Silica Nanoparticles for Crude Oil Recovery Using Carbon Dioxide and Crude Oil Recovery Method

Abstract

[Problem] To provide a hydrosol used in CO2 foam flooding from among EOR flooding methods for recovering crude oil by injection into an oil stratum in an inland or offshore oil field, the hydrosol for increasing the long-term and high-temperature / high-pressure stability of a foam against salt water, and for enhancing the crude oil recovery rate. [Solution] A hydrosol for increasing the stability of a foam or emulsion in a mixture that includes carbon dioxide, water, and oil in CO2 foam flooding for enhanced oil recovery (EOR), wherein silica particles which have an average particle diameter of 1-100 nm measured by dynamic light scattering, and in which surfaces thereof are at least partially covered by a silane compound having hydrolyzable groups, are dispersed as a dispersoid in an aqueous solvent as a dispersion medium having a pH of 1.0-6.0 inclusive.

Description

Technical Field

[0001] The present invention relates to an aqueous sol used in a CO2 foam method among enhanced oil recovery (“Enhanced Oil Recovery”, hereinafter abbreviated as “EOR”) methods for injecting into an oil reservoir in an inland or undersea oil field to recover crude oil.

Background Art

[0002] For the method of recovering (producing) crude oil from an oil reservoir, a three-stage method of primary, secondary, and tertiary recovery (or EOR (enhanced recovery)), in which different recovery methods are applied in chronological order, is applied. Examples of the primary recovery method include a natural flow production method that utilizes the natural pressure and gravity of the oil reservoir, and an artificial production method that uses artificial production techniques such as pumps. The crude oil recovery rate of the primary recovery implemented by combining these is said to be at most about 20%. Examples of the secondary recovery method include a water flooding method and a reservoir pressure maintenance method in which, after production declines in the primary recovery method, water or natural gas is injected to restore the reservoir pressure and increase the oil production rate. Even when these primary and secondary recoveries are combined, the crude oil recovery rate is about 40%, and most of the crude oil remains in the underground oil reservoir. Therefore, in order to recover more crude oil and to recover additional crude oil from an oil reservoir from which crude oil has already been recovered from the easier-to-recover portions, a tertiary recovery method, that is, a method for enhancing the recovery of crude oil (EOR method), has been proposed.

[0003] EOR methods include thermal methods, gas methods, microbial methods, chemical methods, etc. Among these, the gas method (also called the gas miscible method) is to create a miscible state (a mixed state under supercritical pressure) between the injected gas (fluid) and oil, aiming to improve the recovery rate of the crude oil remaining in the fine pores of the reservoir rock. Since hydrocarbon gas, carbon dioxide (CO2), nitrogen, combustion exhaust gas, etc. that appear during oil production are the objects of injection in the gas method, the gas collected from the oil layer can be reused as it is, and CO2 in the exhaust gas discharged from oil refineries, power plants, etc. can be recovered and used. In addition to increasing the crude oil recovery rate and leading to the effective use of resources, it is attracting attention as a technology that can also contribute to reducing greenhouse gas emissions, that is, measures against global warming. Also, because the fluidity of the injected gas is high in the gas method, the injected gas tends to diffuse along the large gaps in the oil layer and is difficult to enter the fine gaps. Therefore, in order to reduce the fluidity of the injected gas, the gas-liquid alternate injection method (WAG injection method: Water Alternating Gas) of alternately injecting gas and water has also been put into practical use.

[0004] As a next-generation technology of the CO2 gas method in the above gas method, the CO2 foam method that improves the sweep efficiency by controlling the mobility has been proposed. This method thickens the injected fluid by forming CO2 foam (Foam), makes the viscosity of the crude oil, which is the displaced fluid, relatively low to improve the mobility, and aims to improve the sweep efficiency of the crude oil remaining in the fine pores of the reservoir rock. For example, regarding the CO2 foam (Foam) method, Non-Patent Document 1 discloses a technique using commercially available silane-modified silica nanoparticles, and Non-Patent Document 2 discloses a technique using silica nanoparticles grafted with ligands on the nanoparticle surface. Patent Document 1 also discloses a foam containing a foam composition containing surface-modified silica nanoparticles and a foaming agent such as nitrogen gas as a foam for enhancing oil recovery. Furthermore, Patent Document 2 discloses a method for recovering crude oil using an emulsion stabilized by amphiphilic nanoparticles containing silica nanoparticles and metal nanoparticles.

Prior Art Documents

Patent Documents

[0005] [Patent Document 1] Japanese Patent Publication No. 2005-526887 [Patent Document 2] International Publication No. 2015 / 116332 [Non-Patent Document]

[0006] [Non-Patent Document 1] A.U. Rongmo (University of Bergen) et al., ”Performance of Silica Nanoparticles in CO2-Foam for EOR and CCUS at Tough Reservoir Conditions”, Society of Petroleum Engineers (2018) SPE-191318-MS, Society of Petroleum Engineers [Non-Patent Document 2] Shehab Alzobaidi (University of Texas at Austin) et al., ”Carbon Dioxide-in-Brine Foams at High Temperatures and Extreme Salinities Stabilized with Silica Nanoparticles”, Energy & Fuels 2017 31 10680-10690 [Summary of the Invention] [Problems to be Solved by the Invention]

[0007] In oil recovery, the fluid (such as Foam) injected into the underground or undersea oil reservoir is often recovered several months after injection. Therefore, there is a need for a fluid that can remain stable under extremely harsh conditions for dozens of days to several months at high temperatures around 100°C and high pressures exceeding 100 atmospheres, and be exposed to seawater or brine containing high concentrations of sodium ions, calcium ions, chlorine ions, etc., and can exhibit an oil recovery effect. As described above, in the CO2 Foam flooding method of EOR, although various techniques using silica nanoparticles and the like have been disclosed, there have been no reports on the stability of CO2 Foam under high pressure and high temperature, or on sols containing silica nanoparticles.

[0008] The present invention is directed to an aqueous sol used in the CO2 Foam flooding method for injecting into an oil reservoir in an inland or undersea oil field to recover crude oil. That is, it is an object of the present invention to provide an aqueous sol that can enhance the stability of Foam over a long period of time, under high temperature and high pressure, and in the presence of brine, thereby improving the crude oil recovery rate. Another object of the present invention is to provide a crude oil recovery method using the aqueous sol and a method for producing the aqueous sol.

Means for Solving the Problems

[0009] As a result of intensive studies by the present inventors to solve the above problems, an aqueous sol in which silica particles having an average particle diameter of 1 to 100 nm and at least a part of the surface thereof is coated with a silane compound having a hydrolyzable group are dispersed in an aqueous solvent having a pH of 1.0 or more and 6.0 or less as a dispersion medium has been found to enhance the stability of Foam over a long period of time, under high temperature and high pressure, and in the presence of brine, thereby leading to an improvement in the crude oil recovery rate, and the present invention has been completed.

[0010] That is, as a first aspect, the present invention is an aqueous sol for enhancing the stability of foam or emulsion in a mixture containing carbon dioxide, water, and oil in a CO2 foam process for enhanced oil recovery (EOR), which relates to an aqueous sol in which silica particles having an average particle diameter of 1 to 100 nm in measurement by dynamic light scattering method and having at least a part of the surface coated with a silane compound having a hydrolyzable group are dispersed in an aqueous solvent having a pH of 1.0 or more and 6.0 or less as a dispersion medium. As a second aspect, the present invention relates to the aqueous sol according to the first aspect, wherein the silane compound having a hydrolyzable group is a silane compound containing an epoxy group or an organic group obtained by hydrolysis thereof. As a third aspect, the present invention relates to the aqueous sol according to the second aspect, wherein the epoxy group is a glycidyl group, a cyclohexyl epoxy group, or a combination thereof. As a fourth aspect, the present invention relates to the aqueous sol according to the first aspect, wherein the silane compound having a hydrolyzable group is a silane compound containing an amino group. As a fifth aspect, the present invention relates to the aqueous sol according to any one of the first to fourth aspects, wherein the silane compound having a hydrolyzable group further contains a second silane compound having a hydrolyzable group. As a sixth aspect, the present invention relates to the aqueous sol according to the fifth aspect, wherein the second silane compound having a hydrolyzable group is a silane compound containing an organic group containing an alkyl group having 1 to 40 carbon atoms, an aromatic ring group having 6 to 40 carbon atoms, or a combination thereof. As a seventh aspect, the present invention relates to the aqueous sol according to any one of the first to sixth aspects, wherein in the silica particles having at least a part of the surface coated, the silane compound and the silica particles are contained at a ratio of 0.01 to 2.00:1.00 by mass ratio. As an eighth aspect, the present invention relates to the aqueous sol according to any one of the first to seventh aspects, which does not have an isoelectric point at pH 6 or less. As a ninth aspect, regarding the aqueous sol according to any one of the first to eighth aspects, after a test in which the aqueous sol is stored at 80 °C for 30 days at a silica concentration of 1.0% by mass in an environment containing sodium chloride, calcium chloride, and magnesium chloride as main components and having a total salt concentration of 10,000 to 230,000 ppm, the difference between the value of the average particle diameter measured by dynamic light scattering of the aqueous sol and the average particle diameter before the test is 200 nm or less. As a tenth aspect, regarding the aqueous sol according to any one of the first to ninth aspects, the pH during the coating of silica particles in an aqueous medium with a silane compound having a hydrolyzable group in the aqueous sol is 1.0 or more and 6.0 or less, and after a test in which the aqueous sol stored at a pH of 1.0 or more and 6.0 or less is stored at 80 °C for 30 days at a silica concentration of 1.0% by mass in an environment containing sodium chloride, calcium chloride, and magnesium chloride as main components and having a total salt concentration of 10,000 to 230,000 ppm and at a pH of 5.0 to 8.0 in the environment, the difference between the value of the average particle diameter measured by dynamic light scattering of the aqueous sol and the value of the average particle diameter before the test is 200 nm or less. As an eleventh aspect, regarding the aqueous sol according to any one of the first to tenth aspects, the foam or emulsion is stable at a temperature of 30 to 120 °C and a pressure of 70 to 400 atmospheres. As a twelfth aspect, a method for recovering crude oil from a subsurface hydrocarbon-containing layer, (a) step: injecting the aqueous sol, water, and carbon dioxide according to any one of the first to eleventh aspects into the underground layer, respectively or simultaneously; (b) step: recovering crude oil from a production well drilled in the underground layer to the ground relates to a crude oil recovery method including the above steps. As a thirteenth aspect, regarding the crude oil recovery method according to the twelfth aspect, the (a) step is a step of alternately injecting the aqueous sol and water and carbon dioxide into the underground layer. As a fourteenth aspect, regarding the crude oil recovery method according to the twelfth or thirteenth aspect, the injection in the (a) step is performed at a temperature of 30 to 120 °C and a pressure of 70 to 400 atmospheres. From the 15th perspective, it relates to the crude oil recovery method according to any one of the 12th to 14th perspectives, wherein the underground layer is a layer containing sandstone. From the 16th perspective, it relates to the crude oil recovery method according to any one of the 12th to 14th perspectives, wherein the underground layer is a layer containing carbonate rock. From the 17th perspective, it is a method for producing an aqueous sol containing, as a dispersion medium, silica particles at least partially coated on the surface with a silane compound having a hydrolyzable group according to any one of the 1st to 11th perspectives, the method including a step of mixing an aqueous sol of unmodified colloidal silica and a silane compound having a hydrolyzable group at a ratio such that the mass ratio of the silane compound to the silica particles in the aqueous sol is 0.01 - 2:1.00, and treating this at pH 1 - 6 for 0.1 hour - 20 hours. From the 18th perspective, it relates to the production method according to the 17th perspective, wherein the step of mixing and treating the aqueous sol of unmodified colloidal silica and the silane compound having a hydrolyzable group is carried out at 50 - 100°C.

Advantages of the Invention

[0011] The aqueous sol of the present invention can stably form and maintain fine CO2 foam for a long period at high temperature (30 - 120°C), high pressure (70 - 400 atm), and salt concentration (10,000 - 230,000 ppm). And by forming a CO2 foam excellent in long-term stability and salt tolerance, the viscosity of the fluid (CO2 foam) injected into the underground layer increases, allowing the fluid to penetrate into the pores of the reservoir rock, including pores that were difficult to penetrate until now. As a result, it is expected that the sweep efficiency of the crude oil in the rock can be improved and the crude oil can be recovered at a high recovery rate.

Brief Description of the Drawings

[0012]

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DETAILED DESCRIPTION OF THE INVENTION

[0013] The present invention relates to an aqueous sol for enhancing the stability of foams or emulsions in a liquid in the CO2 foam flooding method for enhanced oil recovery (EOR). The aqueous sol of the present invention can contribute to the formation and stabilization of foams or emulsions by contact between water (including brine, seawater, etc.) and carbon dioxide, and further by contact between these and crude oil. In the present invention, "foam" means a state where a large number of gas bubbles are gathered, "Foam", and each gas bubble has a diameter of approximately several μm to several hundred μm. In an emulsion, the droplets generally have a diameter of 0.1 μm to several hundred μm.

[0014] <Aqueous sol> Generally, an aqueous sol refers to a colloidal dispersion system having an aqueous solvent as a dispersion medium and colloidal particles as a dispersed phase. In the present invention, an aqueous sol having an aqueous medium (water) with a pH in the acidic region as a dispersion medium and silica particles surface-treated with specific functional groups as a dispersed phase is targeted. That is, the present invention is directed to an aqueous sol having silica particles (hereinafter also referred to as "silica particles surface-treated with a silane compound" or "surface-treated silica particles") at least partially covered on the surface with a silane compound having a hydrolyzable group (hereinafter also simply referred to as "silane compound") as a dispersed phase and an aqueous solvent with a pH of 1.0 or more and 6.0 or less as a dispersion medium. In the present invention, "at least partially covered on the surface with a silane compound having a hydrolyzable group" means a mode in which a silane compound having a hydrolyzable group is bonded to at least a part of the surface of the silica particles, that is, a mode in which the silane compound covers the entire surface of the silica particles, a mode in which the silane compound covers a part of the surface of the silica particles, and a mode in which the silane compound is bonded to the surface of the silica particles are included.

[0015] The silica particles (surface-treated silica particles) in the aqueous sol of the present invention can be evaluated for their dispersion state together with the average particle size (DLS average particle size) by measurement using the dynamic light scattering method. The DLS average particle size represents the average value of the secondary particle size (dispersed particle size). The DLS average particle size in a completely dispersed state is said to be about twice the average primary particle size (the specific surface area diameter obtained by measurement using the nitrogen gas adsorption method (BET method) or the Shear method, which represents the average value of the primary particle size). That is, by measuring the DLS average particle size, it is possible to determine whether the colloidal particles (surface-treated silica particles in the present invention) in the aqueous sol are in a dispersed state or an aggregated state, and it can be determined that the larger the DLS average particle size, the more the colloidal particles in the aqueous sol are in an aggregated state. In the present invention, the average particle diameter (DLS particle diameter) of the surface-treated silica particles in the aqueous sol can be 1 to 100 nm, or 1 to 50 nm, or 3 to 30 nm, or 5 to 15 nm. By making the particles with a DLS average particle diameter larger than 1 nm, the particles do not aggregate in the aqueous sol and become more stable. Also, by making the average particle diameter smaller than 100 nm, it becomes easier to penetrate into the pores of sandstone and carbonate rocks existing in the underground oil reservoir layer, and the crude oil recovery rate can be made good.

[0016] In the surface-treated silica particles in the aqueous sol, the ratio of the silane compound to the silica particles is, by mass, for example, a ratio of 0.01 to 2.00:1.00, or a ratio of 0.30 to 2.00:1.00, or a ratio of 0.33 to 2.00:1.00, or a ratio of 0.33 to 1.00:1.00. By setting the mass ratio of the silane compound to 0.01 part or more, preferably 0.30 part or more, with respect to 1.00 part of the silica particles in the aqueous sol, it can be expected to improve the salt resistance of the aqueous sol. However, even if the same mass ratio is more than 2.00 parts, no further improvement in the effect can be expected.

[0017] In the aqueous sol, the concentration (solid content concentration) of the surface-treated silica particles can be, for example, 1 to 40% by mass.

[0018] The aqueous sol of the present invention preferably does not have an isoelectric point in the range of pH 6 or less, for example, pH 1 to 6. Thereby, it can be expected to be a stable aqueous sol that does not aggregate.

[0019] Generally, the salt concentration of seawater is about 30,000 ppm to 40,000 ppm, the salt concentration of oil fields and gas fields in Japan is about 10,000 ppm to 50,000 ppm, and the salt concentration of formation water overseas (e.g., Abu Dhabi carbonate rock oil field) is about 160,000 ppm. In view of injecting the aqueous sol of the present invention into the oil layer of inland or submarine oil fields, it has high salt tolerance in an environment containing a salt concentration of approximately 10,000 ppm (equivalent to 1.0% by mass) to exceeding 200,000 ppm. That is, in the above environment, it is desired that the silica particles in the aqueous sol do not aggregate, do not gel, and maintain a dispersed state. In the present invention, for example, in an environment containing sodium chloride, calcium chloride, and magnesium chloride as main components and having a total salt concentration of 10,000 to 230,000 ppm, the salt tolerance (salt water stability) of the aqueous sol can be evaluated by a salt tolerance test in which the aqueous sol is stored at 80 °C for 30 days at a silica concentration of 1.0% by mass and a pH of 5.0 to 8.0. If the change in the average particle diameter in the measurement of the aqueous sol by dynamic light scattering before and after this test is small, it can be evaluated that the silica particles in the aqueous sol maintain a dispersed state. However, when the salt tolerance of the aqueous sol is poor, the DLS average particle diameter after the salt tolerance test becomes very large, which reflects the aggregated state of the silica particles in the sol. In the present invention, if the value of the average particle diameter in the measurement by dynamic light scattering after the above salt tolerance test is a difference of 200 nm or less compared to the value of the average particle diameter before the test, it can be determined that the aqueous sol has good salt tolerance. In particular, those with a difference in DLS average particle diameter before and after the test of 200 nm or less, for example, 160 nm or less, can be determined to be aqueous sols with no alteration (aggregation / gelation) of the silica sol and very good salt tolerance.

[0020] The silica particles in the aqueous sol of the present invention can stably maintain the form of foam or emulsion in a state containing water, oil, and carbon dioxide at a temperature of 30 to 120 °C and a pressure of 70 to 400 atmospheres. Here, "stable" means that the collapse or separation of the foam or emulsion does not occur. The inventors have confirmed that a foam or emulsion formed under static conditions for several hours can maintain a stable foam or emulsion state for several days. Carbon dioxide becomes a supercritical state under the conditions of 31.1 °C and 72.8 atmospheres or more. In the present invention, the oil in the rock pores is swept by water, oil, and carbon dioxide containing silica particles in the form of foam or emulsion. At this time, the carbon dioxide may be supercritical carbon dioxide in a homogeneous state, or carbon dioxide in a gas phase or liquid phase state.

[0021] The aqueous sol is obtained by mixing a silane compound having a hydrolyzable group and an (unmodified) aqueous silica sol and then performing heat treatment described below. Hereinafter, the aqueous silica sol and the silane compound having a hydrolyzable group constituting the aqueous sol will be described in detail.

[0022] 〈Aqueous silica sol〉 The aqueous silica sol (unmodified silica sol) constituting the aqueous sol of the present invention is an aqueous silica sol having colloidal silica as a dispersion medium, and can be produced by a known method using water glass (sodium silicate aqueous solution) as a raw material. The average particle diameter of the aqueous silica sol indicates the average particle diameter of the colloidal silica particles as the dispersion medium, and refers to the specific surface area diameter or the shear method particle diameter obtained by measurement by the nitrogen gas adsorption method (BET method) unless otherwise specified. The specific surface area diameter (average particle diameter (specific surface area diameter) D (nm)) obtained by measurement by the nitrogen gas adsorption method (BET method) is the specific surface area S (m 2 / g) is given by the formula D (nm) = 2720 / S. The shear method particle diameter refers to the average particle diameter measured based on the literature: G.W. Sears, Anal. Chem. 28 (12) p. 1981, 1956, A rapid method for measuring the particle diameter of colloidal silica. Specifically, it is the equivalent diameter (specific surface area diameter) calculated from the amount of 0.1N-NaOH required to titrate colloidal silica corresponding to 1.5 g of SiO2 from pH4 to pH9 to obtain the specific surface area of colloidal silica. In the present invention, the average particle diameter of the aqueous silica sol (colloidal silica particles) by the nitrogen gas adsorption method (BET method) or the shear method can be, for example, 1 to 100 nm, or 1 to 50 nm, or 3 to 30 nm, or 5 to 15 nm.

[0023] Commercially available products can be used as the aqueous silica sol. In addition, those having a silica concentration of 5 to 50% by mass in the aqueous silica sol are generally commercially available, which is preferable in terms of easy availability. In addition, there are alkaline aqueous silica sols and acidic aqueous silica sols for the aqueous silica sol. However, it is preferable to use an acidic aqueous silica sol having a pH of 1.0 or more and 6.0 or less because an aqueous sol excellent in salt resistance (non-aggregating) can be obtained. Examples of commercially available acidic aqueous silica sols include Snowtex (registered trademark) ST-OXS, ST-OS, ST-O (all manufactured by Nissan Chemical Industries, Ltd.). The silica (SiO2) concentration in the aqueous silica sol used for the aqueous sol can be, for example, 1 to 40% by mass.

[0024] 〈Silane compound〉 The silane compound used for the surface treatment of the aqueous silica sol is a silane compound having a hydrolyzable group. Examples of the hydrolyzable group include an alkoxy group, an acyloxy group, a halogen group, and the like. Among them, an alkoxy group such as a methoxy group or an ethoxy group is preferable as the hydrolyzable group. For example, it is preferable to use a silane compound having a methoxy group as the hydrolyzable group.

[0025] As the silane compound having the hydrolyzable group, a silane compound containing an epoxy group or an organic group obtained by hydrolyzing the epoxy group can be used in addition to the hydrolyzable group. Examples of the epoxy group include a glycidyl group, a cyclohexyl epoxy group, or a combination thereof. As will be described later, as the silane compound having the hydrolyzable group, a silane compound having an oxetane ring can be used instead of the epoxy group in addition to the hydrolyzable group. Examples of the silane compound having an epoxy group (and a hydrolyzable group) include 3-glycidoxypropyltrimethoxysilane, 3-glycidoxypropyltriethoxysilane, 3-glycidoxypropylmethyldimethoxysilane, 3-glycidoxypropylmethyldiethoxysilane, 3-glycidoxypropyltriethoxysilane, 3-(3,4-epoxycyclohexyl)propyltrimethoxysilane, 3-(3,4-epoxycyclohexyl)propyltriethoxysilane, 2-(3,4-epoxycyclohexyl)ethyltrimethoxysilane, 2-(3,4-epoxycyclohexyl)ethyltriethoxysilane, 1-(3,4-epoxycyclohexyl)methyltrimethoxysilane, 1-(3,4-epoxycyclohexyl)methyltriethoxysilane, etc. These can be used alone or in combination of two or more. Also, as described above, instead of the silane compound having an epoxy group, a silane compound having an oxetane ring can be used. For example, [(3-ethyl-3-oxetanyl)methoxy]propyltrimethoxysilane, [(3-ethyl-3-oxetanyl)methoxy]propyltriethoxysilane, etc. can be mentioned.

[0026] In addition, as the silane compound having a hydrolyzable group, a silane compound containing an amino group can be used in addition to the hydrolyzable group. Examples of the silane compound having an amino group (and a hydrolyzable group) include N-2-(aminoethyl)-3-aminopropylmethyldimethoxysilane, N-2-(aminoethyl)-3-aminopropyltrimethoxysilane, 3-aminopropyltrichlorosilane, 3-aminopropyltrimethoxysilane, 3-aminopropyltriethoxysilane, 3-aminopropylmethyldimethoxysilane, 3-aminopropylmethyldiethoxysilane, 3-triethoxysilyl-N-(1,3-dimethyl-butylidene)propylamine, N-phenyl-3-aminopropyltrimethoxysilane, N-phenyl-3-aminopropyltriethoxysilane, etc. These can be used alone or in combination of two or more.

[0027] In the present invention, the silane compound used for the surface treatment of the aqueous silica sol can further contain a second silane compound having a hydrolyzable group in addition to the silane compound having a hydrolyzable group (a silane compound containing an epoxy group or an organic group obtained by hydrolyzing an epoxy group, or a silane compound containing an amino group). The second silane compound having a hydrolyzable group may be a silane compound having an organic group containing an alkyl group having 1 to 40 carbon atoms, an aromatic ring group having 6 to 40 carbon atoms, or a combination thereof. Examples of the silane having a hydrolyzable group and an alkyl group having 1 to 40 carbon atoms include alkoxysilanes such as methyltrimethoxysilane, methyltriethoxysilane, dimethyldimethoxysilane, dimethyldiethoxysilane, trimethylmethoxysilane, ethyltrimethoxysilane, ethyltriethoxysilane, n-propyltrimethoxysilane, n-propyltriethoxysilane, isobutyltrimethoxysilane, isobutyltriethoxysilane, n-hexyltrimethoxysilane, n-hexyltriethoxysilane, cyclohexylmethyldimethoxysilane, n-octyltriethoxysilane, and n-decyltrimethoxysilane, and these can be used alone or in combination of two or more. Examples of the silane having a hydrolyzable group and an aromatic ring group having 6 to 40 carbon atoms include phenyltrimethoxysilane, phenyltriethoxysilane, diphenyldimethoxysilane, and diphenyldiethoxysilane. By using the second silane compound having a hydrolyzable group in combination, it is expected that the stabilization effect of the foam or emulsion in the liquid during CO2 foam flooding can be further enhanced. The second silane compound having a hydrolyzable group is preferably used in combination with a silane compound having a hydrolyzable group containing an amino group. In the present invention, a silane compound having a hydrolyzable group and containing an epoxy group or a hydrolyzed organic group thereof or a silane compound containing an amino group (first silane compound) is used as an essential component, and if desired, a silane compound having a hydrolyzable group and an organic group containing an alkyl group having 1 to 40 carbon atoms, an aromatic ring group having 6 to 40 carbon atoms, or a combination thereof (second silane compound) is used to treat (modify) the surface of the silica particles. The ratio of the first silane compound to the second silane compound in all the silane compounds can be used in the range of 1.00:0 to 3.00 or 1.00:0 to 1.00 in terms of molar ratio.

[0028] As the silane compound used for the surface treatment of the aqueous silica sol, for example, 3-glycidoxypropyltrimethoxysilane, 3-glycidoxypropyltriethoxysilane, a combination of 3-glycidoxypropyltrimethoxysilane and 2-(3,4-epoxycyclohexyl)ethyltrimethoxysilane, and a combination of 3-aminopropyltriethoxysilane and phenyltrimethoxysilane can be mentioned.

[0029] Commercially available products can be used as the silane compound. For example, product names such as KBM-403 (3-glycidoxypropyltrimethoxysilane), KBE-403 (3-glycidoxypropyltriethoxysilane), KBM-303 (2-(3,4-epoxycyclohexyl)ethyltrimethoxysilane), KBE-903 (3-aminopropyltriethoxysilane), and KBM-103 (phenyltrimethoxysilane) manufactured by Shin-Etsu Chemical Co., Ltd. can be mentioned.

[0030] In the present invention, the surface of the silica particles of the aqueous silica sol is treated (coated) with a silane having a hydrolyzable group, and silane particles having a silane having an organic functional group bonded thereto are used. The combination of the pH of the raw material aqueous silica sol and the hydrolyzable group is important for salt resistance. When an acidic aqueous silica sol is used as the raw material, the hydrolyzable group of the silane can be used preferably with either a methoxy group or an ethoxy group. When the aqueous silica sol of the raw material is alkaline, if the hydrolysis group of the silane is a methoxy group, gelation tends to progress during production, and if it is an ethoxy group, the salt water resistance is low. Also, when an alkaline aqueous silica sol is used and coated with a silane having an ethoxy group as a hydrolysis group, the salt water resistance is low even if the pH is made acidic thereafter.

[0031] 〈Surface treatment method (method for producing aqueous sol)〉 The silica particles surface-treated with the silane compound can be obtained by adding a silane compound having the hydrolysis group to the aqueous silica sol, preferably an acidic aqueous silica sol having a pH of 1.0 or more and 6.0 or less, and then performing a heat treatment at, for example, 50 to 100 °C for 1 hour to 20 hours. At this time, the silane compound having the hydrolysis group may be added to the silica particles (silica solid content) in the aqueous silica sol at a mass ratio of, for example, silane compound:silica particles = 0.01 to 2.00:1.00, or at a ratio of 0.30 to 2.00:1.00, or at a ratio of 0.33 to 2.00:1.00, or at a ratio of 0.33 to 1.00:1.00. When the heat treatment temperature is less than 50 °C, the rate of partial hydrolysis of the hydrolysis group becomes slow and the efficiency of surface treatment deteriorates. On the other hand, when it is higher than 100 °C, a dry gel of silica is generated, which is not preferable. Also, when the heat treatment time is less than 1 hour, the hydrolysis reaction of the silane compound having the hydrolysis group is insufficient, and even if it is made longer than 20 hours, the hydrolysis reaction of the silane compound is almost in a saturated state, so it is not necessary to further increase the heating time. The silane compound that coats the silica particles includes cases where the hydrolysis group is completely hydrolyzed and coats the silica particles with a siloxane bond, and cases where some of the hydrolysis groups remain unreacted and the other hydrolysis groups are hydrolyzed to coat the silica particles with a siloxane bond. The amount of surface treatment (coating) with the silane compound having the hydrolysis group, that is, the silane compound bonded to the silica particle surface, is preferably, for example, 0.01 to 5, or 1 to 5 per 1 nm of the silica particle surface. 2 per, for example, 0.01 to 5, or 1 to 5 is suitable. The aqueous sol having silica particles surface-treated with the silane compound thus obtained as the dispersion medium becomes an aqueous sol dispersed in an aqueous solvent having a pH of 1.0 or higher and 6.0 or lower, that is, an aqueous sol stored at a pH of 1.0 or higher and 6.0 or lower.

[0032] In addition, it is also possible to obtain silica particles surface-treated by the same procedure as described above by using an alkaline (pH 8 or higher) aqueous silica sol and adding a silane compound having a hydrolyzable group thereto. However, an aqueous sol in which surface-treated silica particles obtained by using an alkaline aqueous silica sol as a raw material are dispersed in an aqueous medium has a significantly increased average particle diameter measured by the dynamic light scattering method after the above-mentioned salt tolerance test, that is, the silica particles aggregate and the stability tends to decrease, so attention is required. Further, when silica particles surface-treated under alkaline conditions are obtained, it has been confirmed that the aqueous sol in which these are dispersed has low foaming properties in a mixed system of water, carbon dioxide, and a crude oil substitute (hydrocarbon (decane)), and it is considered that it is difficult to exhibit an effect in crude oil recovery by carbon dioxide foam. Then, an acidic aqueous silica sol (aqueous sol) obtained by making an alkaline aqueous silica sol (aqueous sol) in which silica particles are surface-treated under alkaline conditions acidic (for example, pH 1.0 to 6.0) using, for example, hydrochloric acid has an increased average particle diameter measured by the dynamic light scattering method after the above-mentioned salt tolerance test, the silica particles aggregate, and the stability decreases. Even when this acidic aqueous silica sol is used, the foaming property is low in a mixture system of water, carbon dioxide, and a crude oil substitute (decane). In addition, the rock pores contributing to the flow of the fluid are several μm or more, and it is considered that the aggregated and gelled aqueous silica sol hardly passes through the rock pores of several μm in the rock core sweep test. Therefore, the above-mentioned alkaline aqueous silica sol (aqueous sol) surface-treated with a silane compound under alkaline conditions and the acidic aqueous silica sol (aqueous sol) obtained by making the alkaline aqueous silica sol acidic are not suitable for the crude oil recovery of the present invention.

[0033] <Crude Oil Recovery Method> As a procedure for recovering crude oil from a subsurface hydrocarbon-containing layer using the aqueous sol of the present invention, as an example, it can be carried out including (a) step: injecting the aqueous sol of the present invention, water, and carbon dioxide into the subsurface layer respectively or simultaneously, and (b) step: recovering crude oil from a production well drilled in the subsurface layer to the ground.

[0034] The water injected in the step (a) may be brine containing chloride ions and sodium ions, calcium ions, magnesium ions, etc., or may be seawater (for example, seawater is used when it is assumed to be used in the oil layer of an offshore oil field). The salt concentration of these brines and seawater is not particularly limited, but is generally about 10,000 to 230,000 ppm as described above.

[0035] When injecting, the ratio of the surface-treated silica particles in the aqueous sol to water (or brine, seawater) is, for example, about 1:3 to 1000 by mass ratio, and the ratio of water (or brine, seawater) to carbon dioxide can be, for example, 1:0.01 to 100 by volume ratio. The injection pressure is preferably above the natural injection pressure due to the gravity of the fluid from the injection well and below the higher pressure of the initial pressure of the target reservoir layer or the formation fracture pressure of the cap rock. Also, the injection process can be carried out, for example, at a temperature of 30 to 120 °C and a pressure of 70 to 400 atmospheres.

[0036] The step (a) can be, for example, a step of alternately injecting the aqueous sol and water and carbon dioxide into the subsurface layer. Carbon dioxide can be injected as supercritical carbon dioxide or liquid carbon dioxide.

[0037] Also, in the step (a), optional components for crude oil recovery may be added to the aqueous sol or water. Such optional components can include, but are not limited to, surfactants, thickeners, deoxidizers, corrosion inhibitors, anti-algal agents, bactericides, scale inhibitors, etc.

[0038] The underground layer targeted by the crude oil recovery method is not particularly limited. For example, it can target a layer containing sandstone or a layer containing carbonate rock. In the present invention, when an aqueous sol, water, and carbon dioxide are injected into a formation rock, by making the zeta potential of the silica particles in the aqueous sol and the formation rock both negative or both positive, aggregation of the silica particles in the rock pores can be prevented, which is suitable for the formation and maintenance of a stable CO2 foam and the improvement of crude oil recovery efficiency based thereon. In the present invention, the liquid carbon dioxide injected into the formation forms a CO2 foam underground. The mixture containing the aqueous sol, water, and carbon dioxide has an increased viscosity, and the fluid with the increased viscosity is considered to sweep the oil in the rock pores. The viscosity of these mixtures is preferably in the range of, for example, 1 cP to 100 cP, or 1 cP to 50 cP.

[0039] Subsequent to step (a), step (b): a step of recovering crude oil from the production well drilled in the underground layer to the ground is carried out.

Examples

[0040] (The following apparatuses were used for the analysis in the examples and comparative examples.) · pH: Measured by a pH meter (manufactured by Toa DKK Corporation). · Viscosity: Measured by an Ostwald viscometer (manufactured by AS ONE Corporation). · Average primary particle size in the measurement by the nitrogen gas adsorption method (BET method): For the silica powder obtained by drying the aqueous silica sol to obtain a silica solid, pulverizing it, and further drying it, it was calculated based on the specific surface area value obtained using a specific surface area measurement device Monosorb (manufactured by Quantachrome Instruments). · Average particle size (DLS average particle size) in the measurement by the dynamic light scattering method: After diluting the aqueous sol, it was measured by a dynamic light scattering particle size measurement device Zetasizer Nano (manufactured by the Malvern Panalytical Business Unit of Spectris Co., Ltd.). · Zeta potential: Using a zeta potential, particle size, and molecular weight measurement system ELSZ-2000ZS (manufactured by Otsuka Electronics Co., Ltd.), after diluting the aqueous sol, 0.4 M sulfuric acid was added to adjust the pH to 2, and then 0.25 M aqueous NaOH solution was added while increasing the pH to measure the zeta potential at each pH. · Composition of rock core samples: The rock core samples were pulverized, and composition information (in terms of metal oxides) of the rock core samples was obtained using a wavelength dispersive small fluorescence X-ray analyzer Supermini200 (manufactured by Rigaku Corporation). · Shape observation of rock core samples: The shape of the surface of the rock core samples was observed using a scanning electron microscope JSM-6010LV (manufactured by JEOL Ltd.).

[0041] (Salt composition of the brine used for evaluation) The salt compositions of domestic oilfield formation water (salt concentration: 14,000 ppm), low-salt-concentration brine (same: 35,000 ppm), medium-salt-concentration brine (same: 175,000 ppm), and high-salt-concentration brine (same: 229,000 ppm) used for evaluation are shown in Table 1.

[0042]

Table 1

[0043] Example 1: Production of an aqueous sol containing silica particles surface-treated with 3-glycidoxypropyltrimethoxysilane (GPS) Into a 500 mL glass eggplant flask, 300 g of an aqueous silica sol (manufactured by Nissan Chemical Industries, Ltd., Snowtex (registered trademark) ST-OXS, silica concentration 10.5 mass%, average primary particle diameter 5 nm, pH 3.0) and a stir bar were added. Then, while stirring with a magnetic stirrer, 13.5 g of 3-glycidoxypropyltrimethoxysilane (GPS) (trade name KBM-403, manufactured by Shin-Etsu Chemical Co., Ltd.) was added so that the mass ratio of the silane compound to 1.00 part of the silica particles in the aqueous silica sol was 0.43 part. Subsequently, a cooling tube through which tap water was flowing was installed at the top of the eggplant flask, and the aqueous silica sol was heated to 80°C and held at 80°C for 8 hours while refluxing. After cooling to room temperature, the aqueous silica sol was taken out, and 313.5 g of an aqueous silica sol surface-treated with a silane compound (GPS) (hereinafter, the aqueous sol of Example 1, mass ratio of silane compound to 1.00 part of silica particles = 0.43 part, silica concentration 11.0 mass%, pH 3.1, viscosity 1.8 cP, specific gravity 1.06, DLS average particle diameter 8.0 nm) was obtained.

[0044] Example 2: Production of an aqueous sol containing silica particles surface-treated with 3-aminopropyltriethoxysilane (APTES) and phenyltrimethoxysilane (PTMS) Into a 500 mL glass eggplant flask, 300 g of an aqueous silica sol (manufactured by Nissan Chemical Industries, Ltd., Snowtex (registered trademark) ST-OXS, silica concentration 10.5% by mass, average primary particle diameter 5 nm, pH 3.0) and a stir bar were added. Then, while stirring with a magnetic stirrer, 6.9 g of 85% DL-lactic acid (manufactured by Sigma-Aldrich) was added. Next, 9.5 g of 3-aminopropyltriethoxysilane (APTES) (trade name KBE-903, manufactured by Shin-Etsu Chemical Co., Ltd.) was added so that the mass ratio of the silane compound to 1.00 part of the silica particles in the aqueous silica sol was 0.30 part. The container was sealed and held in an oven at 60°C for 12 hours. Subsequently, while stirring with a magnetic stirrer, 1.7 g of phenyltrimethoxysilane (PTMS) (trade name KBM-103, manufactured by Shin-Etsu Chemical Co., Ltd.) was added so that the mass ratio of the silane compound to 1.00 part of the silica particles in the aqueous silica sol was 0.05 part. A cooling tube through which tap water was flowing was installed at the top of the eggplant flask, and the aqueous silica sol was heated to 60°C and held at 60°C for 3 hours while refluxing. After cooling to room temperature, the aqueous silica sol was taken out, and 318.1 g of an aqueous silica sol surface-treated with a silane compound (APTES + PTMS) (hereinafter, the aqueous sol of Example 2, mass ratio of the total silane compound to 1.00 part of the silica particles = 0.35 part, silica concentration 10.8% by mass, pH 4.0, viscosity 1.8 cP, specific gravity 1.06, DLS average particle diameter 13.0 nm) was obtained.

[0045] Example 3: Production of an aqueous sol containing silica particles surface-treated with 3-glycidoxypropyltrimethoxysilane (GPS) and 2-(3,4-epoxycyclohexyl)ethyltrimethoxysilane (EPCHS) A 500 mL glass eggplant flask was charged with 300 g of an aqueous silica sol (manufactured by Nissan Chemical Industries, Ltd., Snowtex (registered trademark) ST-OXS, silica concentration 10.5% by mass, average primary particle size 5 nm, pH 3.0) and a stir bar. While stirring with a magnetic stirrer, 13.5 g of 3-glycidoxypropyltrimethoxysilane (GPS) (trade name KBM-403, manufactured by Shin-Etsu Chemical Co., Ltd.) was added so that the mass ratio of the silane compound to 1.00 part of the silica particles in the aqueous silica sol was 0.43 part. Subsequently, a cooling tube through which tap water was flowing was installed at the top of the eggplant flask, and the temperature of the aqueous silica sol was raised to 80 °C and held at 80 °C for 8 hours while refluxing. After cooling to room temperature, 7.0 g of 2-(3,4-epoxycyclohexyl)ethyltrimethoxysilane (EPCHS) (trade name KBM-303, manufactured by Shin-Etsu Chemical Co., Ltd.) was added so that the mass ratio of the silane compound to 1.00 part of the silica particles in the aqueous silica sol was 0.22 part while stirring with a magnetic stirrer. Subsequently, a cooling tube through which tap water was flowing was installed at the top of the eggplant flask, and the temperature of the aqueous silica sol was raised to 60 °C and held at 60 °C for 3 hours while refluxing. After cooling to room temperature, the aqueous silica sol was taken out, and 320.5 g of an aqueous silica sol surface-treated with a silane compound (GPS + EPCHS) (hereinafter, the aqueous sol of Example 3, mass ratio of the total silane compound to 1.00 part of the silica particles = 0.65 part, silica concentration 11.4% by mass, pH 3.1, viscosity 2.2 cP, specific gravity 1.06, DLS average particle size 8.9 nm) was obtained.

[0046] Example 4: Production of an aqueous sol containing silica particles surface-treated with 3-glycidoxypropyltrimethoxysilane (GPS) and 2-(3,4-epoxycyclohexyl)ethyltrimethoxysilane (EPCHS) A 500 mL glass eggplant flask was charged with 300 g of an aqueous silica sol (manufactured by Nissan Chemical Industries, Ltd., Snowtex (registered trademark) ST-OS, silica concentration 20.5% by mass, average primary particle diameter 9 nm, pH 3.0) and a stir bar. While stirring with a magnetic stirrer, 14.6 g of 3-glycidoxypropyltrimethoxysilane (GPS) (trade name KBM-403, manufactured by Shin-Etsu Chemical Co., Ltd.) was added so that the mass ratio of the silane compound to 1.00 part of the silica particles in the aqueous silica sol was 0.24 part. Subsequently, a cooling tube through which tap water was flowing was installed at the top of the eggplant flask, and the aqueous silica sol was heated to 80°C and held at 80°C for 8 hours while refluxing. After cooling to room temperature, while stirring with a magnetic stirrer, 15.2 g of 2-(3,4-epoxycyclohexyl)ethyltrimethoxysilane (EPCHS) (trade name KBM-303, manufactured by Shin-Etsu Chemical Co., Ltd.) was added so that the mass ratio of the silane compound to 1.00 part of the silica particles in the aqueous silica sol was 0.25 part. Subsequently, a cooling tube through which tap water was flowing was installed at the top of the eggplant flask, and the aqueous silica sol was heated to 60°C and held at 60°C for 3 hours while refluxing. After cooling to room temperature, the aqueous silica sol was taken out, and 329.8 g of an aqueous silica sol surface-treated with a silane compound (GPS + EPCHS) (hereinafter, the aqueous sol of Example 4, mass ratio of the total silane compound to 1.00 part of the silica particles = 0.49 part, silica concentration 20.8% by mass, pH 2.9, viscosity 3.3 cP, specific gravity 1.13, DLS average particle diameter 18.2 nm) was obtained.

[0047] Comparative Example 1: Production of an aqueous sol containing silica particles surface-treated with 3-glycidoxypropyltriethoxysilane (GPTES) Water was added to commercially available sodium water glass (JIS No. 3 sodium water glass: SiO2 concentration 28.8% by mass, Na2O concentration 9.5% by mass) to obtain an aqueous sodium silicate solution with a silica concentration of 3.8% by mass. This aqueous sodium silicate solution was passed through a column filled with a hydrogen-type strongly acidic cation exchange resin (Amberlite IR-120B, manufactured by Dow Chemical Company) to obtain a colloidal aqueous solution of active silica (silica concentration 3.6% by mass, pH 3.2). Into a reactor equipped with a stirrer, a heating device, etc. in a 3 L glass reaction vessel with an internal volume, 11.9 g of a 10% aqueous sodium hydroxide solution and 291.7 g of pure water were charged, and after heating to 55°C, while maintaining the temperature at 55°C, 732.0 g of the colloidal aqueous solution of the active silica was continuously supplied over 2 hours. Then, while raising the temperature to 80°C, 1464.4 g of the colloidal aqueous solution of the active silica was continuously supplied over 4 hours, and then held at 80°C for 6 hours to obtain 2500.0 g of an alkaline silica sol thin liquid (silica concentration 3.1% by mass, pH 9.7, average primary particle diameter 7 nm). Next, this alkaline silica sol thin liquid was concentrated using an ultrafiltration device to obtain an alkaline aqueous silica sol (silica concentration 28% by mass, average primary particle diameter 7 nm, pH 9.0, viscosity 5 cP, specific gravity 1.2, DLS average particle diameter 9.4 nm). Into a 500 mL glass eggplant flask, 250 g of this alkaline aqueous silica sol and a stir bar were added, and then, while stirring with a magnetic stirrer, an HCl aqueous solution was added to adjust the pH to 8. 18.9 g of 3-glycidoxypropyltriethoxysilane (GPTES) (trade name KBE-403 manufactured by Shin-Etsu Chemical Co., Ltd.) was added so that the mass ratio of the silane compound to 1.00 part of the silica particles in the aqueous silica sol was 0.27 part, and then held at 23°C for 2 hours. This aqueous silica sol was taken out to obtain 269.0 g of an aqueous silica sol surface-treated with a silane compound (GPTES) (hereinafter, the aqueous sol of Comparative Example 1, mass ratio of silane compound to 1.00 part of silica particles = 0.27 part, silica solid content = 28% by mass, average primary particle diameter 7 nm, pH 8, viscosity 5 cP, specific gravity 1.2, DLS average particle diameter 19.0 nm).

[0048] Comparative Example 2: Production of an aqueous sol containing silica particles surface-treated with 3-glycidoxypropyltrimethoxysilane (GPS) A 500-ml glass eggplant flask was charged with 300 g of an aqueous silica sol (manufactured by Nissan Chemical Industries, Ltd., Snowtex (registered trademark) ST-XS, silica concentration 20.5% by mass, average primary particle size 5 nm, pH 9.5) and a stir bar. Then, while stirring with a magnetic stirrer, 26.3 g of 3-glycidoxypropyltrimethoxysilane (GPS) (trade name KBM-403, manufactured by Shin-Etsu Chemical Co., Ltd.) was added so that the mass ratio of the silane compound to 1.00 part of the silica particles in the aqueous silica sol was 0.43 part. After that, it was held at 23°C for 2 hours. The aqueous silica sol surface-treated with the silane compound (GPS) aggregated and became turbid during the manufacturing process, and a uniform aqueous silica sol could not be obtained.

[0049] [Zeta potential measurement results] Figure 1 shows the measurement results of the zeta potential at each pH from pH 2 to pH 10 for the aqueous sols (aqueous silica sols surface-treated with a silane compound) prepared in Example 1 and Example 2. As shown in Figure 1, the zeta potential of the aqueous sol of Example 1 was negative at pH 6 or lower, and the zeta potential of the aqueous sol of Example 2 was positive at pH 6 or lower. Both aqueous sols were sols that did not have an isoelectric point at pH 6 or lower.

[0050] [Saline stability test] Using the aqueous sols of Example 1 and Comparative Example 1, a stability test against saline was carried out. The aqueous sol of Example 1 (a silica sol in which silica particles were surface-treated with 3-glycidoxypropyltrimethoxysilane (GPS), silane compound:silica particles = 0.43:1 (mass ratio), pH 3.1, DLS average particle size 8.0 nm) or the aqueous sol of Comparative Example 1 (a silica sol in which silica particles were surface-treated with 3-glycidoxypropyltriethoxysilane (GPTES), silane compound:silica particles = 0.27:1 (mass ratio), pH 8, DLS average particle size 19.0 nm) was added to saline so that the silica concentration became 1.0% by mass. At this time, samples for the saline stability test were prepared so as to have a low salt concentration (salt concentration 35,000 ppm), a medium salt concentration (salt concentration 175,000 ppm), or a high salt concentration (salt concentration 229,000 ppm). In addition, an aqueous solution of NaOH was added to the sample of Example 1, and an aqueous solution of HCl was added to the sample of Comparative Example 1 to prepare an aqueous sol adjusted to an arbitrary pH, which was used for the brine stability test.

[0051] Each prepared sample was stored at a temperature of 80°C, and the change in the average particle diameter (DLS average particle diameter: nm) in the measurement by the dynamic light scattering method was measured. The results obtained are shown in Fig. 2 and Table 2 (low salt concentration: 35,000 ppm), Fig. 3 and Table 3 (medium salt concentration: 175,000 ppm), and Fig. 4 and Table 4 (high salt concentration: 229,000 ppm), respectively. In addition, the sample of "Example 1, pH 3" in the "aqueous sol" column of Table 2 was obtained by adjusting the aqueous sol obtained in Example 1 to pH 3, storing it, and then diluting the silica concentration of the aqueous sol to 1.0 mass% with brine at a low salt concentration (35,000 ppm). The change in the DLS average particle diameter when the sample after dilution with brine (pH 6.4) was stored at 80°C is shown. The sample of "Example 1, pH 5" in the "aqueous sol" column of Table 2 was obtained by adjusting the aqueous sol obtained in Example 1 to pH 5, storing it, and then diluting the silica concentration of the aqueous sol to 1.0 mass% with brine at a low salt concentration (35,000 ppm). The change in the DLS average particle diameter when the sample after dilution with brine (pH 6.5) was stored at 80°C is shown. The sample of "Example 1, pH 6" in the "aqueous sol" column of Table 2 was obtained by adjusting the aqueous sol obtained in Example 1 to pH 6, storing it, and then diluting the silica concentration of the aqueous sol to 1.0 mass% with brine at a low salt concentration (35,000 ppm). The change in the DLS average particle diameter when the sample after dilution with brine (pH 6.7) was stored at 80°C is shown. The sample of "Example 1, pH 9" in the "aqueous sol" column of Table 2 was obtained by adjusting the aqueous sol obtained in Example 1 to pH 9, storing it, and then diluting the silica concentration of the aqueous sol to 1.0 mass% with brine at a low salt concentration (35,000 ppm). The change in the DLS average particle diameter when the sample after dilution with brine (pH 7.0) was stored at 80°C is shown. The sample of "Comparative Example 1, pH 8" in the "Aqueous Sol" column of Table 2 was prepared by adjusting the pH of the aqueous sol obtained in Comparative Example 1 to pH 8, storing it, and then diluting the aqueous sol with low-salt-concentration (35,000 ppm) brine so that the silica concentration of the aqueous sol became 1.0% by mass. The resulting sample after dilution with brine (pH 6.9) shows the change in the DLS average particle diameter during storage at 80°C. Also, the sample of "Comparative Example 1, pH 3" in the "Aqueous Sol" column of Table 2 was prepared by adjusting the pH of the aqueous sol obtained in Comparative Example 1 to pH 3, storing it, and then diluting the aqueous sol with low-salt-concentration (35,000 ppm) brine so that the silica concentration of the aqueous sol became 1.0% by mass. The resulting sample after dilution with brine (pH 6.4) shows the change in the DLS average particle diameter during storage at 80°C. Similarly, the samples shown in Tables 3 and 4 were prepared by adjusting the pH of the aqueous sols of Example 1 and Comparative Example 1 (refer to the pH values in the "Aqueous Sol" column), storing them, and then diluting the aqueous sols with medium-salt-concentration to high-salt-concentration brine so that the silica concentration of the aqueous sols became 1.0% by mass and the pH was in the range of 5.0 to 8.0 (refer to the pH column of the brine stability test samples). The change in the DLS average particle diameter of the resulting samples after dilution with brine was measured during storage at 80°C for 30 days. As shown in Figure 2 and Table 2 (low-salt concentration), Figure 3 and Table 3 (medium-salt concentration), and Figure 4 and Table 4 (high-salt concentration), compared with the aqueous sol of Comparative Example 1, the aqueous sols of Example 1 with pH 3 to 6 showed a smaller change in the DLS average particle diameter even after storage at 80°C for 30 days. However, when using aqueous sols with pH 9 in the case of low-salt concentration and medium-salt concentration, and pH 7 or higher in the case of high-salt concentration, even in the aqueous sol of Example 1, the change in the average particle diameter was large, and after 30 days of storage, the change in the DLS average particle diameter before storage exceeded 200 nm.

[0052]

Table 2

[0053]

Table 3

[0054]

Table 4

[0055] [Foaming test] Using the aqueous sols of Example 1, Example 2, Example 3, Example 4, and Comparative Example 1, a foaming test was carried out with the apparatus shown in Fig. 5 according to the following procedure. Salt water (silica concentration 1.0 mass%) containing the surface-treated aqueous silica sol (aqueous sols of Examples 1 to 4, Comparative Example 1) was put into a pressure-resistant cell for visual observation with an observation window (manufactured by Tama Seiki Kogyo Co., Ltd., volume 150 mL). After that, the pressure-resistant cell was heated to a temperature of 100 °C, and carbon dioxide (manufactured by Nippon Yecarbon Co., Ltd., purity 99.99% or more) was injected until the internal pressure reached 100 atm, 200 atm, or 300 atm. After stirring at a stirring bar rotation speed of 1000 to 1500 rpm for 15 minutes, the stirring was stopped and left to stand, and the formation state of foam or emulsion was observed and evaluated through the observation window.

[0056] 〈Foaming test 1〉 Using the aqueous sols of Example 1 and Example 2, and Comparative Example 1, a foaming test was carried out using a crude oil substitute (n-decane). The aqueous sol of Example 1 (silica sol with silica particles surface-treated with 3-glycidoxypropyltrimethoxysilane (GPS), silane compound:silica particles = 0.43:1 (mass ratio)), the aqueous sol of Example 2 (silica sol with silica particles surface-treated with 3-aminopropyltriethoxysilane (APTES) and phenyltrimethoxysilane (PTMS), silane compound:silica particles = 0.35:1 (mass ratio)), or the aqueous sol of Comparative Example 1 (silica sol with silica particles surface-treated with 3-glycidoxy triethoxysilane (GPTES), silane compound:silica particles = 0.27:1 (mass ratio)) was added to salt water so that the silica concentration became 1.0 mass%, and three types of salt water samples for foaming test 1 (salt concentration: 229,000 ppm (high salt concentration salt water)) were prepared. This was mixed so that it became (a) the brine sample of foaming test 1: carbon dioxide = 50:50 (volume ratio), or (b) the brine sample of foaming test 1: carbon dioxide: decane = 20:60:20 (volume ratio), and was stirred at a rotational speed of 1500 rpm for 15 minutes at a temperature of 100 ° C and pressures of 100 atm, 200 atm, or 300 atm. Observation photos immediately after stopping the stirring (0 minutes) and after standing for 30 minutes of each mixture sample are shown in Fig. 6.

[0057] In the observation photos shown in Fig. 6 and Figs. 7 and 8 described later, the cloudy part (uniform white part) seen in each circle (observation window) indicates the formation of foam or emulsion, and the dark part seen on the lower side in the circle indicates brine. Also, when voids or color unevenness are seen in the cloudy part within the circle, it indicates that the formation of foam or emulsion is insufficient. By forming foam or emulsion, these can enter the pores in the rock core and function in the recovery of crude oil.

[0058] As shown in Fig. 6(a), in the sample mixed at a volume ratio of the brine sample of foaming test 1 (described as "brine" in Fig. 6) / carbon dioxide = 50 / 50, the samples using the aqueous sols of Example 1 and Example 2 showed high foaming properties. Furthermore, as shown in Fig. 6(b), in the foaming test using a crude oil substitute (n-decane): the sample mixed at a volume ratio of the brine sample of foaming test 1 / carbon dioxide / decane = 20 / 60 / 20, the samples using the aqueous sols of Example 1 and Example 2 showed high foaming properties. These results were results suggesting that the aqueous sols of Example 1 and Example 2 had a high ability to sweep the crude oil in the pores in the core sample. On the other hand, in the comparative example, as shown in the test using a crude oil substitute in particular (Fig. 6(b)), voids and color unevenness were seen in the upper part of the circle immediately after stopping the stirring for 15 minutes (0 minutes) and after standing for 30 minutes, indicating that the formation of foam or emulsion was insufficient and suggesting inferior crude oil sweeping ability.

[0059] 〈Foaming Test 2〉 Foaming property tests were carried out using the aqueous sols of Example 3, Example 4, and Comparative Example 1. The aqueous sols of Example 3 (a silica sol in which silica particles were surface-treated with 3-glycidoxypropyltrimethoxysilane (GPS) and epoxycyclohexylethyltrimethoxysilane (EPCHS), silane compound:silica particles = 0.65:1 (mass ratio)), Example 4 (a silica sol in which silica particles were surface-treated with 3-glycidoxypropyltrimethoxysilane (GPS) and epoxycyclohexylethyltrimethoxysilane (EPCHS), silane compound:silica particles = 0.49:1 (mass ratio)), or Comparative Example 1 (a silica sol in which silica particles were surface-treated with 3-glycidoxypropyltriethoxysilane (GPTES), silane compound:silica particles = 0. .27:1 (mass ratio)) were added to brine so that the silica concentration became 1.0% by mass, and three brine samples (salt concentration: 14,000 ppm (domestic oil field formation water)) of Foaming Property Test 2 were prepared. This was mixed so that the brine sample of Foaming Property Test 2: carbon dioxide = 50:50 (volume ratio), and stirred at a temperature of 100 °C, a pressure of 185 atm or 300 atm, and a stirring speed of the stirrer of 1000 rpm, 1250 rpm, or 1500 rpm for 15 minutes. Observation photographs immediately after stopping the stirring of each mixture sample and after standing for 30 minutes after stirring at 1500 rpm for 15 minutes are shown in Fig. 7. As shown in Fig. 7, the samples using the aqueous sols of Example 3 and Example 4 showed high foaming properties, suggesting that they have a high ability to sweep the crude oil in the pores of the rock core.

[0060] <Foaming Property Test 3: Long-Term Stability Test of Foam or Emulsion> Aqueous sol of Example 1 (silica sol with silica particles surface-treated with 3-glycidoxypropyltrimethoxysilane (GPS), silane compound:silica particles = 0.43:1 (mass ratio)) and aqueous sol of Example 2 (silica sol with silica particles surface-treated with 3-aminopropyltriethoxysilane (APTES) and phenyltrimethoxysilane (PTMS), silane compound:silica particles = 0.35:1 (mass ratio)) were each added to brine so that the silica concentration became 1.0 mass%, and two types of brine samples (salt concentration: 229,000 ppm (high-salt-concentration brine)) for the foaming property test 3 were prepared. This was mixed so that the brine sample:carbon dioxide:decane for the foaming property test 3 was 20:60:20 (volume ratio), and stirred at a stirring bar rotation speed of 1500 rpm for 15 minutes at a temperature of 100 °C and a pressure of 200 atmospheres. After stopping the stirring of each mixture sample and allowing it to stand for 30 minutes, and then allowing it to stand for 1 day, 3 days, and 7 days, the observation photos are shown in Fig. 8. As shown in Fig. 8, the samples using the aqueous sols of Example 1 and Example 2 maintained high foaming properties even after standing for 7 days, and excellent long-term stability of the formed foam or emulsion was obtained.

[0061] 〈Observation of foam or emulsion〉 An aqueous sol of Example 1 (silica sol with silica particles surface-treated with 3-glycidoxypropyltrimethoxysilane (GPS), silane compound:silica particles = 0.43:1 (mass ratio)) was added so that the silica concentration became 1.0 mass%, and a brine sample for observing foam or emulsion (salt concentration: 229,000 ppm (high-salt-concentration brine), pH was 5.2.) was prepared. In addition, a water-soluble dye (methyl orange) represented by the following formula (1) was added to the brine sample for observing foam or emulsion so as to be 0.3 mass% in the brine.

Chemical formula

[0062] [Observation of the composition and shape of rock core samples] Regarding the rock core samples used for the crude oil recovery evaluation described later, their composition information was obtained and their shapes were observed according to the above procedure. The rock core samples used were Berea Sandstone (obtained from Core Lab Instruments, hereinafter referred to as BSS), which is a sandstone (SiO2-based), and Indiana 200md (obtained from Kocurek, hereinafter referred to as IN 200md), which is a carbonate rock (CaCO3-based). In various evaluation tests, as the rock core samples (sandstone samples or carbonate rock samples), cylindrical samples with a diameter of 1.5 inches and a length of 1 foot (about 3.8 cm in diameter and 30.5 cm in length) that were dried at 120°C for 1 day after reflux extraction and washing with toluene for oil and water removal and then dried at 80°C for 1 day after reflux extraction and washing with methanol for salt removal were used. The compositional information (fluorescent X-ray analysis, oxide-converted composition) of each obtained sample is shown in Table 5. Also, Figure 15 shows the appearance photo of the rock core sample and the observation results of the surface shape (scanning electron microscope photo (magnification 500 times)) respectively ((a) sandstone (BSS) in Figure 15, (b) carbonate rock (IN 200md) in Figure 15).

[0063]

Table 5

[0064] [Pore Volume and Air Permeability of Rock Core Samples] For the said rock core samples, the porosity and air permeability were measured to obtain the pore volume. The porosity was measured by a helium porosimeter (manufactured by Core Lab Instruments). Also, the air permeability was measured by an air permeameter (manufactured by Core Lab Instruments). Five samples of sandstone (BSS) and nine samples of carbonate rock (IN 200md) were measured. The obtained results are shown in Tables 6 and 7.

[0065]

Table 6

[0066]

Table 7

[0067] In addition, as the carbonate rock sample: IN 200 md used for the crude oil recovery evaluation described later, from the K (air permeability)-Phi (porosity) plot shown in Fig. 16, medium permeability rock core samples (●) with an air permeability of about 150 ± 50 md were selected and used, excluding low permeability core samples (□) and high permeability core samples (△).

[0068] [Crude Oil Recovery Evaluation Using Rock Core Samples] Using the aqueous sol prepared in Example 1, a crude oil recovery evaluation assuming an underground oil reservoir was conducted by the core flow test apparatus (piping diagram) shown in Fig. 17, using Middle East-produced crude oil and rock core samples (sandstone (BSS) and carbonate rock (IN 200 md)) according to the following procedure. As shown in Fig. 17, the core flow test apparatus consists of an injection pump (manufactured by Schlumberger), a CO2 piston cylinder for fluid filling, a nanoparticle brine piston cylinder, a crude oil piston cylinder (all manufactured by VINCI Technologies), a core holder (manufactured by VINCI Technologies), an annulus pressure pump (manufactured by VINDUM ENGINEERING), a back pressure valve and a back pressure pump (manufactured by VINCI Technologies), a gas-liquid separator crude oil recovery unit for the recovered fluid (manufactured by VINCI Technologies), a wet gas meter for measuring the amount of free gas (manufactured by Shinagawa Co., Ltd.), a pressure gauge (manufactured by VALCOM), a thermistor for measuring the core temperature, the constant temperature bath temperature, and the free gas temperature (manufactured by Chino Corporation), and an air constant temperature bath (manufactured by Sunaoka Rika Kogyo Co., Ltd.). The upstream and downstream pressures of the core holder, the annulus pressure (side pressure) of the core holder, the back pressure valve control pressure, the core and constant temperature bath temperatures, the amount and temperature of the free gas were recorded every 1 second by a computer via a data logger (manufactured by GRAPHTEC).

[0069] 〈Test Example 1: Crude Oil Recovery Evaluation Using Sandstone (BSS)〉 A single sandstone (BSS) core sample inserted into a rubber sleeve was set in the core holder shown in Fig. 17. The annulus (confining pressure (lateral pressure) fluid-filled annular space) between the inside wall of the rubber sleeve and the core holder was evacuated, and pressurized fluid was sucked into the annulus from the confining pressure pump until it was saturated at atmospheric pressure. Then, the confining pressure (lateral pressure) was pressurized to 68.0 atmospheres with the confining pressure pump to confirm that there was no leakage into or out of the sandstone (BSS) core pores. The back pressure valve was set to 200 atmospheres, which was the test condition, with the back pressure pump. The injection pump 2 was connected to the crude oil piston cylinder, and crude oil was introduced into the evacuated sandstone (BSS) core pores and pressurized to 34.0 atmospheres, and the pump was controlled at a constant pressure. To set the differential pressure for the pressure setting of the crude oil recovery evaluation test (back pressure setting pressure + 68.0 atmospheres (1,000 psi)), the confining pressure (lateral pressure) was pressurized to 102.0 atmospheres, and the amount of crude oil introduced was recorded. The dead volume between the upstream and downstream valves of the core holder, which had been pre-measured, was subtracted from the amount of crude oil introduced at a differential pressure of 68.0 atmospheres to obtain the 100% crude oil saturation volume in the core pores, which was used as the core pore volume when calculating the crude oil recovery rate. While checking for leakage, the pressure was increased by 34.0 atmospheres in sequence for the confining pressure (lateral pressure) and the pressure inside the core pores, and finally, the confining pressure (lateral pressure), which was the test pressure, was set to 268.1 atmospheres, and the pressure inside the core pores was set to 200.0 atmospheres. The injection pump 2 was set to constant flow control, and crude oil was injected at a low flow rate to check the operation of the back pressure valve and the signal output status of the pressure gauge. The upstream valve of the crude oil piston cylinder was closed, and the internal pressure of the fluid-filled piston cylinder was controlled at a constant pressure of 200 atmospheres with injection pumps 1 and 2. The air thermostat was heated in steps from room temperature to 10°C and stabilized at the test temperature of 100°C. During the heating process, the volume of fluid expansion was such that the internal pressure of the fluid-filled piston cylinder was maintained at 200 atmospheres with injection pumps 1 and 2, the crude oil in the core holder was discharged from the back pressure valve and maintained at 200 atmospheres, and the confining pressure (lateral pressure) was maintained at 268.1 atmospheres with the confining pressure pump. Subsequently, a brine preparation solution containing the aqueous sol of Example 1 (a silica sol in which silica particles were surface-treated with 3-glycidoxypropyltrimethoxysilane (GPS)), brine (silica concentration: 1.0 mass%, salt concentration: 175,000 ppm (medium-salt-concentration brine)) was simultaneously injected from a nanoparticle brine piston cylinder and carbon dioxide from a CO2 piston cylinder at a ratio of 1:1 each, and injected into a crude oil-saturated sandstone (BSS) core sample in a core holder at a flow rate of 4 feet per day. As a comparative test example, carbon dioxide alone was injected into a core sample saturated with crude oil at a flow rate of 4 feet per day. The injection conditions of the injection fluid into the core sample were 100 °C, back-pressure control pressure: 200 atm, confining pressure (lateral pressure): 268.1 atm, and injection was carried out until the volume of the injection fluid reached 120% of the pore volume of the core sample. With the injection of the injection fluid (the aqueous sol of Example 1, brine, carbon dioxide) into the sandstone (BSS) core sample, the crude oil recovery rate was calculated from the amount of crude oil swept (recovered) from the pores of the core sample. The obtained results are shown in FIG. 18 and Table 8. Also, using a brine preparation solution containing the aqueous sol of Example 2 (a silica sol in which silica particles were surface-treated with 3-aminopropyltriethoxysilane (APTES) and phenyltrimethoxysilane (PTMS)), brine (silica concentration: 1.0 mass%, salt concentration: 175,000 ppm (medium-salt-concentration brine)), the crude oil recovery rate was evaluated in the same procedure. The obtained results are shown together with FIG. 18 and Table 8.

[0070] Figures 18 and Table 8 show the injection ratio of fluids (the aqueous sol of Example 1 or Example 2, brine, carbon dioxide) (fluid injection pore volume ratio (injected volume / pore volume): PV) with the total rock pore volume of the sandstone (BSS) core sample set to 1.0 on the horizontal axis, and the ratio (%) of the amount of crude oil recovered (swept) from the pores of the core sample on the vertical axis. In Figure 18, ● represents the result of simultaneously injecting brine (silica concentration 1.0 mass%, salt concentration 175,000 ppm) containing the aqueous sol of Example 1 (silica sol with silica particles surface-treated with 3-glycidoxypropyltrimethoxysilane (GPS)) and carbon dioxide at a ratio of 1:1 each, and injecting at a flow rate of 4 feet / day. ◇ represents the result of simultaneously injecting brine (silica concentration 1.0 mass%, salt concentration 175,000 ppm) containing the aqueous sol of Example 2 (silica sol with silica particles surface-treated with 3-aminopropyltriethoxysilane (APTES) and phenyltrimethoxysilane (PTMS)) and carbon dioxide at a ratio of 1:1 each, and injecting at a flow rate of 4 feet / day. ○ represents the result of injecting only carbon dioxide at a flow rate of 4 feet / day. As shown in Figure 18 and Table 8, when the injection ratio of the fluid into the pores of the sandstone (BSS) core sample is 1.20 (120%), the crude oil recovery rate is 58.5% when injecting the aqueous sol of Example 1, brine, and carbon dioxide, 61.6% when injecting the aqueous sol of Example 2, brine, and carbon dioxide, while the recovery rate is 50.5% when injecting only carbon dioxide.

[0071]

Table 8

[0072] 〈Test Example 2: Crude Oil Recovery Test Using Carbonate Rock (IN 200 md)〉 A carbonate rock (IN 200 md) core sample (one piece) inserted into a rubber sleeve was set in the core holder shown in Fig. 17. The annular space (confining pressure (lateral pressure) fluid-filled annular space) between the inside of the rubber sleeve and the inner wall of the core holder was evacuated, and after pressurized fluid was saturated by atmospheric pressure suction from the confining pressure pump into the annulus, the confining pressure (lateral pressure) was pressurized to 68.0 atmospheres with the confining pressure pump to confirm that there was no leakage into and outside the carbonate rock (IN 200 md) core pores. The back pressure valve was set to 200 atmospheres, which is the test condition, with the back pressure pump. The injection pump 2 was connected to the crude oil piston cylinder, and crude oil was introduced into the carbonate rock (IN 200 md) core pores in a vacuum state and pressurized to 34.0 atmospheres to control the pump at a constant pressure. To make the differential pressure the pressure setting for the crude oil recovery evaluation test (back pressure setting pressure + 68.0 atmospheres (1,000 psi)), the confining pressure (lateral pressure) was pressurized to 102.0 atmospheres and the amount of crude oil introduced was recorded. The dead volume between the upstream and downstream valves of the core holder, which had been previously measured, was subtracted from the amount of crude oil introduced at a differential pressure of 68.0 atmospheres, and the 100% crude oil saturation volume in the core pores was obtained and used as the core pore volume when calculating the crude oil recovery rate. While checking for leakage, the pressure was increased by 34.0 atmospheres in order, first the confining pressure (lateral pressure) and then the pressure inside the core pores. Finally, the confining pressure (lateral pressure), which is the test pressure, was set to 268.1 atmospheres and the pressure inside the core pores was set to 200.0 atmospheres. The injection pump 2 was set to constant flow rate control, and crude oil was injected at a low flow rate to check the operation of the back pressure valve and the signal output status of the pressure gauge. The upstream valve of the crude oil piston cylinder was closed, and the internal pressure of the fluid-filled piston cylinder was controlled at a constant pressure of 200 atmospheres with injection pumps 1 and 2. The air thermostat was heated in steps from room temperature to 10 °C and stabilized at the test set temperature of 100 °C. During the heating process, the fluid expansion volume was such that the internal pressure of the fluid-filled piston cylinder was maintained at 200 atmospheres with injection pumps 1 and 2, the crude oil in the core holder was discharged from the back pressure valve and maintained at 200 atmospheres, and the confining pressure (lateral pressure) was maintained at 268.1 atmospheres with the confining pressure pump. Subsequently, a brine preparation containing the aqueous sol of Example 1 (a silica sol with silica particles surface-treated with 3-glycidoxypropyltrimethoxysilane (GPS)) (brine with a silica concentration of 1.0 mass% and a salt concentration of 229,000 ppm (high-salt-concentration brine)) was simultaneously pressure-injected from a nanoparticle brine piston cylinder and carbon dioxide from a CO2 piston cylinder at a ratio of 1:1 each, and pressure-injected into a carbonate rock (IN 200 md) core sample saturated with crude oil in a core holder at a flow rate of 4 feet per day. As a comparative test example, carbon dioxide alone was pressure-injected into a core sample saturated with crude oil at a flow rate of 4 feet per day. The pressure injection conditions of the pressure injection fluid into the core sample were 100 °C, a backpressure control pressure of 200 atmospheres, and a confining pressure (lateral pressure) of 268.1 atmospheres, and pressure injection was carried out until the volume of the pressure injection fluid reached 120% of the pore volume of the core sample. Based on the amount of crude oil swept (recovered) from the pores of the carbonate rock (IN 200 md) core sample with the pressure injection of the pressure injection fluid (the aqueous sol of Example 1, brine, carbon dioxide), the crude oil recovery rate was calculated. The obtained results are shown in FIG. 19 and Table 9.

[0073] FIG. 19 and Table 9 show the pressure injection ratio of the fluid (the aqueous sol of Example 1, brine, carbon dioxide) (fluid pressure injection pore volume ratio (injection volume / pore volume): PV) with the total rock pore volume of the carbonate rock (IN 200 md) core sample as 1.0 on the horizontal axis, and the ratio (%) of the amount of crude oil swept (recovered) from the pores of the core sample on the vertical axis. In FIG. 19, ● indicates the result of simultaneously pressure-injecting the brine (salt concentration of 229,000 ppm) containing the aqueous sol of Example 1 (a silica sol with silica particles surface-treated with 3-glycidoxypropyltrimethoxysilane (GPS)) and carbon dioxide at a ratio of 1:1 each and pressure-injecting at a flow rate of 4 feet per day, and ○ indicates the result of pressure-injecting carbon dioxide alone at a flow rate of 4 feet per day. As shown in FIG. 19 and Table 9, when the pressure injection ratio of the fluid into the pores of the carbonate rock (IN 200 md) core sample reached 1.20 (120%), the crude oil recovery rate was 51.4% when the aqueous sol of Example 1, brine, and carbon dioxide were pressure-injected, while the recovery rate was 37.0% when carbon dioxide alone was pressure-injected.

[0074]

Table 9

[0075] 〈Test Example 3: Test for confirming the presence or absence of clogging of rock core pores of an aqueous sol (Example 1) using sandstone (BSS)〉 Using the aqueous sol of Example 1, a sample with a medium salt concentration (175,000 ppm), a silica concentration of 1.0% by mass, and a pH of 6.3 was prepared in the same manner as in the [brine stability test], and after storing it at 80°C for 7 days, an experiment was conducted to determine whether the sample clogged the pores of the rock core. The sample used in this test (using the aqueous sol of Example 1) is shown in Fig. 20(a). It was visually confirmed that the silica particles of the aqueous sol were uniformly dispersed and had not settled. Using the core pore clogging test apparatus (piping diagram) shown in Fig. 21, the aqueous sol prepared according to the procedure of Example 1 as described above was added to brine (medium salt concentration (175,000 ppm, pH 6.3)) so that the silica concentration became 1.0% by mass, and a sample stored at 80°C for 7 days was prepared. Using this sample and a rock core sample (sandstone, BSS-4) saturated with distilled water, a test for confirming the presence or absence of clogging of rock core pores assuming an underground oil reservoir was conducted according to the following procedure. The core flow test apparatus, as shown in Fig. 21, consists of an injection pump (manufactured by Schlumberger), a CO2 piston cylinder for fluid filling, a nanoparticle brine piston cylinder, a distilled water piston cylinder (all manufactured by VINCI Technologies), a core holder (manufactured by VINCI Technologies), an annular pressure pump (manufactured by VINDUM ENGINEERING), a backpressure valve and a backpressure pump (manufactured by VINCI Technologies), a gas-liquid separator for the recovered fluid (manufactured by VINCI Technologies) and a wet gas meter for measuring the amount of free gas (manufactured by Shinagawa Co., Ltd.), a pressure gauge (manufactured by VALCOM), a resistance thermometer for measuring the core temperature, the constant temperature bath temperature, and the free gas temperature (manufactured by Chino Co., Ltd.), and an air constant temperature bath (manufactured by Suzunaka Rika Kogyo Co., Ltd.). The upstream and downstream pressures of the core holder, the annular pressure (side pressure) of the core holder, the backpressure valve control pressure, the core and constant temperature bath temperatures, the amount and temperature of the free gas were recorded every 1 second by a computer via a data logger (manufactured by GRAPHTEC).

[0076] <Test Example 3: Confirmation Test for the Presence or Absence of Rock Core Pore Blockage of Aqueous Sols (Example 1, Example 2) Using Sandstone (BSS)> Set a single sandstone (BSS) core sample inserted into a rubber sleeve in the core holder shown in Fig. 21. Vacuum the annulus (confining pressure (lateral pressure) fluid-filled annular space) inside the pores of the sandstone (BSS) core and then between the rubber sleeve and the inner wall of the core holder. After saturating the pressurized fluid in the annulus from the confining pressure pump to atmospheric pressure suction, pressurize the confining pressure (lateral pressure) to 68.0 atmospheres with the confining pressure pump to confirm that there is no leakage inside and outside the pores of the sandstone (BSS) core. Set the backpressure valve to 200 atmospheres, which is the test condition, with the backpressure pump. Connect the injection pump 2 and the distilled water piston cylinder, introduce distilled water into the pores of the vacuumed sandstone (BSS) core, pressurize it to 34.0 atmospheres, and control the pump at a constant pressure. To set the differential pressure for the pressure setting of the plugging evaluation test (backpressure setting pressure + 68.0 atmospheres (1,000 psi)), pressurize the confining pressure (lateral pressure) to 102.0 atmospheres and record the amount of distilled water introduced. Subtract the dead volume between the upstream and downstream valves of the core holder, which was pre-measured, from the amount of distilled water introduced at a differential pressure of 68.0 atmospheres to obtain the 100% distilled water saturation volume inside the core pores, which was used as the core pore volume when calculating the injection ratio (fluid injection pore volume ratio (injected volume / pore volume): PV). While checking for leakage, increase the pressure by 34.0 atmospheres each in the order of the confining pressure (lateral pressure) and the pressure inside the core pores. Finally, set the confining pressure (lateral pressure), which is the test pressure, to 268.1 atmospheres and the pressure inside the core pores to 200.0 atmospheres. Set the injection pump 2 to constant flow control, inject distilled water at a low flow rate, and check the operation of the backpressure valve and the signal output status of the pressure gauge. Close the upstream valve of the distilled water piston cylinder and control the internal pressure of the fluid-filled piston cylinder at a constant pressure of 200 atmospheres with injection pumps 1 and 2. Gradually increase the temperature of the air thermostat from room temperature in 10°C steps and stabilize it at the test set temperature of 100°C. For the fluid expansion volume during the heating process, keep the internal pressure of the fluid-filled piston cylinder at 200 atmospheres with injection pumps 1 and 2, discharge the distilled water inside the core holder from the backpressure valve and keep it at 200 atmospheres, and keep the confining pressure (lateral pressure) at 268.1 atmospheres with the confining pressure pump. Subsequently, a brine preparation solution containing the aqueous sol of Example 1 (a silica sol in which silica particles were surface-treated with 3-glycidoxypropyltrimethoxysilane (GPS)) (silica concentration 1.0 mass%, salt concentration 175,000 ppm (medium-salt-concentration brine)) was simultaneously pressure-injected from a nanoparticle brine piston cylinder and carbon dioxide from a CO2 piston cylinder at a ratio of 1:1 each, and pressure-injected into a sandstone (BSS) core sample saturated with distilled water in a core holder at a flow rate of 4 feet per day. The pressure injection conditions of the pressure injection fluid into the core sample were 100 °C, back pressure control pressure 200 atmospheres, and confining pressure (lateral pressure) 268.1 atmospheres. While measuring the pressure injection differential pressure (fluid flow differential pressure at a flow rate of 4 feet per day), the brine preparation solution containing the aqueous sol of Example 1 (a silica sol in which silica particles were surface-treated with 3-glycidoxypropyltrimethoxysilane (GPS)) filled in the piston cylinder was pressure-injected until the total amount was finished, and the pressure injection was continued until the pump pressure of pump 2 increased to 234 atmospheres, which is the pressure upper limit set value, and the pressure injection pump 2 automatically stopped. After the pressure injection stopped, if the fluid flowed out from the back pressure valve and the differential pressure decreased to 0 atmospheres (upstream pressure of the sandstone (BSS) core sample - downstream pressure), it was judged as unblocked. If the differential pressure after the pressure injection stopped held the pressure upper limit set value of 234 atmospheres (upstream pressure of the sandstone (BSS) core sample - downstream pressure), it was judged as blocked. Also, when it was confirmed that the core was unblocked and an increase was seen in the pressure injection differential pressure when the brine preparation solution was simultaneously pressure-injected from the nanoparticle brine piston cylinder and carbon dioxide from the CO2 piston cylinder at a ratio of 1:1 each, it was suggested that the apparent viscosity of the pressure injection fluid was high, and it was judged that a CO2 foam was generated. As the pressure injection fluid (aqueous sol of Example 1, brine, carbon dioxide) was pressure-injected into the sandstone (BSS) core sample, the pressure injection differential pressure of the fluid flowing through the pores of the core sample was measured, and the obtained results are shown in FIG. 22 and Table 10. Note that the injection differential pressure is the difference in pressure between the primary side (upstream pressure) and the secondary side (downstream pressure) when the fluid is flowing. In the flow experiment, it refers to the difference in pressure measured upstream and downstream of the core sample inserted into the core holder when the fluid is flowing (injection (flow) differential pressure = upstream pressure - downstream pressure). When the injection flow rate is constant, the injection differential pressure shows a low differential pressure for a high-permeability core and a high differential pressure for a low-permeability core compared to a high-permeability core. Also, even for the same core (constant permeability), a high injection differential pressure is shown when the fluid injection flow rate is high, and a low differential pressure is shown when it is low. Furthermore, when a high-viscosity fluid is injected at the same flow rate, a high differential pressure is shown, and when a low-viscosity fluid is injected, a low differential pressure is shown.

[0077] Figure 22 shows, with the horizontal axis representing the injection ratio of the fluid (fluid injection pore volume ratio (injected volume / pore volume): PV) of a sample (a sample obtained by storing salt water (containing silica at a concentration of 1.0 mass% and salt at a concentration of 175,000 ppm (medium-salt-concentration salt water)) containing the aqueous sol of Example 1 (silica sol with silica particles surface-treated with 3-glycidoxypropyltrimethoxysilane (GPS)) and carbon dioxide at 80 °C for 7 days, with the total rock pore volume of the sandstone (BSS) core sample being 1.0), and the vertical axes representing the injection differential pressure (left vertical axis) and the amount of salt water (including the aqueous sol) recovered from the pores of the core sample (cc) (right vertical axis). In Figure 22, ● indicates the injection differential pressure, and ○ indicates the liquid recovery amount. As shown in Table 10 and Figure 22, the increase in the injection differential pressure suggests the generation of foam or emulsion inside the rock core. Since the upstream pressure decreased to the downstream pressure immediately after the pump stopped and the differential pressure became 0 atm, it was determined that there was no "blockage". A photograph of foam generation in the recovered fluid is shown in Figure 23. Also, a test for confirming the presence or absence of core blockage was conducted in the same manner using the aqueous sol of Example 2 (silica sol with silica particles surface-treated with 3-aminopropyltriethoxysilane (APTES) and phenyltrimethoxysilane (PTMS)) with sandstone (BSS). The obtained results are shown in Figure 24 and Table 11. Figure 24 shows the injection time (hour) of fluid (brine containing the aqueous sol of Example 2 (silica sol with silica particles surface-treated with 3-aminopropyltriethoxysilane (APTES) and phenyltrimethoxysilane (PTMS)), silica concentration 1.0 mass%, salt concentration 175,000 ppm (medium salt concentration brine)) stored at 80°C for 7 days, carbon dioxide) on the horizontal axis and the injection differential pressure on the vertical axis, with the total rock pore volume of the sandstone (BSS) core sample taken as 1.0. As shown in Table 11 and Figure 24, an increase in the injection differential pressure gradually applied to the sandstone core was confirmed from the start of fluid injection. And due to the end of the experimental operation 5.42 hours after the start of fluid injection, the injection stopped due to pump stoppage, and thereafter a gentle decrease in the differential pressure applied to the sandstone core was confirmed. A gentle pressure decrease is seen until the differential pressure reaches 0 atm immediately after pump stoppage, but these "mild blockages" did not pose a problem in practice.

[0078]

Table 10

Table 11

[0079] 〈Test Example 4: Test for Confirming the Presence or Absence of Blockage of Rock Core Pores of Aqueous Sol (Comparative Example 1) Using Sandstone (BSS)〉 Using the aqueous sol of Comparative Example 1, a sample with a medium salt concentration (175,000 ppm), silica concentration 1.0 mass%, and pH 7.2 was prepared in the same manner as in the [Brine Stability Test], stored at 80°C for 7 days, and then an experiment was conducted to determine whether the sample blocked the pores of the rock core. The sample used in this test (using the aqueous sol of Comparative Example 1) is shown in Figure 20(b). It was visually confirmed that the silica particles of the aqueous sol were aggregated and sedimented. Using the core pore plugging test apparatus (piping diagram) shown in Fig. 21, the aqueous sol prepared according to the procedure of Comparative Example 1 as described above was added to brine (medium brine concentration (175,000 ppm, pH 7.2)) so that the silica concentration was 1.0% by mass, and a sample stored at 80°C for 7 days was prepared. Using this sample and a rock core sample (sandstone, BSS-5) saturated with distilled water, a test for confirming the presence or absence of plugging of rock pores assuming an underground oil reservoir was carried out according to the same procedure as in Test Example 3.

[0080] Fig. 25 shows, with the horizontal axis representing the injection ratio of the fluid (a sample obtained by storing brine (containing the aqueous sol of Comparative Example 1, silica concentration 1.0% by mass, salt concentration 175,000 ppm (medium brine concentration brine)) at 80°C for 7 days, carbon dioxide) (fluid injection pore volume ratio (injection volume / pore volume): PV), and the vertical axes representing the injection differential pressure (left vertical axis) and the amount of brine swept (recovered) from the pores of the core sample (since no increase in the injection differential pressure was measured and it changed at a differential pressure of about 2 to 3 atm, it is presumed that the silica particles of the aqueous sol aggregated and settled in the nanoparticle brine piston cylinder and only brine was injected) (cc) (right vertical axis). In Fig. 25, ● represents the injection differential pressure and ○ represents the liquid recovery amount.

[0081]

Table 12

[0082] As shown in Table 12 and Fig. 25, no increase in the injection differential pressure, which would indicate the formation of foam or emulsion inside the rock core, was measured. The reason for this is that separation and precipitation of the silica component of the aqueous sol occurred inside the filling piston cylinder in the brine containing the aqueous sol (Comparative Example 1), and the silica component in the brine containing the aqueous sol of Comparative Example 1 gelatinized. Therefore, it is judged that the silica component in the brine containing the aqueous sol of Comparative Example 1 was not injected into the rock core sample. Note that the term "gelatinization" refers to the gelation of silica. Subsequently, when the press-fitting was further continued, a rapid pressure increase as shown in Table 13 (Figure 26) was measured. Figure 26 is a diagram showing the fluid injection pressure (vertical axis) with respect to the injection time (horizontal axis). The results shown in Table 13 and Figure 26 indicate that when a rapid pressure increase (after 4.06 hours) was confirmed, although the silica component of the gelatinized aqueous sol (Comparative Example 1) started to be injected into the voids of the rock core sample as the injection fluid, it was immediately judged that "blockage" of the voids occurred.

[0083]

Table 13

[0084] Figure 27 shows a photograph of the silica component in the gelatinized aqueous sol (Comparative Example 1) in the cylinder for the injection fluid, visually observed at room temperature when the blockage test device was disassembled after the test using the aqueous sol of Comparative Example 1 was completed. As shown in Figure 27, it was confirmed that the silica component in the aqueous sol (Comparative Example 1) was gelatinized, and it was judged that injection into the rock core was impossible. When gelatinization occurs in this way, it is highly likely that injection into the rock itself becomes impossible, and the permeability of the rock mass may be completely inhibited. However, as shown in the differential pressure behavior of the APTES-based aqueous sol in Example 2 (Figure 24, Table 11), if it is a mild blockage that does not lead to loss of permeability, there is room to expect the possibility of improving the replacement efficiency by changing the flow path of the replacement fluid (CO2 or CO2 foam) in the rock.

Claims

1. CO for Enhanced Oil Recovery (EOR) ２ An aqueous sol for enhancing the stability of foam or emulsion in a mixture containing carbon dioxide, water and oil in a foam (Foam) process, An aqueous sol in which silica particles having an average particle diameter of 1 to 100 nm in measurement by dynamic light scattering method and having at least a part of the surface coated with a silane compound having a hydrolyzable group are used as a dispersion medium and dispersed in an aqueous solvent having a pH of 1.0 or more and 6.0 or less. The silane compound having a hydrolyzable group is a first silane compound having a hydrolyzable group and containing an epoxy group, an organic group obtained by hydrolyzing the epoxy group, or an amino group; and a second silane compound having a hydrolyzable group and containing an organic group containing an alkyl group having 1 to 40 carbon atoms, an aromatic ring group having 6 to 40 carbon atoms, or a combination thereof. The aqueous sol.

2. The aqueous sol according to Claim 1, wherein the epoxy group is a glycidyl group, a cyclohexyl epoxy group, or a combination thereof.

3. The aqueous sol according to Claim 1 or 2, wherein in the silica particles having at least a part of the surface coated, the silane compound and the silica particles are contained in a mass ratio of 0.01 to 2.00:1.

00.

4. CO in Enhanced Oil Recovery (EOR) ２ Carbon dioxide, water and oil in the foam process An aqueous sol for enhancing the stability of foam or emulsion in a mixture containing, in which silica particles having an average particle diameter of 1 to 15 nm in measurement by dynamic light scattering method and having at least a part of the surface coated with a silane compound having a hydrolyzable group are used as a dispersion medium and dispersed in an aqueous solvent having a pH of 1.0 or more and 6.0 or less. In the silica particles having at least a part of the surface coated, the ratio of the silane compound and the silica particles is contained in a mass ratio of 0.01:1.00 to 2.00:1.

00. The aqueous sol.

5. The aqueous sol according to Claim 4, wherein the silane compound having a hydrolyzable group is a silane compound having a hydrolyzable group and containing an epoxy group, an organic group obtained by hydrolyzing the epoxy group, or an amino group.

6. The aqueous sol according to Claim 5, wherein the epoxy group is a glycidyl group, a cyclohexyl epoxy group, or a combination thereof.

7. The aqueous sol according to any one of Claims 4 to 6, wherein the silane compound having a hydrolyzable group further contains a second silane compound having a hydrolyzable group.

8. The aqueous sol according to claim 7, wherein the second silane compound having a hydrolyzable group is a silane compound containing an organic group including an alkyl group having 1 to 40 carbon atoms, an aromatic ring group having 6 to 40 carbon atoms, or a combination thereof.

9. The aqueous sol according to any one of claims 1 to 8, which does not have an isoelectric point at pH 6 or lower.

10. After the test of storing the aqueous sol at 80 ° C for 30 days at a concentration of 1.0% by mass of silica in an environment containing sodium chloride, calcium chloride, and magnesium chloride as main components and having a total salt concentration of 10,000 to 230,000 ppm, the difference between the value of the average particle diameter measured by the dynamic light scattering method of the aqueous sol and the value of the average particle diameter before the test is 200 nm or less. The aqueous sol according to any one of claims 1 to 9.

11. The aqueous sol has a pH of 1.0 or more and 6.0 or less when coating silica particles in an aqueous medium with a silane compound having a hydrolyzable group, the aqueous sol stored at pH 1.0 or more and 6.0 or less, after the test of storing the aqueous sol at 80 ° C for 30 days at a concentration of 1.0% by mass of silica in an environment containing sodium chloride, calcium chloride, and magnesium chloride as main components and having a total salt concentration of 10,000 to 230,000 ppm and at a pH of 5.0 to 8.0 in the environment, the difference between the value of the average particle diameter measured by the dynamic light scattering method of the aqueous sol and the value of the average particle diameter before the test is 200 nm or less. The aqueous sol according to any one of claims 1 to 10.

12. The aqueous sol according to any one of claims 1 to 11, wherein the foam or emulsion is stable at a temperature of 30 to 120 ° C and a pressure of 70 to 400 atmospheres.

13. A method for recovering crude oil from a subterranean hydrocarbon-containing layer, comprising: step (a): injecting the aqueous sol according to any one of claims 1 to 12, water, and carbon dioxide into the subterranean layer, either separately or simultaneously; step (b): recovering crude oil from a production well drilled in the subterranean layer to the surface. A crude oil recovery method comprising the above steps.

14. The crude oil recovery method according to claim 13, wherein step (a) is a step of alternately injecting the aqueous sol and water and carbon dioxide into the subterranean layer.

15. The crude oil recovery method according to claim 13 or 14, wherein the injection in step (a) is performed at a temperature of 30 to 120 ° C and a pressure of 70 to 400 atmospheres.

16. The crude oil recovery method according to any one of claims 13 to 15, wherein the underground layer is a layer containing sandstone.

17. The crude oil recovery method according to any one of claims 13 to 15, wherein the underground layer is a layer containing carbonate rock.

18. A method for producing an aqueous sol containing, as a dispersoid, silica particles at least partially coated on the surface with a silane compound having a hydrolyzable group, according to any one of claims 1 to 17, comprising a step of mixing an aqueous sol of unmodified colloidal silica and a silane compound having a hydrolyzable group at a ratio such that the mass ratio of the silane compound to the silica particles in the aqueous sol is 0.01 to 2:1.00, and treating this at pH 1 to 6 for 0.1 hour to 20 hours.

19. The production method according to claim 18, wherein the step of mixing and treating the aqueous sol of unmodified colloidal silica and the silane compound having a hydrolyzable group is carried out at 50 to 100°C.

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