The injection tubing 2 is lowered to the top of the hydrate reservoir, and the packer 3 is set in the overlying layer of the hydrate reservoir to seal the annulus between the oil casing, providing an injection fluid channel for matrix acidification and functional microemulsion injection for reservoir plugging removal, and a flow channel between the hydrate reservoir and the production casing 1 is established by using the perforation holes 4. In the natural gas hydrate reservoir shown in the figure, three sand control zones, namely Zone A, Zone B, and Zone C, are divided.

[0033] The natural gas hydrate reservoir mainly consists of a rock skeleton 8, hydrates 9 inside the pore throats 10, and formation fluids, as Figure 3 shown. In order to ensure that the reservoir does not produce large-scale sand production during the production process of the production well, a functional microemulsion sand control operation is designed for this well.

[0034] The specific method for sand control of a muddy silt hydrate reservoir in this patent includes the following steps:

[0035] Step 1, matrix acidification and plugging removal of the reservoir: An acidification working fluid is injected into the matrix area near the wellbore in the muddy silt hydrate reservoir. The acidification working fluid used is an aqueous solution containing 10% by weight of HCL and 3% of HF.

[0036] Determine the dosage S of the injected acidification working fluid: Its calculation formula is as follows:

[0037] S = πr2 Hφ = 3.14×0.5²×20×0.35 ≈ 5.5 m 3 , where r is the acidification radius of the reservoir. When the drilling pollution radius < the sand consolidation radius of the reservoir, the sand consolidation radius of the reservoir is selected as the acidification radius of the reservoir; if the drilling pollution radius ≥ the sand consolidation radius of the reservoir, the drilling pollution radius is selected as the acidification radius of the reservoir. In the embodiment of this patent, the drilling pollution radius 0.3 m < the sand consolidation radius 0.5 m, and the acidification radius r of the reservoir = 0.5 m; the length of the acidification interval is the reservoir thickness 20 m, and φ is the reservoir porosity of 35%.

[0038] Determine the injection pressure of the acidification working fluid: Use a surface high-pressure pump to pump 5.5 m of the acidification working fluid downhole through the injection tubing 2 3 At the same time, considering that the fracture pressure of the argillaceous silt hydrate reservoir is 22 MPa, during the injection of the acidification working fluid, the injection pressure of the acidification working fluid < 22 MPa. The main purpose is to ensure that the acidification working fluid can penetrate into the reservoir matrix radially, realize the uniform acidification and plug removal of the matrix in the near-wellbore zone of the reservoir, so as to avoid the formation of artificial fractures in the reservoir under high pressure and then lead to non-uniform consolidation and sand control in the near-wellbore zone during subsequent operations.

[0039] After the injection of the acidification working fluid is completed, just displace it in place. Use the acidification working fluid to remove the solid particles in the drilling fluid in the matrix of the near-wellbore zone, and at the same time use the acidification working fluid to etch the wall surface of the holes and pore throats 10 in the argillaceous silt hydrate reservoir and dissolve the plugging particles in the pore throats 10 to increase the radius of the holes and pore throats and improve the seepage capacity of the argillaceous silt hydrate reservoir.

[0040] Step 2: Inject the functional microemulsion: Inject the functional microemulsion into the matrix area of the near-wellbore zone in the argillaceous silt hydrate reservoir to ensure that the functional microemulsion seeps into the pore throats of the argillaceous silt hydrate reservoir.

[0041] Such as Figure 2As shown, the functional microemulsion is composed of an external heat - generating fluid 5, an internal phase cementing fluid 6, and a system stabilizer 7. The internal phase cementing fluid is dispersed in the external heat - generating fluid in the form of nanoparticles. The content of the internal phase cementing fluid particles in the functional microemulsion meets the requirement that the sand production of the consolidated reservoir is reduced to the lowest level, and the reservoir permeability is not lower than the original permeability. Specifically, the percentage content of the volume fraction of the internal phase cementing fluid is 50% - 70%, and the balance is the external heat - generating fluid and the system stabilizer. The percentage content of the system stabilizer in terms of the weight of the external heat - generating fluid is 1% - 5%. The external heat - generating fluid is the continuous phase, including a heat - generating agent, a delayed heat - generating control agent, a clay inhibitor, and a hydrate inhibitor. Among them, the percentage content of the heat - generating agent in terms of weight is 5% - 10%, the percentage content of the delayed heat - generating control agent in terms of weight is 1% - 5%, the percentage content of the clay inhibitor in terms of weight is 1% - 5%, and the percentage content of the hydrate inhibitor in terms of weight is 1% - 5%. The delayed heat - generating control agent is used to control the heat - generating timing of the heat - generating agent to ensure that the heat - generating agent generates heat in the pore throats of the muddy silt hydrate reservoir. The internal phase cementing fluid is the dispersed phase, mainly including a silane coupling agent, which is used to cement with sand particles and rock walls. The system stabilizer generally uses an amphoteric surfactant, which is used to demulsify and ensure that the internal phase cementing fluid is stably dispersed in the external heat - generating fluid in the form of nanoparticles.

[0042] The specific preparation method of the functional microemulsion is as follows:

[0043] Prepare the functional microemulsion: First, prepare the external heat - generating fluid, and add a clay inhibitor, a hydrate inhibitor, a heat - generating agent, and a delayed heat - generating control agent in proportion to the brine with the same salinity as the formation water. Second, slowly add the system stabilizer to the external heat - generating fluid and mechanically stir to dissolve the system stabilizer in the external heat - generating fluid. Third, under a high - speed stirring speed, slowly drop the internal phase cementing fluid into the external heat - generating fluid. Finally, after the addition of the internal phase cementing fluid is completed, continue to use a high - pressure homogenizer to break the internal phase cementing fluid into nanoparticles with a particle size of 0.1 - 1 nm and uniformly disperse them in the external heat - generating fluid.

[0044] Determine the dosage G of the functional microemulsion: Its calculation formula is as follows:

[0045] G = πr 2 Hφ = 3.14×0.52×20×0.35≈5.5m 3 , where r is the acidification radius of the reservoir. When the drilling pollution radius < the sand - fixing radius of the reservoir, the sand - fixing radius of the reservoir is selected as the acidification radius of the reservoir; when the drilling pollution radius ≥ the sand - fixing radius of the reservoir, the drilling pollution radius is selected as the acidification radius of the reservoir. In the embodiment of this patent, the drilling pollution radius 0.3m < the sand - fixing radius of the reservoir 0.5m, and the acidification radius r of the reservoir = 0.5m; the acidification interval length is the reservoir thickness 20m, and φ is the reservoir porosity of 35%.

[0046] Determine the injection pressure of the functional microemulsion: Use a surface high-pressure pump to pump 5.5 m downhole through the injection tubing 2 3 of the functional microemulsion. Considering that the fracture pressure of the argillaceous silt hydrate reservoir is 22 MPa, during the injection of the functional microemulsion, the injection pressure of the functional microemulsion < 22 MPa. The main purpose is to ensure that the functional microemulsion can penetrate radially into the reservoir matrix and disperse the internal phase cementation to achieve sand consolidation and sand control.

[0047] After the injection of the functional microemulsion is completed, the external heat-generating liquid in the functional microemulsion undergoes a chemical reaction in the pore throats to generate heat to increase the environmental temperature in the matrix pore throats. It should be noted that the heat generation by the chemical reaction should occur at an appropriate time. In order to ensure that the external heat-generating liquid undergoes a heat generation reaction after being injected into the reservoir matrix, if the functional microemulsion is prepared before matrix acidification and plugging removal, the delay time of the delayed heat generation control agent for delaying heat generation needs to be greater than the liquid preparation time and injection time of the functional microemulsion and the time required for matrix acidification; if the functional microemulsion is prepared after matrix acidification and plugging removal, the delay time of the delayed heat generation control agent for delaying heat generation needs to be greater than the liquid preparation time and injection time of the functional microemulsion. When the functional microemulsion is injected into the pores of the reservoir matrix,

[0048] the external heat-generating liquid 5 undergoes a chemical reaction and generates heat in the pores of the reservoir matrix under the action of the delayed heat generation control agent, the functional microemulsion and the environmental temperature increase. After the environmental temperature rises, the critical micelle concentration of the system stabilizer 7 increases significantly, resulting in the concentration of the surfactant in the microemulsion system in the pore throats being lower than the critical micelle concentration under the current temperature conditions, and the functional microemulsion demulsifies. At the same time, the heat generated by the chemical reaction in the pore throats causes the hydrates in the argillaceous silt hydrate reservoir to decompose, releasing free water. The free water dissolves in the external heat-generating liquid of the functional microemulsion, which will further reduce the concentration of the system stabilizer in the microemulsion system and further accelerate the demulsification of the functional microemulsion;

[0049] Use the internal phase cementing liquid in the functional microemulsion to directly contact the wall surface of the pore throats and undergo cementation to enhance the strength of the matrix skeleton and prevent the collapse and sand production of the pore throats. And the internal phase cementing liquid also undergoes cementation with the sediment particles in the pore throats to control and reduce the sand production volume.

[0050] Specifically, after the external heat-generating liquid 5 of the functional microemulsion undergoes a chemical reaction and generates heat and demulsifies, the internal phase cementing liquid 6 will directly contact the wall surface of the reservoir pore throats 10. The internal phase cementing liquid 6 undergoes spot cementation at the wall surface of the reservoir pore throats 10 to form a spot cementation state 11, as shown in Figure 4As shown, the matrix skeleton strength is enhanced to prevent reservoir collapse and sand production. Since the inner-phase cementing fluid 6 with a smaller particle size migrates deeper in the reservoir matrix and undergoes cementing sand control at the pore throats 10 in the far-well zone, while the inner-phase cementing fluid 6 with a larger particle size migrates shallower in the reservoir matrix and undergoes cementing sand control at the pore throats 10 in the near-well zone. Additionally, during the production process of the hydrate reservoir, the hydrate decomposes to generate decomposition gas 12 and free water, and the migration of formation fluids will scour the wall surface of the pore throats 10, resulting in the shedding of some loosely cemented mud and sand. The nano-scale inner-phase cementing fluid 6 utilizes its large specific surface area to adsorb and consolidate the mud and sand particles migrating in the pores, thereby controlling reservoir sand production and achieving efficient sand control in the near-well reservoir matrix area.

[0051] Experimental detection: Experimental detection of this embodiment reveals that the sand production rate of the reservoir after adopting the patented technology is only 3 mL / h. Compared with the conventional screen sand control technology, under the same experimental conditions, the sand production rate in the large physical model test using this patented technology is reduced by more than 25%, thereby reducing the migration blockage of solid-phase particles in the near-well zone of the hydrate reservoir, improving the reservoir seepage capacity, and significantly enhancing the single-well production capacity and stable production period.

[0052] In addition, without contradiction, those skilled in the art can combine and combine the different embodiments or examples described in this specification and the features of different embodiments or examples. Although the embodiments of the present invention have been shown and described above, it can be understood that the above embodiments are exemplary and should not be construed as limitations on the present invention. Those of ordinary skill in the art can make changes, modifications, substitutions, and variations to the above embodiments within the scope of the present invention.

Claims

1. A method for sand control in argillaceous silt hydrate reservoirs, characterized in that, It includes the following steps: Step 1, reservoir matrix acidification and plugging removal: Inject the acidification working fluid into the matrix area near the wellbore in the argillaceous silt hydrate reservoir, use the acidification working fluid to remove the solid particles in the drilling fluid in the matrix near the wellbore, and at the same time use the acidification working fluid to etch the walls of the holes and pore throats in the argillaceous silt hydrate reservoir and dissolve the plugging particles in the pore throats to increase the radius of the holes and pore throats and improve the seepage capacity of the argillaceous silt hydrate reservoir; Step 2, injection of functional microemulsion: Inject the functional microemulsion into the matrix area near the wellbore in the argillaceous silt hydrate reservoir to ensure that the functional microemulsion seeps into the pore throats of the argillaceous silt hydrate reservoir; Use the exothermic liquid in the functional microemulsion to undergo a chemical reaction in the pore throats to generate heat to increase the environmental temperature in the matrix pore throats. After the environmental temperature rises, the critical micelle concentration of the system stabilizer increases significantly, resulting in the concentration of the surfactant in the microemulsion system in the pore throats being lower than the critical micelle concentration under the current temperature conditions, and the functional microemulsion demulsifies; Use the internal phase cementing liquid in the functional microemulsion to directly contact the walls of the pore throats and undergo cementing to enhance the strength of the matrix skeleton, prevent the pore throats from collapsing and sand production, and at the same time the internal phase cementing liquid also undergoes cementing with the mud and sand particles in the pore throats to control and reduce the sand production volume.

2. The method for sand control in argillaceous silt hydrate reservoirs according to claim 1, characterized in that: In the step 1, the dosage S of the acidification working fluid is calculated by the following formula: S = πr 2 Hφ, where r is the acidification radius of the reservoir, H is the length of the acidified interval, and φ is the porosity of the reservoir.

3. The method for sand control in argillaceous silt hydrate reservoirs according to claim 2, characterized in that: In the said Step 1, if the drilling pollution radius < the reservoir sand consolidation radius, then select the reservoir sand consolidation radius as the reservoir acidification radius; if the drilling pollution radius ≥ the reservoir sand consolidation radius, then select the drilling pollution radius as the reservoir acidification radius.

4. The method for sand control in argillaceous silt hydrate reservoirs according to claim 1, characterized in that: The injection pressures of both the acidification working fluid and the functional microemulsion are lower than the fracture pressure of the argillaceous silt hydrate reservoir.

5. The method for sand control in argillaceous silt hydrate reservoirs according to claim 1, characterized in that: In the step 2, the heat generated by the chemical reaction of the exothermic fluid in the functional microemulsion in the pore throats decomposes the hydrates in the argillaceous silt hydrate reservoir, releasing free water. The free water dissolves in the exothermic fluid of the functional microemulsion, further reducing the concentration of the system stabilizer in the microemulsion system to accelerate demulsification. The dosage G of the functional microemulsion is calculated by the following formula: G = πr 2 Hφ, where r is the acidification radius of the reservoir, H is the length of the acidified well section, and φ is the porosity of the reservoir.

6. The method for sand control in argillaceous silt hydrate reservoirs according to claim 5, characterized in that: The said acidification working fluid is an aqueous solution containing 10% by weight of HCL and 3% by weight of HF.

7. The method for sand control in argillaceous silt hydrate reservoirs according to any one of claims 1 to 6, characterized in that: The functional microemulsion is composed of an exothermic liquid in the external phase, a cementing liquid in the internal phase and a system stabilizer. The internal phase cementing liquid is dispersed in the exothermic liquid in the external phase in the form of nanoparticles. Among them, the percentage content of the internal phase cementing liquid by volume is 50%-70%, and the balance is the exothermic liquid in the external phase and the system stabilizer. The system stabilizer is 1%-5% by weight percentage of the exothermic liquid in the external phase; The exothermic liquid in the external phase is the continuous phase, including a heat generating agent, a delayed heat generation control agent, a clay inhibitor and a hydrate inhibitor. Among them, the weight percentage content of the heat generating agent is 5%-10%, the weight percentage content of the delayed heat generation control agent is 1%-5%, the weight percentage content of the clay inhibitor is 1%-5%, the weight percentage content of the hydrate inhibitor is 1%-5%, and the balance is water; The delayed heat generation control agent is used to control the heat generation timing of the heat generating agent to ensure that the heat generating agent generates heat in the pore throats of the argillaceous silt hydrate reservoir; The internal phase cementing liquid is the dispersed phase, mainly including a silane coupling agent, which is used to cement with mud and sand particles and the rock wall; The system stabilizer uses an amphoteric surfactant to demulsify and ensure that the internal phase cementing liquid is stably dispersed in the exothermic liquid in the external phase in the form of nanoparticles.

8. The method for sand control in argillaceous silt hydrate reservoirs according to claim 7, characterized in that: The nanoparticles of the internal phase cementing fluid dispersed in the external heat - generating fluid have a particle size of 0.1 - 1 nm.

9. The method for sand control in argillaceous silt hydrate reservoirs according to claim 7, characterized in that: The preparation method of the functional microemulsion is as follows: First, prepare the external heat - generating fluid by adding a clay inhibitor, a hydrate inhibitor, a heat - generating agent, and a delayed heat - generating control agent in proportion in a brine with salinity equivalent to that of formation water. Second, slowly add the system stabilizer to the external heat - generating fluid and mechanically stir to dissolve the system stabilizer in the external heat - generating fluid. Third, slowly drop - wise add the internal phase cementing fluid to the external heat - generating fluid at a high - speed stirring speed. Finally, after the addition of the internal phase cementing fluid is completed, continue to use a high - pressure homogenizer to break the internal phase cementing fluid into nanosize and uniformly disperse it in the external heat - generating fluid.

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