Method for improving recovery ratio of heavy oil reservoir through foaming agent assisted steam flooding and application

Abstract

The invention provides a method for improving the recovery ratio of a heavy oil reservoir through foaming agent assisted steam flooding and application, and relates to the technical field of oilfield development. The method comprises the following steps: injecting a steam front slug, injecting a nitrogen slug, injecting a foaming agent slug and injecting a nitrogen mixed steam main slug; wherein the ratio of the injection speed of nitrogen to the injection speed of steam is always kept at 1: (2-3) when the nitrogen and the steam are injected into the main slug, and the mode of slow injection in the early stage, quick injection in the middle stage and slow injection in the later stage is kept in the steam injection process; the foaming agent comprises the following components in percentage by weight: 8-15% of alpha-olefin sulfonate, 1-2% of sodium methyl cocoyl taurate, 12-18% of fatty alcohol-polyoxyethylene ether, 2-3% of lauryl hydroxyl sulfobetaine and the balance of water. According to the method, the sweep efficiency and displacement efficiency of the thickened oil steam drive can be greatly improved, and the development effect of the thickened oil steam drive thermal recovery is improved.

Description

Technical Field

[0001] This application belongs to the field of oilfield development technology, and in particular relates to a method and application of foaming agent-assisted steam drive to improve the recovery rate of heavy oil reservoirs. Background Technology

[0002] Steam flooding is a thermal recovery technology used to further enhance oil recovery in heavy oil reservoirs after steam huff and puff recovery. Steam flooding technology uses periodic pulses of high-pressure and low-pressure steam to act on the formation, forcing steam from high-permeability layers, high-permeability sections, and high-permeability zones into low-permeability layers, low-permeability sections, and low-permeability zones, thus expanding the steam's swept volume. Because steam is a hot fluid with low density and high fluidity, it suffers from severe gas channeling within formation pores, resulting in a large loss rate and limiting its application. Currently, methods to improve the efficiency of steam flooding in heavy oil include nitrogen injection, air injection, mixed gas injection, and chemical injection. While air injection is relatively effective, it suffers from severe gas channeling between injection and production wells and poses a safety hazard of potential explosions from the oil-gas mixture. Chemical-assisted steam flooding can avoid these problems.

[0003] Foaming agents, also known as foaming agents, reduce the surface tension of liquids and generate a large amount of uniform and stable foam, and have a long history of application in oil fields. With advancements in surfactant technology, the types and properties of foaming agents will better meet the actual needs of the field, playing a more important role in the petroleum industry. However, because steam drive can create interconnected temperature fields between wells, with the steam sweep zone temperature ranging from 100 to 300°C, foaming agents must be able to withstand high temperatures while maintaining good foaming performance. Furthermore, conventional foaming agents are easily adsorbed by the formation after entering the formation, thus affecting their effectiveness and consequently impacting the steam drive's extraction efficiency. Therefore, developing foaming agents that can withstand the high temperatures of 100–300°C in steam drive, are resistant to formation adsorption, and possess excellent foaming performance holds great promise for improving steam drive extraction efficiency.

[0004] Patent CN107903886A discloses a high-temperature resistant foaming agent for auxiliary steam driving, comprising 5-10 parts of a foaming agent, 10-30 parts of a foam stabilizer, and 60-85 parts of water. The foaming agent is an imino-containing polyether sulfonate, a product of the reaction between N-alkyl polyethylene and butene ether polymer sulfonate. This foaming agent exhibits a maximum foaming volume of 468 mL and a half-life of 91 min at 300°C. While it can withstand high temperatures of 300°C, its foaming performance needs further improvement. Summary of the Invention

[0005] The purpose of this application is to address the shortcomings of existing technologies by providing a method and application for improving the recovery rate of heavy oil reservoirs through foam-assisted steam drive. This application increases the steam sweep volume, improves displacement efficiency, and increases crude oil recovery by using foam-assisted steam drive.

[0006] To achieve the above objectives, the technical solution adopted in this application is as follows: A method for enhancing the recovery rate of heavy oil reservoirs using foaming agent-assisted steam drive includes the following steps: S1, pre-steam injection plug; S2, Inject nitrogen gas into the sluice gate; S3, Inject foaming agent into the plug; S4. Inject nitrogen-mixed steam into the main sluice plug until the water content of the produced fluid is higher than 98%, then stop production. In the main sluice block of the nitrogen-vapor mixture, the injection rate ratio of nitrogen to vapor is 1:(2-3), and the vapor injection rate is divided into three stages: Stage 1: Steam injection rate of 3000–4000 m / s 3 / d, the injection time is 1 / 3 to 1 / 4 of the total time of injecting nitrogen-mixed vapor slug; Stage Two: Steam injection rate of 7000–8000 m / s 3 / d, the injection time is 1 / 2 to 1 / 3 of the total time of injecting nitrogen-mixed vapor slug; Stage 3: Steam injection rate of 4000–5000 m / s 3 / d, the injection time is 1 / 3 to 1 / 4 of the total time of injecting nitrogen-mixed vapor slug; The foaming agent, by weight percentage, comprises: 8-15% α-olefin sulfonate, 1-2% sodium methyl cocoyl taurate, 12-18% fatty alcohol polyoxyethylene ether, and 2-3% lauryl hydroxysulfonate betaine, with the balance being water.

[0007] Preferably, the foaming agent comprises, by weight percentage: 12% α-olefin sulfonate, 1% sodium methyl cocoyl taurate, 15% fatty alcohol polyoxyethylene ether, and 2.6% lauryl hydroxysulfonate betaine, with the balance being water.

[0008] Preferably, a nitrogen-vapor mixture is injected into the main sluice gate, and the vapor injection rate is divided into three stages: Stage 1: Steam injection rate is 4000m / s² 3 / d, the injection time is 1 / 4 of the total time of injecting nitrogen-mixed vapor slug; Stage Two: Steam injection rate at 7600m 3 / d, the injection time is 1 / 2 of the total time of injecting nitrogen-mixed vapor slug; Stage 3: Steam injection rate at 4500m 3 / d, the injection time is 1 / 4 of the total time of injecting nitrogen-mixed vapor slug.

[0009] Furthermore, during the steam injection pre-blocking process, the steam injection rate is 3-5 mL / min, the temperature is 250℃-300℃, the steam injection dryness is ≥95%, and the injection volume is 0.5-0.7 PV.

[0010] Furthermore, during the nitrogen injection slug process, the nitrogen injection rate is 3000–5000 m / s. 3 / d, when the production oil-to-gas ratio > 800m 3 The next segment of the plug is executed at / t.

[0011] Furthermore, during the foaming agent injection process, the amount of foaming agent injected is 0.1 to 0.15 PV.

[0012] Furthermore, the fatty alcohol polyoxyethylene ether in the foaming agent satisfies an alkyl carbon chain length of 12-16 and a degree of polymerization of ethylene oxide of 9-14.

[0013] In a further embodiment, the foaming agent further comprises 0-1% modified nano-SiO2, preferably 0.5-1%, wherein the modified nano-SiO2 is obtained by modifying nano-SiO2 with hexamethyldisilazane (HMDS) and polyether-modified heptamethyltrisiloxane. The polyether-modified heptamethyltrisiloxane can be commercially available or prepared using methods well-known to those skilled in the art, such as hydrosilylation of heptamethyltrisiloxane with allyl polyether, and is not particularly limited.

[0014] The above-described method for preparing modified nano-SiO2 includes the following steps: (1) Disperse nano-SiO2 in an organic solvent, add HMDS, react at 100-120℃ for 1-3 h, and take out to obtain HMDS modified nano-SiO2; (2) HMDS-modified nano-SiO2 is redispersed in an organic solvent, polyether-modified heptamethyltrisiloxane is added, and the reaction is carried out at 80-100℃ for 1-2 hours. After the reaction is completed, it is washed with anhydrous ethanol and dried to obtain the modified nano-silica.

[0015] Optionally, in step (1), the mass ratio of HMDS to nano-SiO2 in the modified nano-SiO2 is (10-18):100.

[0016] Optionally, in step (2), the mass ratio of polyether-modified heptamethyltrisiloxane to nano-SiO2 in the modified nano-SiO2 is (5-8):100.

[0017] Optionally, the organic solvent can be acetone, toluene, xylene, dichloromethane, etc., as long as it can dissolve the material, and there is no particular limitation; the amount of the organic solvent is generally more than twice the amount of the material.

[0018] According to another aspect of this application, the method for enhancing the recovery rate of heavy oil reservoirs by foaming agent-assisted steam drive described above is provided for the development of heavy oil reservoirs, the application including the development of heavy oil reservoirs with oil layer burial depth > 1000m, oil layer thickness > 5m, oil saturation > 75%, oil layer porosity 30-40%, permeability < 1000mD, and crude oil viscosity > 10000mPa·s.

[0019] Compared with the prior art, this application has the following beneficial effects: 1. The steam drive development method provided in this application injects nitrogen and foaming agent before injecting nitrogen-mixed steam main sluice. After the foaming agent enters the formation, it seals the high-permeability layer or large pores, effectively inhibiting steam from entering the high-permeability zone and turning it to the low-permeability zone or other undisplaced zones, increasing the displacement volume, improving the steam sweep area, and effectively improving the recovery rate.

[0020] 2. The steam drive development method provided in this application uses a combination of α-olefin sulfonate, sodium methyl cocoyl taurate, fatty alcohol polyoxyethylene ether, and lauryl hydroxysulfonate betaine as a foaming agent. It has strong foaming ability, good foam stability, and maintains high foam performance even after high-temperature treatment at 300℃. It has good plugging effect and good resistance to formation adsorption, making it suitable for steam drive development and improving oil recovery.

[0021] 3. The steam-driven development method provided in this application involves injecting nitrogen and steam into the reservoir at a slow-fast-slow injection rate during the nitrogen-steam main sluice process. The initial slow injection rate allows for longer contact time between the steam and the formation rock and crude oil, resulting in more thorough heat exchange and transferring more heat energy to the reservoir, thus creating conditions for subsequent crude oil flow. Mid-term rapid injection increases the injection volume and rate of steam, covering more reservoir volume and improving sweep efficiency. Late-stage slow injection extends the contact time between the steam and these areas, allowing heat to slowly penetrate into low-permeability zones, heating and displacing remaining oil. Adopting a slow-fast-slow injection rate and controlling the injection rate improves thermal efficiency and enhances oil recovery. Detailed Implementation

[0022] The following non-limiting embodiments are intended to enable those skilled in the art to gain a more comprehensive understanding of this application, but do not limit this application in any way. The following content is merely an exemplary description of the scope of protection claimed in this application, and those skilled in the art can make various changes and modifications to the invention based on the disclosed content, which should also fall within the scope of protection claimed in this application.

[0023] The present application will be further described below by way of specific embodiments. Unless otherwise specified, all chemical reagents used in the embodiments of this application are obtained through conventional commercial means.

[0024] Example 1 A method and application for enhancing the recovery rate of heavy oil reservoirs by foaming agent-assisted steam drive, characterized by comprising the following steps: S1. Inject steam into the pre-slug, with a steam injection rate of 3 mL / min, a steam temperature of 250℃, a steam injection dryness of 95%, and an injection volume of 0.5 PV; S2. Inject nitrogen into the sluice gate at a nitrogen injection rate of 3000 m / s. 3 / d; When the production oil-to-gas ratio > 800m 3 The next stage of plugging will begin at / t; S3. Inject foaming agent into the sluice gate, with an injection volume of 0.1 PV; S4. Inject nitrogen-mixed vapor into the main plug section; S5, well shut-in, well opening production; In the nitrogen-vapor main slug, the nitrogen to vapor injection rate ratio is always maintained at 1:2, and the vapor injection rate is divided into three stages: Stage 1: Steam injection rate is 4000m / s² 3 / d, the injection time is 1 / 4 of the total time of injecting nitrogen-mixed vapor slug; Phase Two: Steam injection rate at 8000m 3 / d, the injection time is 1 / 2 of the total time of injecting nitrogen-mixed vapor slug; Stage 3: Steam injection rate of 5000m 3 / d, the injection time is 1 / 4 of the total time of injecting nitrogen-mixed vapor slug; The foaming agent, by mass percentage, comprises: 8% α-olefin sulfonate, 2% sodium methyl cocoyl taurate, 18% fatty alcohol polyoxyethylene ether (alkyl carbon chain length 12, degree of polymerization of oxyethylene is 9), and 3% lauryl hydroxysulfonate betaine, with the balance being water.

[0025] Example 2 A method and application for enhancing the recovery rate of heavy oil reservoirs by foaming agent-assisted steam drive, characterized by comprising the following steps: S1. Inject steam into the pre-slug, with a steam injection rate of 5 mL / min, a steam temperature of 300℃, a steam injection dryness of 95%, and an injection volume of 0.7 PV. S2. Inject nitrogen into the sluice gate at a nitrogen injection rate of 5000 m / s. 3 / d; When the production oil-to-gas ratio > 800m 3 The next stage of plugging will begin at / t; S3. Inject foaming agent into the sluice gate, with an injection volume of 0.15 PV; S4. Inject nitrogen-mixed vapor into the main plug section; S5, well shut-in, well opening production; In the nitrogen-vapor main slug, the nitrogen to vapor injection rate ratio is always maintained at 1:3, and the vapor injection rate is divided into three stages: Stage 1: Steam injection rate is 4000m / s² 3 / d, the injection time is 1 / 4 of the total time of injecting nitrogen-mixed vapor slug; Stage Two: Steam injection rate at 7600m 3 / d, the injection time is 1 / 2 of the total time of injecting nitrogen-mixed vapor slug; Stage 3: Steam injection rate at 4500m 3 / d, the injection time is 1 / 4 of the total time of injecting nitrogen-mixed vapor slug; The foaming agent, by mass percentage, comprises: 12% α-olefin sulfonate, 1% sodium methyl cocoyl taurate, 15% fatty alcohol polyoxyethylene ether (alkyl carbon chain length 12, degree of polymerization of ethylene oxide 9), and 2.6% lauryl hydroxysulfonate betaine, with the balance being water.

[0026] Example 3 A method and application for enhancing the recovery rate of heavy oil reservoirs by foaming agent-assisted steam drive, characterized by comprising the following steps: S1. Inject steam into the pre-slug, with a steam injection rate of 5 mL / min, a steam temperature of 300℃, a steam injection dryness of 95%, and an injection volume of 0.7 PV. S2. Inject nitrogen into the sluice gate at a nitrogen injection rate of 5000 m / s. 3 / d; When the production oil-to-gas ratio > 800m 3 The next stage of plugging will begin at / t; S3. Inject foaming agent into the sluice gate, with an injection volume of 0.15 PV; S4. Inject nitrogen-mixed vapor into the main plug section; S5, well shut-in, well opening production; In the nitrogen-vapor slug injection system, the nitrogen to vapor injection rate ratio is consistently maintained at 1:3, and the vapor injection rate is divided into three stages: Stage 1: Steam injection rate is 3000m / s² 3 / d, the injection time is 1 / 4 of the total time of injecting nitrogen-mixed vapor slug; Stage Two: Steam injection rate of 7000m 3 / d, the injection time is 1 / 2 of the total time of injecting nitrogen-mixed vapor slug; Stage 3: Steam injection rate of 4000m 3 / d, the injection time is 1 / 4 of the total time of injecting nitrogen-mixed vapor slug; The foaming agent, by mass percentage, comprises: 15% α-olefin sulfonate, 1% sodium methyl cocoyl taurate, 12% fatty alcohol polyoxyethylene ether (alkyl carbon chain length 16, degree of polymerization of oxyethylene 14) and 2% lauryl hydroxysulfonate betaine, with the balance being water.

[0027] Example 4 The difference from Example 2 is that the foaming agent also contains 0.5% modified nano-SiO2. The preparation method of modified nano-SiO2 includes the following steps: (1) Disperse nano-SiO2 in sufficient dichloromethane, add HMDS, react at 100℃ for 3h, and take out to obtain HMDS modified nano-SiO2; the mass ratio of HMDS to nano-SiO2 is 10:100. (2) HMDS-modified nano-SiO2 was redispersed in sufficient dichloromethane. Polyether-modified heptamethyltrisiloxane was added at a mass ratio of 5:100 to nano-SiO2. The reaction was carried out at 80°C for 2 hours. After the reaction was completed, the nano-SiO2 was washed with anhydrous ethanol and dried to obtain the modified nano-SiO2.

[0028] Example 5 The difference from Example 2 is that the foaming agent also contains 1% modified nano-SiO2. The preparation method of modified nano-SiO2 includes the following steps: (1) Disperse nano-SiO2 in sufficient dichloromethane, add HMDS, react at 120℃ for 1 h, and take out to obtain HMDS modified nano-SiO2; the mass ratio of HMDS to nano-SiO2 is 18:100. (2) HMDS-modified nano-SiO2 is redispersed in sufficient dichloromethane. Polyether-modified heptamethyltrisiloxane is added at a mass ratio of 8:100 to nano-SiO2. The reaction is carried out at 100°C for 1 hour. After the reaction is complete, the nano-SiO2 is washed with anhydrous ethanol and dried to obtain the modified nano-SiO2.

[0029] Example 6 The difference from Example 5 is that, in the preparation of modified nano-SiO2, the mass ratio of HMDS to nano-SiO2 is 25:100, and the mass ratio of polyether-modified heptamethyltrisiloxane to nano-SiO2 is 10:100.

[0030] Example 7 The difference from Example 5 is that the foaming agent contains 2% modified nano-SiO2, and the preparation method of the modified nano-SiO2 is the same as that of Example 5.

[0031] Comparative Example 1 The difference from Example 2 is that the foaming agent, by mass percentage, contains: 5% α-olefin sulfonate, 5% sodium methyl cocoyl taurate, 20% fatty alcohol polyoxyethylene ether, and 5% lauryl hydroxysulfonate betaine, with the balance being water.

[0032] Comparative Example 2 The difference from Example 2 is that the foaming agent, by mass percentage, contains: 18% α-olefin sulfonate, 1% sodium methyl cocoyl taurate, 10% fatty alcohol polyoxyethylene ether, and 1% lauryl hydroxysulfonate betaine, with the balance being water.

[0033] Comparative Example 3 The difference from Example 2 is that, during the injection of nitrogen-mixed vapor into the main sluice plug, the vapor injection rate is: Stage 1: Steam injection rate is 2000m / s² 3 / d, the injection time is 1 / 4 of the total time of injecting nitrogen-mixed vapor slug; Phase 2: Steam injection rate of 6000m 3 / d, the injection time is 1 / 2 of the total time of injecting nitrogen-mixed vapor slug; Stage 3: Steam injection rate at 3500m 3 / d, the injection time is 1 / 4 of the total time of injecting nitrogen-mixed vapor slug.

[0034] Comparative Example 4 The difference from Example 2 is that, during the injection of nitrogen-mixed vapor into the main plug, the vapor injection includes two stages. Stage 1: The steam injection rate is 2t / h, and the injection time is 1 / 2 of the total time of injecting nitrogen-mixed steam slug. Second stage: The steam injection rate is 4.5t / h, and the injection time is 1 / 2 of the total time of injecting nitrogen-mixed steam slug.

[0035] Comparative Example 5 The difference from Example 2 is that during the injection of nitrogen-mixed vapor into the main sluice plug, the vapor injection rate was maintained at 4000 m / s. 3 / d.

[0036] Test Example 1 Performance testing of foaming agents The foaming agents in Examples 1-7 and Comparative Examples 1 and 2 were prepared into solutions with a mass concentration of 0.5%. Each solution was divided into three parts. One part was tested for foam performance using an MRM-RI Roche foam analyzer at 50°C. Another part was tested for foam performance at 300°C. The third part was placed in a high-temperature and high-pressure reactor and aged at 300°C and 10MPa pressure for 72 hours before being tested for foam performance in a foam analyzer.

[0037] The measured results are shown in Table 1 below. It can be seen that the foaming agent provided in this application has a high foaming volume and a long half-life, and has good foaming performance. Even at a high temperature of 300℃ and after aging treatment at 300℃, it can still maintain a high foaming volume and half-life, and has good high temperature resistance.

[0038] Table 1. Foam Properties

[0039] Test Example 2 Foaming agent plugging performance It uses an inner diameter of 25 mm, a length of 300 mm, and a permeability of 3.00 μm. 2 The foam plugging performance was evaluated using left and right sand-filled pipe models. The specific steps are as follows: (1) First, saturate the sand-filled pipe with water and measure the water phase permeability of the core. (2) Nitrogen and steam are simultaneously injected into the core at a gas-liquid ratio of 1:1. When the pressure difference between the two ends of the core reaches a stable level, the pressure difference between the two ends of the core at this time is recorded as the base pressure difference; (3) Nitrogen and foaming agent are simultaneously injected into the core at the same gas-liquid ratio of 1:1. When the pressure difference between the two ends of the core reaches a stable level, the pressure difference at this point is recorded as the working pressure difference. Finally, the resistance factor of the foam system is calculated according to the formula: Fr = working pressure difference / base pressure difference.

[0040] The results are shown in Table 2 below. The results show that the resistance factor of the foaming agent provided in this application is above 40, and the sealing performance is excellent.

[0041] Table 2. Resistance Factors

[0042] Test Example 3 An oil displacement performance test was conducted using a sand-filled tube model with an inner diameter of 400 mm, a length of 150 mm, a permeability of 680 mD, an oil layer porosity of 36.8%, an oil saturation of 85.8%, and a crude oil viscosity of 13600 mPa·s. Specifically: (1) After saturating the sand-filled tube with water, crude oil was saturated at 50°C and aged for 24 h; (2) Steam at 300°C was injected, and displacement was stopped when the water content reached 98%, and the steam-driven recovery rate was calculated; (3) Displacement was carried out according to the methods provided in the above embodiments and comparative examples, and displacement was stopped when the water content of the produced fluid was greater than 98%, and the final recovery rate was calculated; (4) The difference between the final recovery rate and the steam-driven recovery rate is the enhanced oil recovery rate.

[0043] The enhanced oil recovery rates measured are shown in Table 3 below. It can be seen that, compared with traditional steam drive, the steam drive development method of this application improves the oil recovery rate.

[0044] Table 3. Oil Displacement Effect

[0045] The above description of the embodiments is provided to enable those skilled in the art to understand and use the invention. It will be apparent to those skilled in the art that various modifications can be made to these embodiments, and the general principles described herein can be applied to other embodiments without inventive effort. Therefore, this application is not limited to the above embodiments, and any improvements and modifications made by those skilled in the art based on the disclosure of this application without departing from the scope of this application should be within the protection scope of this application.

Claims

1. A method for improving the recovery rate of heavy oil reservoirs by using foaming agents-assisted steam drive, characterized in that, Includes the following steps: S1, Steam injection pre-steam plug; S2, Inject nitrogen gas into the sluice gate; S3, Inject foaming agent into the plug; S4. Inject nitrogen-mixed vapor into the main plug section; In the main sluice block of the nitrogen-vapor mixture, the injection rate ratio of nitrogen to vapor is always maintained at 1:(2-3), and the vapor injection rate is divided into three stages: Stage 1: Steam injection rate is 3000–4000 m / s 3 / d, the injection time is 1 / 3 to 1 / 4 of the total time of this blockage; Stage Two: Steam injection rate of 7000–8000 m / s 3 / d, the injection time is 1 / 2 to 1 / 3 of the total time of this blockage; Stage 3: Steam injection rate of 4000–5000 m / s 3 / d, the injection time is 1 / 3 to 1 / 4 of the total time of this blockage; The foaming agent, by weight percentage, comprises: 8-15% α-olefin sulfonate, 1-2% sodium methyl cocoyl taurate, 12-18% fatty alcohol polyoxyethylene ether, and 2-3% lauryl hydroxysulfonate betaine, with the balance being water.

2. The method according to claim 1, characterized in that, During the steam injection pre-blocking process, the steam injection rate is 3-5 mL / min, the temperature is 250℃-300℃, the steam injection dryness is ≥95%, and the injection volume is 0.5-0.7 PV.

3. The method according to claim 1, characterized in that, During the nitrogen injection slug process, the nitrogen injection rate is 3000–5000 m / s. 3 / d.

4. The method according to claim 1, characterized in that, During the foaming agent slugging process, the foaming agent injection volume is 0.1 to 0.15 PV.

5. The method according to claim 1, characterized in that, The fatty alcohol polyoxyethylene ether in the foaming agent satisfies an alkyl carbon chain length of 12-16 and a degree of polymerization of ethylene oxide of 9-14.

6. The method according to claim 1, characterized in that, The foaming agent also contains 0-1% modified nano-SiO2, which is obtained by modifying nano-SiO2 with hexamethyldisilazane (HMDS) and polyether-modified heptamethyltrisiloxane.

7. The method according to claim 6, characterized in that, In the modified nano-SiO2, the mass ratio of HMDS to nano-SiO2 is (10-18):

100.

8. The method according to claim 7, characterized in that, In the modified nano-SiO2, the mass ratio of polyether-modified heptamethyltrisiloxane to nano-SiO2 is (5-8):

100.

9. The application of the method according to any one of claims 1-8 in the development of heavy oil reservoirs, characterized in that, The applications include the development of heavy oil reservoirs with a burial depth >1000m, a reservoir thickness >5m, an oil saturation >75%, a reservoir porosity of 30-40%, a permeability <1000mD, and a crude oil viscosity >10000mPa·s.

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