High-temperature and high-salt oil reservoir oil displacement system as well as preparation method and application thereof

Abstract

The invention relates to a high-temperature and high-salt oil reservoir oil displacement system as well as a preparation method and application thereof. The high-temperature and high-salt oil reservoir oil displacement system comprises the following raw materials in percentage by weight: 0.05-0.5% of a betaine surfactant, 0.01-0.3% of a polymer, 0.001-0.01% of nanoparticles and the balance of water, the betaine surfactant comprises an alkyl amide hydroxy sulfobetaine surfactant and / or an alkyl aryl hydroxy sulfobetaine surfactant. Through mutual cooperation of the specific betaine surfactant, the polymer and the nanoparticles, a synergistic effect is exerted, an oil displacement system which has ultralow interfacial tension and excellent emulsifying performance under high-temperature and high-salt conditions and can effectively improve the recovery efficiency of a high-temperature and high-salt oil reservoir is obtained, and the oil displacement system can be well applied to tertiary oil recovery.

Description

Technical Field

[0001] The present invention relates to the technical field of oil extraction, and in particular to a high-temperature and high-salinity oil reservoir oil displacement system and a preparation method and application thereof. Background Art

[0002] High-temperature and high-mineralization oil reservoirs are widely distributed in countries around the world and are an important part of oil production. In order to meet the oil production of high-temperature and high-salinity oil reservoirs, laboratories and oil fields have systematically studied measures to improve oil recovery. In order to improve crude oil recovery, chemical flooding methods such as polymer flooding, alkaline water flooding, surfactant flooding and composite flooding are commonly used. Experiments have shown that chemical flooding to improve oil recovery technology is the largest technology to improve oil recovery. However, due to the characteristics of high-temperature and high-salinity oil reservoirs, effectively improving oil recovery has always been a technical difficulty that R&D workers in various countries have been unable to overcome.

[0003] In high-temperature and high-salinity reservoirs, polymer molecular chains are prone to breakage due to very high temperature and salinity. Polymer degradation leads to a significant decrease in the viscosity of the system, which in turn affects the efficiency and reduces the oil recovery efficiency. Therefore, conventional polymer technology cannot effectively improve the recovery rate. Surfactants can reduce the oil-water interfacial tension and activate the remaining oil in the pores, so that the remaining oil is taken out of the oil recovery system by the oil displacement fluid, thereby improving the oil recovery efficiency. At present, anionic surfactants and nonionic surfactants are the two most commonly used surfactants in tertiary oil recovery. However, due to their poor salt tolerance, anionic surfactants are likely to precipitate in high-salinity brine, while nonionic surfactants cannot be used under high temperature conditions due to their poor stability and high adsorption capacity; at the same time, the mixture of anionic and nonionic surfactants will cause serious adsorption and separation problems during the oil recovery process. Research on temperature-resistant and salt-resistant surfactants for oil recovery at home and abroad mainly focuses on anionic-nonionic surfactants and gemini surfactants. However, the synthesis process of anionic-nonionic surfactants and gemini surfactants is relatively complex and the cost is relatively high.

[0004] The oil displacement system screening method is an important guarantee for optimizing the design of oil displacement systems. At present, the methods for screening oil displacement systems mainly include: core flooding experimental method and visual model seepage method. The core flooding experimental method can comprehensively evaluate the influence of almost all factors, including the emulsification seepage capacity of the oil displacement system, on improving the recovery rate, but the experimental cost is high, the cycle is long, and the operation is complicated, making it difficult to carry out large-scale sample screening. The visual model seepage method for screening oil displacement systems can observe the morphology of emulsion seepage in the model and the distribution of oil and water, etc., but the structure and size of pore throats are still somewhat different from the real formation porous media; in addition, due to the limitations of processing technology and processing materials, the size of the visual model is often small, and affected by the scale effect, the oil displacement effect of different systems is low, and the screening effect of the oil displacement system is not good. Therefore, both of these oil displacement system screening methods have problems such as complex operation, long experimental cycle, high cost, and low differentiation of oil displacement effects of different systems. Moreover, it is impossible to infer the mechanism of action of the displacement agent from the level of chemical agent composition properties, and it is difficult to guide the optimization design of the oil displacement system. The oil displacement process is essentially an interfacial process. Therefore, starting from the interface adsorption layer of the oil displacement system, developing a method for screening the oil displacement system based on specific interface parameters can solve the problem that the influencing factors of the current indoor evaluation experiments are too complex, making it difficult to effectively screen the oil displacement system.

[0005] Therefore, the challenges brought by high temperature and high mineralization to the temperature and salt resistance of surfactants have led to a serious lack of oil recovery systems and related technologies that can be used to improve the recovery rate of high-temperature and high-salinity reservoirs. The development of low-cost and high-efficiency oil recovery agent systems for high-temperature and high-salinity reservoirs is a key technology for chemical flooding, and it is of great practical significance for targeted research on oil recovery systems for high-temperature and high-salinity reservoirs. Summary of the invention

[0006] In order to solve the above technical problems, the present invention provides a high-temperature and high-salinity oil reservoir flooding system and its preparation method and application. The present invention uses a specific betaine surfactant, a polymer and nanoparticles to cooperate with each other to exert a synergistic effect, thereby obtaining an oil flooding system with ultra-low interfacial tension and excellent emulsification performance under high-temperature and high-salinity conditions, which can effectively improve the recovery rate of high-temperature and high-salinity oil reservoirs, and can be well applied to tertiary oil recovery.

[0007] To achieve this object, the present invention adopts the following technical solutions:

[0008] In a first aspect, the present invention provides a high-temperature and high-salinity oil reservoir flooding system, wherein the high-temperature and high-salinity oil reservoir flooding system comprises the following raw materials in weight percentage:

[0009] Betaine surfactant 0.05-0.5%

[0010] Polymer 0.01-0.3%

[0011] Nanoparticles 0.001-0.01%;

[0012] The rest is water;

[0013] The betaine surfactant includes an alkylamide hydroxysulfobetaine surfactant and / or an alkylaryl hydroxysulfobetaine surfactant.

[0014] The use amount of specific surfactants, polymers and nanoparticles in the high-temperature and high-salinity oil reservoir deoiling system of the present invention is low, that is, it has a low use concentration, thereby reducing economic costs; at the same time, the present invention combines specific betaine surfactants with polymers and nanoparticles to make them work together synergistically, thereby obtaining an oil displacement system with ultra-low interfacial tension and excellent emulsification performance under high-temperature and high-salinity conditions, which can effectively improve the recovery rate of high-temperature and high-salinity oil reservoirs. Therefore, the high-temperature and high-salinity oil reservoir system provided by the present invention has the dual advantages of high economic benefits and high oil displacement efficiency.

[0015] The oil recovery process is essentially an interfacial process. Starting from the interfacial adsorption layer of the oil recovery system, through the specific selection of surfactants, polymers and nanoparticles, an oil recovery system with ultra-low interfacial tension is obtained, thereby achieving the goal of good and economical oil recovery for high-temperature and high-salinity reservoirs.

[0016] The surfactant content in the high-temperature and high-salinity reservoir flooding system of the present invention is 0.05-0.5%, for example, it can be 0.08%, 0.1%, 0.15%, 0.2%, 0.25%, 0.3%, 0.35%, 0.4%, 0.45% or 0.48%, and is more preferably 0.05-0.3%.

[0017] The polymer content is 0.01-0.3%, for example, it can be 0.03%, 0.05%, 0.08%, 0.1%, 0.12%, 0.15%, 0.18%, 0.2%, 0.23%, 0.25% or 0.28%, and more preferably 0.05-0.2%.

[0018] The content of nanoparticles is 0.001-0.01%, for example, 0.0015%, 0.002%, 0.003%, 0.004%, 0.005%, 0.006%, 0.007%, 0.008%, 0.009% or 0.0095%, and more preferably 0.005-0.01%.

[0019] Preferably, the carbon number of the alkyl group in the alkylamide hydroxysulfobetaine surfactant is 16-28, for example, 17, 18, 19, 20, 21, 22, 23, 24, 25, 26 or 27.

[0020] Preferably, the carbon number of the alkyl group in the alkylaryl hydroxysulfobetaine surfactant is 16-26, for example, 17, 18, 19, 20, 21, 22, 23, 24 or 25.

[0021] Preferably, the betaine surfactant is a combination of an alkylamide hydroxysulfobetaine surfactant and an alkylaryl hydroxysulfobetaine surfactant, and more preferably a combination of erucamidopropyl hydroxysulfobetaine and eicosyl aryl hydroxysulfobetaine.

[0022] Preferably, the mass ratio of the alkylamide hydroxysulfobetaine surfactant to the alkylaryl hydroxysulfobetaine surfactant is (8:2)-(3:7), for example, it can be 8:2, 7:3, 6:4, 5:5, 4:6 or 3:7, and more preferably (7:3)-(5:5).

[0023] In the present invention, the mass ratio of the specific alkylamide hydroxysulfobetaine surfactant to the alkylaryl hydroxysulfobetaine surfactant is selected to further obtain a surfactant system with a moderate maximum compression modulus and low interfacial tension.

[0024] Preferably, the maximum compression modulus of the betaine surfactant is 35-50 mN / m, for example, it may be 36 mN / m, 38 mN / m, 40 mN / m, 41 mN / m, 42 mN / m, 43 mN / m, 44 mN / m, 45 mN / m, 46 mN / m or 48 mN / m, etc.

[0025] Preferably, the maximum compression modulus is obtained by screening based on LB monolayer test technology.

[0026] In the present invention, based on the LB monolayer test technology, specific alkylamide hydroxysulfobetaine surfactants and alkylaryl hydroxysulfobetaine surfactants are screened out through the maximum compression modulus parameter, which can form a surfactant system with a maximum elastic modulus of 35-50mN / m. The maximum compression modulus value within this range has good interfacial film strength and viscoelasticity, is beneficial to the deformation of emulsion droplets, and is closely related to the interaction with rock pore throats.

[0027] Preferably, the polymer includes any one of hard glucan, star-shaped heat-resistant and salt-resistant polymer or heat-resistant and salt-resistant polyacrylamide containing a ring structure, or a combination of at least two of them, and is further preferably a star-shaped heat-resistant and salt-resistant polymer and / or a heat-resistant and salt-resistant polyacrylamide containing a ring structure, and is further preferably a heat-resistant and salt-resistant polyacrylamide containing a ring structure.

[0028] In the present invention, the specific polymer selection enables the system to obtain a maximum elastic modulus of 40-50 mN / m, but when the content of scleroglucan is not higher than 0.05%, the system fails to achieve an ultra-low interfacial tension (10 -3 The star-shaped heat-resistant and salt-resistant polymer also failed to achieve ultra-low interfacial tension (10 -3 Therefore, the most preferred polymer of the present invention is 0.01-0.3% of heat-resistant and salt-resistant polyacrylamide containing a cyclic structure.

[0029] Preferably, the viscosity average molecular weight of the polymer is 3 million to 60 million, for example, 3.5 million, 4 million, 4.5 million, 5 million, 5.5 million, 6 million, 10 million, 20 million, 30 million, 40 million or 50 million, and more preferably 3 million to 40 million.

[0030] Preferably, the nanoparticles include any one of 3-aminopropyltriethoxysilane modified silica, γ-methacryloxypropyltrimethoxysilane modified silica, unmodified silica, ferric oxide, aluminum oxide or 50% methylated modified silica, or a combination of at least two thereof.

[0031] In the present invention, the selection of specific nanoparticles can further reduce the interfacial tension of the system, thereby obtaining an oil displacement system with ultra-low interfacial tension, which is beneficial to improving the oil displacement effect.

[0032] Preferably, the particle size of the nanoparticles is 10-80 nm, for example, 15 nm, 16 nm, 17 nm, 18 nm, 19 nm, 20 nm, 30 nm, 40 nm, 50 nm, 60 nm or 70 nm, etc., more preferably 15-20 nm.

[0033] Preferably, the water is any one of oilfield injection wastewater, formation water or clean water, or a combination of at least two of them.

[0034] Preferably, the mineralization of the water is not higher than 200,000 mg / L, for example, it may be 4,000 mg / L, 6,000 mg / L, 10,000 mg / L, 50,000 mg / L, 70,000 mg / L, 100,000 mg / L, 130,000 mg / L, 150,000 mg / L, 180,000 mg / L or 200,000 mg / L, etc., more preferably 70,000-200,000 mg / L.

[0035] Preferably, the high-temperature and high-salt oil reservoir refers to an oil reservoir with a temperature of 50-120°C (for example, 55°C, 60°C, 70°C, 80°C, 90°C, 95°C, 100°C, 105°C, 110°C or 115°C, etc.) and a water mineralization of no more than 20,000 mg / L.

[0036] The oil displacement system provided in the present invention can achieve low interfacial tension at a temperature of 50-120°C and a salinity of 70,000-200,000 mg / L, so that the specific oil displacement system of the present invention can be well applied to tertiary oil recovery in high-temperature and high-salinity reservoirs. Furthermore, ultra-low interfacial tension (10 -3 order of magnitude) range.

[0037] In a second aspect, the present invention provides a method for preparing the high-temperature and high-salinity reservoir flooding system as described in the first aspect, the preparation method comprising the following steps:

[0038] (1) mixing a polymer, nanoparticles and water to obtain a polymer-nanoparticle mother solution, aging and diluting;

[0039] (2) Adding a betaine surfactant to the diluted solution of the polymer-nanoparticle mother solution in step (1), mixing, and obtaining the high-temperature and high-salinity reservoir flooding system.

[0040] Preferably, the aging time in step (1) is 20-30 hours, for example, 21 hours, 22 hours, 23 hours, 24 hours, 25 hours, 26 hours, 27 hours, 28 hours or 29 hours, etc.;

[0041] In the present invention, dilution refers to diluting the polymer-nanoparticle mother solution with water so that the content of each raw material component after adding the betaine surfactant meets the specific requirements of the oil displacement system of the present invention.

[0042] In a third aspect, the present invention provides an application of the high-temperature and high-salinity reservoir oil recovery system as described in the first aspect in tertiary oil recovery.

[0043] Compared with the prior art, the present invention has at least the following beneficial effects:

[0044] (1) The present invention combines a specific betaine surfactant with a polymer and nanoparticles to achieve a synergistic effect, thereby obtaining an oil recovery system with low interfacial tension and excellent emulsification properties under high temperature and high salinity conditions, which can effectively improve the recovery rate of high temperature and high salinity reservoirs, and can be well applied to tertiary oil recovery.

[0045] (2) The high-temperature and high-salinity oil reservoir flooding system provided by the present invention has high oil recovery efficiency, and the increased recovery factor after water flooding can reach 32.25%, and the usage of specific surfactants, polymers and nanoparticles is low, so it has the dual advantages of lower economic cost and higher oil recovery efficiency. DETAILED DESCRIPTION

[0046] For the convenience of understanding the present invention, the present invention lists the following embodiments. It should be understood by those skilled in the art that the embodiments are only to help understand the present invention and should not be regarded as specific limitations of the present invention.

[0047] The information of some raw materials used in the following examples and comparative examples is shown in Table 1:

[0048] Table 1

[0049]

[0050]

[0051] The raw materials prepared by reference to patents or literature in the above table are all commercially available and no special requirements are made for the corresponding raw materials used in the preparation process.

[0052] The screening of the high-temperature and high-salinity oil reservoir flooding system of the present invention is as follows:

[0053] Screening 1: Choice of Surfactant

[0054] The maximum compression modulus of LB monolayers prepared with different surfactant types was tested.

[0055] Experimental method: Prepare a series of oil-displacing agent (surfactant) / organic solvent (chloroform) solutions with different concentrations, with a solution concentration of 0.01%. Add 220 mL of pure water to the Langmuir trough, install the slide barrier and initialize it, install and calibrate the probe, draw 25 mL of oil-displacing agent / organic solvent solution with a microsyringe, carefully spread it on the water surface, and wait for 30 minutes for the chloroform to completely evaporate. Put on the container protective cover, control the slide barrier by computer to compress the monolayer at a speed of 25 mm / min, and record the average molecular area at the same time. Calculate the surface tension based on the Du Noüy-Padday technique, and obtain the π-A isotherm according to the change of surface tension with the average molecular area. From the π-A isotherm, the maximum compression modulus of the monolayer of different surfactants is obtained, and the test results are shown in Table 2.

[0056] Table 2

[0057]

[0058] As can be seen from Table 2, the maximum compression modulus results of surfactants such as amine oxide, hydroxysulfobetaine, and amidopropylhydroxysulfobetaine are very different. The maximum compression modulus of tetradecylamidopropyl sulfobetaine is 70.58 mN / m at most, the maximum compression modulus of erucamidopropylamine oxide is 15.24 mN / m at most, and the maximum compression modulus of erucamidopropylhydroxysulfobetaine and eicosylarylhydroxysulfobetaine and their mixed systems are between 35-50 mN / m. Therefore, the surfactant of the present invention is preferably a combination of erucamidopropylhydroxysulfobetaine and eicosylarylhydroxysulfobetaine.

[0059] Screening 2: Selection of specific surfactant composition

[0060] The maximum compression modulus and interfacial tension of surfactants composed of erucamide propyl hydroxysulfobetaine and eicosyl aryl hydroxysulfobetaine in different mass ratios were tested.

[0061] Test method:

[0062] The maximum compression modulus test method (LB film test) is the same as screening 1;

[0063] Interfacial tension test: The interfacial tension was tested using a TX500C interfacial tension tester with a spinning drop method. The surfactant concentration was 0.2%, the test temperature was 90°C, and the rotation speed was 5000 RPM. The test results are shown in Table 3.

[0064] Table 3

[0065]

[0066] It can be seen from Table 2 that the maximum compression modulus of the surfactant composed of erucamidopropyl hydroxysulfobetaine and eicosyl aryl hydroxysulfobetaine at different mass ratios is between 35-50 mN / m. Among them, when the mass ratio of erucamidopropyl hydroxysulfobetaine and eicosyl aryl hydroxysulfobetaine is (8:2)-(3:7), the maximum compression modulus is moderate and the interfacial tension reaches the lowest; further, when the mass ratio of the two is 6:4, the ultra-low interfacial tension reaches the lowest, and the maximum compression modulus value is moderate.

[0067] Screening 3: Polymer Selection

[0068] The maximum compression modulus and interfacial tension of the polymer for surfactants (erucamidopropylhydroxysulfobetaine and eicosylarylhydroxysulfobetaine in a mass ratio of 6:4) were tested.

[0069] Test method:

[0070] The maximum compression modulus test method (LB film test) is the same as screening 1;

[0071] Interfacial tension test: Formation water with a mineralization of 140,000 mg / L, a surfactant and an optional polymer were mixed. The mass concentration of the surfactant in the prepared system was 0.2%. The interfacial tension of the above solution was tested using a TX500C interfacial tension tester using a spinning drop method. The test temperature was 100°C and the rotation speed was 5000 RPM. The physical and chemical indicators of the polymer are shown in Table 4. The test results are shown in Table 5.

[0072] Table 4

[0073] Polymer Name Molecular weight (ten thousand) Polymer 1 Heat-resistant and salt-resistant polyacrylamide containing a ring structure 500 Polymer 2 Star-shaped heat-resistant and salt-resistant polymer 1247 Polymer 3 Scleroglucan 1000

[0074] Table 5

[0075]

[0076]

[0077] It can be seen from Table 5 that when the concentration of polymer 1 is 0.01-0.1%, the maximum elastic modulus of the system is 40-50 mN / m, and the ultra-low interfacial tension (10 -3 When the concentration of polymer 2 is 0.01-0.1%, the maximum elastic modulus of the system is also 40-50 mN / m, but the system fails to achieve ultra-low interfacial tension (10 -3 When the concentration of polymer 3 is 0.01-0.1%, the maximum elastic modulus of the system is greater than 50mN / m, and the system also fails to achieve ultra-low interfacial tension (10 -3 Therefore, when the polymer is a heat-resistant and salt-resistant polyacrylamide containing a ring structure and its concentration is 0.1%, the system has the best interfacial tension and the appropriate maximum elastic modulus.

[0078] Screening 4: Nanoparticle Selection

[0079] The interfacial tension of the nanoparticles to a system consisting of a surfactant (erucic acid amide propyl hydroxysulfobetaine and eicosyl aryl hydroxysulfobetaine in a mass ratio of 6:4) and a polymer (temperature-resistant and salt-resistant polyacrylamide containing a ring structure) was tested.

[0080] Test method: Formation water with a mineralization of 150,000 mg / L, a surfactant, a polymer and nanoparticles were mixed. The mass concentration of the surfactant in the prepared system was 0.2%, and the mass concentration of the polymer was 0.1%. The interfacial tension of the above solution was tested by the rotating drop method using a TX500C interfacial tension tester. The test temperature was 90°C and the rotation speed was 5000 RPM. The test results are shown in Table 6.

[0081] Table 6

[0082]

[0083]

[0084] It can be seen from Table 6 that at the same nanoparticle concentration, the interfacial tension of the aluminum oxide system is the highest, but it does not reach the ultra-low (10 -3 The interfacial tension of the system of 50% methylated modified silica, γ-methacryloxypropyl trimethoxysilane modified silica, unmodified silica, and ferric oxide reaches 10 -2 The interfacial tension of the system containing 3-aminopropyltriethoxysilane modified silica is 10 -3 The order of magnitude, that is, the purpose of ultra-low interfacial tension is achieved, and the concentration is only 0.001-0.01%. When the mass concentration of 3-aminopropyltriethoxysilane modified silica is 0.005% and 0.01%, the ultra-low interfacial tension of the system is the lowest. Therefore, when the nanoparticles are 3-aminopropyltriethoxysilane modified silica and its concentration is 0.005%, the system has the best interfacial tension.

[0085] Screening 5: Effects of temperature and salinity on interfacial tension of oil displacement system

[0086] The effects of temperature and mineralization on the interfacial tension of nanoparticles to a system consisting of surfactants (erucylamidopropylhydroxysulfobetaine and eicosylarylhydroxysulfobetaine in a mass ratio of 6:4), polymers (temperature-resistant and salt-resistant polyacrylamide containing a ring structure) and nanoparticles (3-aminopropyltriethoxysilane-modified silica) were tested.

[0087] Interfacial tension test: Formation water with a salinity of 70000-200000 mg / L was used to prepare a solution with a surfactant concentration of 0.2%, a polymer concentration of 0.1%, and a nanoparticle concentration of 0.005%. The interfacial tension of the solution was tested using a TX500C interfacial tension tester using a spinning drop method. The test temperature was 50-120°C and the rotation speed was 5000RPM. When the salinity was 100000 mg / L, the test results at different temperatures are shown in Table 6; when the test temperature was 100°C, the results of the influence of salinity are shown in Table 7.

[0088] Table 7

[0089]

[0090]

[0091] Table 8

[0092] Mineralization (mg / L) Interfacial tension (mN / m) 70000 <![CDATA[6.35×10 -3 ]]> 90000 <![CDATA[5.66×10 -3 ]]> 100000 <![CDATA[4.34×10 -3 ]]> 120000 <![CDATA[6.48×10 -3 ]]> 150000 <![CDATA[6.79×10 -3 ]]> 170000 <![CDATA[7.22×10 -3 ]]> 200000 <![CDATA[8.27×10 -3 ]]>

[0093] It can be seen from Table 7 and Table 8 that in the range of 50-120℃ and the salinity of 70000-200000mg / L, the interfacial tension of the oil displacement system reaches the ultra-low interfacial tension (10 -3 order of magnitude) range.

[0094] Screening 6: Effect of mineralization on the emulsification performance of oil displacement system

[0095] The oil displacement system consists of a surfactant (erucamidopropyl hydroxysulfobetaine and eicosyl aryl hydroxysulfobetaine in a mass ratio of 6:4), a polymer (heat-resistant and salt-resistant polyacrylamide containing a ring structure) and nanoparticles (3-aminopropyl triethoxysilane-modified silica). The emulsification performance of the oil displacement system was tested.

[0096] Test method: The above oil displacement system was prepared using formation water with different mineralizations, wherein the mass concentration of the surfactant was 0.2%, the mass concentration of the polymer was 0.1%, and the mass concentration of the nanoparticles was 0.005%. The solution prepared from the crude oil was mixed according to an oil-water ratio of 1:1 and poured into a sealed bottle; the HZ-8812S water bath reciprocating constant temperature oscillator was used to oscillate at a speed of 90RPM for 6 hours, and the system was observed after standing for 72 hours. The test temperature was 90°C, and the test results are shown in Table 9.

[0097] Table 9

[0098] Mineralization (mg / L) Middle phase microemulsion volume / % 70000 13 90000 16 100000 20 150000 25 170000 23 200000 19

[0099] It can be seen from Table 9 that for oil displacement systems with different salinities, the oil-water system forms a certain amount of middle phase microemulsion, which is Winsor III type, and has the unique property of being able to solubilize both oil and water, and the interfacial tension between the oil phase and the water phase is extremely low. The higher the proportion of the middle phase microemulsion, the stronger the emulsification ability. The volume of the middle phase microemulsion increases first and then decreases with the increase of salinity. When the salinity is 150000 mg / L, the volume of the middle phase microemulsion is the largest, indicating that this system has the best emulsification effect.

[0100] Example 1

[0101] This embodiment provides a high-temperature and high-salinity oil reservoir flooding system, and the high-temperature and high-salinity oil reservoir flooding system includes the following raw materials in weight percentage:

[0102] Betaine surfactant 0.2%

[0103] Polymer 0.1%

[0104] Nanoparticles 0.005%;

[0105] Its and is water;

[0106] The betaine surfactant is obtained by mixing erucic acid amide propyl hydroxysulfobetaine and eicosyl aryl hydroxysulfobetaine in a mass ratio of 6:4, the polymer is a heat-resistant and salt-resistant polyacrylamide containing a ring structure, and the nanoparticles are 3-aminopropyl triethoxysilane modified silicon dioxide (particle size 20nm).

[0107] The preparation method of the high-temperature and high-salinity oil reservoir flooding system comprises the following steps:

[0108] Weigh polymer powder and nanoparticles, prepare polymer-nanoparticle mother liquor with formation water, and dilute it for use after aging for 24 hours; add betaine surfactant to the dilution of polymer-nanoparticle mother liquor, mix them, and prepare the high-temperature and high-salinity oil reservoir flooding system.

[0109] Example 2

[0110] This embodiment provides a high-temperature and high-salinity oil reservoir flooding system, and the high-temperature and high-salinity oil reservoir flooding system includes the following raw materials in weight percentage:

[0111] Betaine surfactant 0.05%

[0112] Polymer 0.01%

[0113] Nanoparticles 0.001%;

[0114] Its and is water;

[0115] The betaine surfactant is tetradecylamidopropylhydroxysulfobetaine, the polymer is a star-shaped temperature-resistant and salt-resistant polymer, and the nanoparticles are 50% methylated modified silicon dioxide (particle size 60nm).

[0116] The preparation method of the high-temperature and high-salinity oil reservoir flooding system comprises the following steps:

[0117] Weigh polymer powder and nanoparticles, prepare polymer-nanoparticle mother liquor with oilfield injection wastewater, and dilute it for use after aging for 24 hours; add betaine surfactant to the dilution of polymer-nanoparticle mother liquor, mix them, and prepare the high-temperature and high-salinity oil reservoir flooding system.

[0118] Example 3

[0119] This embodiment provides a high-temperature and high-salinity oil reservoir flooding system, and the high-temperature and high-salinity oil reservoir flooding system includes the following raw materials in weight percentage:

[0120] Betaine surfactant 0.5%

[0121] Polymer 0.3%

[0122] Nanoparticles 0.01%;

[0123] Its and is water;

[0124] The betaine surfactant is tetradecyl aryl hydroxysulfobetaine, the polymer is scleroglucan with a molecular weight of , and the nanoparticles are unmodified silicon dioxide (particle size 15 nm).

[0125] The preparation method of the high-temperature and high-salinity oil reservoir flooding system comprises the following steps:

[0126] Weigh polymer powder and nanoparticles, prepare polymer-nanoparticle mother liquor with clean water, and dilute it for use after aging for 24 hours; add betaine surfactant to the dilution of polymer-nanoparticle mother liquor, mix them, and prepare the high-temperature and high-salinity oil reservoir flooding system.

[0127] Examples 4-8 and Comparative Examples 1-5

[0128] Compared with Example 1, except that only the types of surfactants (Examples 4-5 and Comparative Examples 1-5) and the combination ratio (Examples 6-8) were adjusted, the rest were the same as Example 1.

[0129] The settings of the surfactants in Example 1, Examples 4-8 and Comparative Examples 1-5 are shown in Table 10.

[0130] Table 10

[0131]

[0132]

[0133] Example 9

[0134] This embodiment provides a high-temperature and high-salt oil reservoir displacement system, which differs from Example 1 in that the temperature-resistant and salt-resistant polyacrylamide containing a ring structure is replaced with hard glucan, and other raw materials, contents and methods are the same as those in Example 1.

[0135] Example 10

[0136] This embodiment provides a high-temperature and high-salt oil reservoir displacement system, which differs from Example 1 in that the temperature-resistant and salt-resistant polyacrylamide containing a ring structure is replaced with ordinary polyacrylamide, and other raw materials, contents and methods are the same as those in Example 1.

[0137] Embodiment 11

[0138] This embodiment provides a high-temperature and high-salinity reservoir flooding system, which differs from Example 1 only in that 3-aminopropyltriethoxysilane-modified silica is replaced with γ-methacryloxypropyltrimethoxysilane-modified silica, and other raw materials, contents and methods are the same as those in Example 1.

[0139] Comparative Example 6

[0140] This comparative example provides an oil displacement system, which differs from Example 1 only in that no nanoparticles are added, and other raw materials, contents and methods are the same as those in Example 1.

[0141] Comparative Example 7

[0142] This comparative example provides an oil displacement system, which differs from Example 1 only in that no nanoparticles are added, and the reduced content thereof is distributed to the surfactant and the polymer in a mass ratio.

[0143] Comparative Example 8

[0144] This comparative example provides an oil displacement system, which differs from Example 1 only in that no polymer is added, and its reduced content is distributed to the surfactant and the nanoparticles in a mass ratio.

[0145] Comparative Example 9

[0146] This comparative example provides an oil displacement system, which differs from Example 1 only in that no betaine surfactant is added, and its reduced content is distributed to the polymer and the nanoparticles in a mass ratio.

[0147] Comparative Example 10

[0148] This comparative example provides an oil displacement system, which differs from Example 1 in that no nanoparticles are added, the surfactant is petroleum sulfonate, the polymer is ordinary polyacrylamide, and other contents and methods are the same as those in Example 1.

[0149] Examples 1-11 and Comparative Examples 1-10 were tested for oil displacement efficiency.

[0150] Test method: The core flooding test was conducted in accordance with the petroleum industry standard SY / T 6424-2000. The basic procedure is: core evacuation, saturation with formation water - water phase permeability measurement - saturation with crude oil to create bound water - water flooding to 98% water content - injection of chemical flooding slugs - subsequent conversion to formation water flooding to 98% water content. The experimental temperature was 90°C, and formation water with a salinity of 150,000 mg / L was used.

[0151] The above test results are shown in Table 11.

[0152] Table 11

[0153]

[0154]

[0155] From Table 11 we can see that:

[0156] (1) It can be seen from Examples 1-11 that the oil recovery rate of the oil displacement system provided by the present invention after water flooding is further improved to no less than 24.17%, and can reach up to 32.25%, which has a significant recovery rate advantage and is suitable for recovery from high-temperature and high-salinity oil reservoirs.

[0157] (2) By comparing Example 1 with Example 4, Example 5 and Comparative Examples 1-5, it can be seen that the selection of the specific betaine surfactant in the present invention is beneficial to reducing the interfacial tension of the oil displacement system, thereby facilitating further recovery of high-temperature and high-salinity oil reservoirs after water flooding; in addition, the combination of the alkylamide hydroxysulfobetaine surfactant and the alkylaryl hydroxysulfobetaine surfactant can enable the oil displacement system to obtain ultra-low interfacial tension (10 -3 orders of magnitude), which has a better oil displacement effect.

[0158] (3) By comparing Example 1 with Comparative Example 6, it can be seen that the addition of nanoparticles can improve the recovery rate of the oil displacement system after water flooding; further, by comparing Example 1 with Comparative Examples 7-9, it can be seen that the high-temperature and high-salinity reservoir oil displacement system provided by the present invention can play a good synergistic role through the cooperation of a specific betaine surfactant with a specific polymer and nanoparticles, thereby greatly improving the recovery rate after water flooding, while the lack of any one of the components will disrupt the balance of the oil displacement system, thereby failing to play a good synergistic role and failing to obtain the best oil displacement effect.

[0159] In summary, the present invention obtains a specific betaine surfactant by screening the maximum compression modulus of the LB monolayer, and the betaine surfactant works synergistically with specific polymers and nanoparticles to obtain an oil displacement system with ultra-low interfacial tension and excellent emulsification performance under high temperature and high salt conditions, which can effectively improve the recovery rate of high temperature and high salt reservoirs, and can be well applied to tertiary oil recovery.

[0160] The applicant declares that the above is only a specific implementation mode of the present invention, but the protection scope of the present invention is not limited thereto. Those skilled in the art should understand that any changes or substitutions that can be easily thought of by those skilled in the art within the technical scope disclosed by the present invention shall fall within the protection scope and disclosure scope of the present invention.

Claims

1. A high-temperature and high-salinity oil reservoir flooding system, characterized in that: The high-temperature and high-salinity reservoir flooding system comprises the following raw materials in weight percentage: Betaine surfactant 0.05-0.5% Polymer 0.01-0.3% Nanoparticles 0.001-0.01%; The rest is water; The betaine surfactant includes an alkylamide hydroxysulfobetaine surfactant and / or an alkylaryl hydroxysulfobetaine surfactant.

2. The high-temperature and high-salinity reservoir flooding system according to claim 1, characterized in that: In terms of weight percentage, the betaine surfactant is 0.05-0.3%; Preferably, the carbon number of the alkyl group in the alkylamide hydroxysulfobetaine surfactant is 16-28; Preferably, the carbon number of the alkyl group in the alkylaryl hydroxysulfobetaine surfactant is 16-26; Preferably, the betaine surfactant is a combination of an alkylamide hydroxysulfobetaine surfactant and an alkylaryl hydroxysulfobetaine surfactant; Preferably, the mass ratio of the alkylamide hydroxysulfobetaine surfactant to the alkylaryl hydroxysulfobetaine surfactant is (8:2)-(3:7), and more preferably (7:3)-(5:5).

3. The high-temperature and high-salinity reservoir oil displacement system according to claim 1 or 2, characterized in that: The maximum compression modulus of the betaine surfactant is 35-50 mN / m; Preferably, the maximum compression modulus is obtained by screening based on LB monolayer test technology.

4. The high-temperature and high-salinity reservoir flooding system according to any one of claims 1 to 3, characterized in that: In terms of weight percentage, the polymer is 0.05-0.2%; Preferably, the polymer comprises any one of scleroglucan, star-shaped heat-resistant and salt-resistant polymer or heat-resistant and salt-resistant polyacrylamide containing a ring structure, or a combination of at least two thereof, and more preferably star-shaped heat-resistant and salt-resistant polymer and / or heat-resistant and salt-resistant polyacrylamide containing a ring structure; Preferably, the viscosity average molecular weight of the polymer is 3 million to 60 million, more preferably 3 million to 40 million.

5. The high-temperature and high-salinity reservoir flooding system according to any one of claims 1 to 4, characterized in that: In terms of weight percentage, the nanoparticles are 0.005-0.01%; Preferably, the nanoparticles include any one or a combination of at least two of 3-aminopropyltriethoxysilane modified silica, γ-methacryloxypropyltrimethoxysilane modified silica, unmodified silica, ferric oxide, aluminum oxide or 50% methylated modified silica; Preferably, the particle size of the nanoparticles is 10-80 nm, more preferably 15-20 nm.

6. The high-temperature and high-salinity reservoir flooding system according to any one of claims 1 to 5, characterized in that: The water is any one of oilfield injection wastewater, formation water or clean water, or a combination of at least two of them; Preferably, the mineralization of the water is not higher than 200,000 mg / L, more preferably 70,000-200,000 mg / L.

7. The high-temperature and high-salinity reservoir flooding system according to any one of claims 1 to 6, characterized in that: The high-temperature and high-salinity oil reservoir refers to an oil reservoir with a temperature of 50-120°C and a water mineralization of no more than 20,000 mg / L.

8. A method for preparing a high-temperature and high-salinity reservoir flooding system according to any one of claims 1 to 7, characterized in that: The preparation method comprises the following steps: (1) mixing a polymer, nanoparticles and water to obtain a polymer-nanoparticle mother solution, aging and diluting; (2) Adding a betaine surfactant to the diluted solution of the polymer-nanoparticle mother solution in step (1), mixing, and obtaining the high-temperature and high-salinity reservoir flooding system.

9. The method for preparing the high-temperature and high-salinity reservoir flooding system according to claim 8, characterized in that: The aging time in step (1) is 20-30 hours.

10. Use of the high-temperature and high-salinity reservoir oil recovery system according to any one of claims 1 to 7 in tertiary oil recovery.

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