CN114891040A

CN114891040A - Nano-emulsion imbibition oil-displacing agent, molybdenum-containing gemini surfactant and preparation method thereof

Info

Publication number: CN114891040A
Application number: CN202210345564.3A
Authority: CN
Inventors: 徐太平; 李栓; 周京伟; 袁发明
Original assignee: Sichuan Jiebeitong Energy Technology Co ltd
Current assignee: Sichuan Jiebeitong Energy Technology Co ltd
Priority date: 2022-03-31
Filing date: 2022-03-31
Publication date: 2022-08-12

Abstract

The application relates to the field of materials, in particular to a nano-emulsion imbibition oil-displacing agent, a molybdenum-containing gemini surfactant and a preparation method thereof. The preparation method of the gemini surfactant containing molybdenum comprises the following steps: carrying out a contracture reaction on tertiary amine and dichloroethyl ether to obtain contracture-chain tertiary amine; mixing the contracture-chain tertiary amine, isopropanol and molybdenum dioxide, and reacting for 4-5 h at 80-90 ℃. In some embodiments of the present application, preparing the tertiary contracture amine further comprises preparing the tertiary amine by: fatty acid and N, N-dimethylamino propylamine react for 6 to 8 hours at the temperature of between 140 and 160 ℃ under the condition of taking potassium hydroxide as a catalyst. The molybdenum-containing gemini surfactant provided by the application has better lipophilicity, and stronger crude oil emulsifying capacity, has stronger stripping capacity to colloid asphalt, and also has superstrong lubrication resistance reducing performance, reduces the flow resistance of crude oil, and improves the oil displacement speed.

Description

Nano-emulsion imbibition oil-displacing agent, molybdenum-containing gemini surfactant and preparation method thereof

Technical Field

The application relates to the field of materials, in particular to a nano-emulsion imbibition oil-displacing agent, a molybdenum-containing gemini surfactant and a preparation method thereof.

Background

At present, how to improve the development effect of secondary and tertiary oil recovery in medium-high permeability oil fields needs to seek a new technology for improving the recovery efficiency urgently. After the low-permeability oil reservoir is fractured, along with the extension of the exploitation time, the energy of the oil reservoir is continuously consumed, the pressure is continuously reduced, the yield is greatly reduced, even the production is stopped, and a large amount of crude oil remained underground cannot be extracted. Even if the repeated fracturing technology is adopted, the effect is not ideal. Therefore, the nano emulsion imbibition oil displacement technology is the most potential new technology for improving the recovery efficiency in the future.

Disclosure of Invention

An object of the embodiments of the present application is to provide a nanoemulsion imbibition oil displacement agent, a molybdenum-containing gemini surfactant and a preparation method thereof, which aim to improve oil displacement efficiency and improve oil recovery ratio.

The application provides a preparation method of a gemini surfactant containing molybdenum, which comprises the following steps:

carrying out a contracture reaction on tertiary amine and dichloroethyl ether to obtain contracture-chain tertiary amine;

mixing the contracture-chain tertiary amine, isopropanol and molybdenum dioxide, and reacting for 4-5 h at 80-90 ℃.

In some embodiments of the present application, preparing the tertiary contracture amine further comprises preparing the tertiary amine by:

fatty acid and N, N-dimethylamino propylamine react for 6 to 8 hours at the temperature of between 140 and 160 ℃ under the condition of taking potassium hydroxide as a catalyst.

In some embodiments herein, the parts by weight of each component are as follows:

120-150 parts of fatty acid, 30-40 parts of N, N-dimethylaminopropylamine, 40-45 parts of dichloroethyl ether, 120-150 parts of isopropanol and 50-60 parts of molybdenum dichloride dioxide.

The application also provides a molybdenum-containing gemini surfactant, which is prepared by any one of the preparation methods of the molybdenum-containing gemini surfactant.

The application also provides a nano emulsion imbibition oil-displacing agent, which mainly comprises the following components in parts by weight:

40-50 parts of any one of the molybdenum-containing gemini surfactants, 5-10 parts of an organic solvent and 15-20 parts of a mutual solvent.

In some embodiments of the present application, the organic solvent comprises at least one of limonene, cyclopentadiene, jasmone, allene, and delta lactone.

In some embodiments of the present application, the mutual solvent comprises at least one of glycerol carbonate, dimethyl carbonate, and diethyl carbonate.

In some embodiments of the present application, the particle size of the nanoemulsion imbibition oil displacement agent is 20-30 nm.

In some embodiments of the present application, the raw material of the nano emulsion imbibition oil displacement agent further comprises 20-40 parts of water.

The application also provides a preparation method of the nano emulsion imbibition oil displacement agent, which comprises the following steps:

and (3) enabling the nano emulsion to penetrate and absorb the oil displacement agent to obtain a raw material, and stirring and reacting for 1-2 hours under the action of electromagnetic waves.

The nano-emulsion imbibition oil-displacing agent, the molybdenum-containing gemini surfactant and the preparation method thereof provided by the embodiment of the application have at least the following beneficial effects:

the molybdenum-containing gemini surfactant provided by the application has better lipophilicity and super-strong crude oil emulsifying capacity, has stronger stripping capacity to colloid asphalt, and also has super-strong lubricating resistance reducing capacity, so that the flow resistance of crude oil is reduced, and the oil displacement speed is improved.

The nano emulsion imbibition oil displacement agent that this application embodiment provided maintains lower interfacial tension, therefore the initial flow resistance of liquid reduces, and in whole crack network, nano emulsion can migrate more deeply farther, reduces the required driving pressure differential of oil gas flow in the matrix simultaneously by a wide margin to extract crude oil more efficiently. The nano emulsion imbibition oil displacement agent provided by the embodiment of the application can be used for adding in a fracturing pad fluid, the swept volume can be increased, the contact area between a fracture wall surface and a reservoir matrix is increased, and meanwhile, the pressure difference required by seepage of fluid in the matrix to a fracture is increased, so that the final yield is improved.

Drawings

In order to more clearly explain the technical solutions of the embodiments of the present application, the drawings that are required to be used in the embodiments will be briefly described below, it should be understood that the following drawings only illustrate some embodiments of the present application and therefore should not be considered as limiting the scope, and it is obvious to those skilled in the art that other related drawings can be obtained from the drawings without inventive effort.

FIG. 1 is the nuclear magnetic resonance imaging of a dry sample of conglomerate No. 1.

FIG. 2 is a nuclear magnetic resonance imaging chart of No. 1 conglomerate after being soaked in water under pressure for 2 h.

FIG. 3 is a nuclear magnetic resonance imaging chart of No. 1 conglomerate after being soaked in water under pressure for 24 h.

FIG. 4 is the MRI image of the dry sample of conglomerate No. 2.

FIG. 5 is a NMR image of conglomerate No. 2 after soaking in 0.2 wt% of the nanoemulsion provided in example 2 for 2 h.

FIG. 6 is a NMR image of conglomerate No. 2 after soaking in 0.2 wt% of the nanoemulsion provided in example 2 for 24 h.

Fig. 7 shows the nuclear magnetic resonance T2 spectrum.

Fig. 8 shows photographs before, during, and after the experiment of cores No. 3 and 4.

Fig. 9 shows photographs before, during, and after the experiment of cores No. 5 and 6.

Fig. 10 shows photographs before, during, and after the experiment of cores No. 7 and 8.

Fig. 11 shows plots of imbibition recovery versus imbibition time for cores No. 3, 6, and 7.

Fig. 12 shows plots of imbibition recovery versus imbibition time for cores No. 4, 5, and 8.

Fig. 13 shows different system displacement pressure variations.

FIG. 14 shows a graph of oil and water permeability changes.

Fig. 15 is a graph of permeability of core No. 9 as a function of time.

Fig. 16 is a graph of permeability change over time for core No. 10.

Fig. 17 shows the results of oil sand wash experiments.

Figure 18 shows xx6 well production profiles.

Figure 19 shows xx7 well production profiles.

Figure 20 shows an xxH1 well production curve.

Figure 21 shows an xxH2 well production curve.

Figure 22 shows an xxH3 well production curve.

Figure 23 shows an xxH4 well production curve.

Detailed Description

In order to make the objects, technical solutions and advantages of the embodiments of the present application clearer, the technical solutions of the embodiments of the present application will be clearly and completely described below. The examples, in which the specific conditions are not specified, were conducted under the conventional conditions or conditions recommended by the manufacturer. The reagents or instruments used are not indicated by the manufacturer, and are conventional products commercially available.

The nano-emulsion imbibition oil-displacing agent, the molybdenum-containing gemini surfactant and the preparation method thereof of the embodiment of the application are specifically described below.

The preparation method of the gemini surfactant containing molybdenum comprises the following steps:

Specifically, in some embodiments of the present disclosure, the tertiary amine and dichloroethyl ether may be obtained commercially, and in some embodiments of the present disclosure, the tertiary amine may be prepared by the following steps:

Specifically, in the tertiary amine preparation process, the preparation temperature may be 140 ℃, 145 ℃, 150 ℃, 155 ℃, 160 ℃ and the like. The reaction time may be 6h, 7h, 8h, etc.

Illustratively, the tertiary amine is prepared by combining the following fatty acids, N-dimethylaminopropylamine, and potassium hydroxide in parts by weight:

120-150 parts by weight of a fatty acid; such as 120 parts, 125 parts, 130 parts, 135 parts, 140 parts, 145 parts, 150 parts, and the like.

30 to 40 parts by weight of N, N-dimethylaminopropylamine; for example, 30 parts, 31 parts, 32 parts, 33 parts, 34 parts, 35 parts, 36 parts, 38 parts, 40 parts, and the like.

The amount of the potassium hydroxide catalyst is, for example, 0.2 to 0.25 part by weight of potassium hydroxide; for example, 0.2 parts, 0.21 parts, 0.22 parts, 0.23 parts, 0.25 parts, etc.

Carrying out a contracture reaction on tertiary amine and dichloroethyl ether to obtain contracture-chain tertiary amine; as an example, the temperature of the contracture chain reaction is 130 ℃ to 140 ℃; for example, 130 ℃, 133 ℃, 135 ℃, 138 ℃, 140 ℃ and so on. The reaction time is 2h to 3h, such as 2h, 2.2h, 2.5h, 2.7h or 3h, and the like.

In this example, 120 to 150 parts of a fatty acid and 30 to 40 parts of N, N-dimethylaminopropylamine were reacted with 40 to 45 parts of dichloroethyl ether.

For example, the dichloroethyl ether may be 40 parts, 42 parts, 43 parts, 45 parts, and the like by weight.

After obtaining the contracture chain tertiary amine, mixing the contracture chain tertiary amine, isopropanol and molybdenum dioxide, and reacting for 4-5 h at 80-90 ℃; for example, the reaction temperature may be 80 ℃, 85 ℃, 88 ℃, 90 ℃ or the like. The reaction time may be 4h, 4.2h, 4.5h, 5h, and the like.

In some embodiments, 120 to 150 parts by weight of isopropanol, 50 to 60 parts by weight of molybdenum dichloride dioxide; for example, the isopropyl alcohol may be present in 120 parts, 125 parts, 130 parts, 135 parts, 140 parts, 150 parts, and the like, by weight.

The application also provides a molybdenum-containing gemini surfactant which is worthy of being prepared by any one of the preparation methods of the molybdenum-containing gemini surfactant.

40-50 parts of the molybdenum-containing gemini surfactant, 5-10 parts of an organic solvent and 15-20 parts of a mutual solvent;

wherein the organic solvent comprises at least one of limonene, cyclopentadiene, jasmone, propyl lactone and butyl lactone;

the mutual solvent comprises at least one of glycerol carbonate, dimethyl carbonate and diethyl carbonate.

Illustratively, the weight parts of the molybdenum-containing gemini surfactant can be 40 parts, 42 parts, 45 parts, 48 parts and 50 parts.

The organic solvent may be present in an amount of 5 parts, 6 parts, 7 parts, 8 parts, 10 parts, etc.

The parts by weight of mutual solvent may be 15 parts, 16 parts, 18 parts, or 20 parts, and so forth.

In some embodiments of the present application, the raw materials are stirred and reacted for 1 to 2 hours under the action of electromagnetic waves, so as to obtain the nanoemulsion imbibition oil-displacing agent.

In some embodiments of the present application, the nano emulsion imbibition oil displacement agent is stirred and ground to a particle size of 20-30 nm.

The nano-emulsion imbibition oil-displacing agent provided by the embodiment of the application has at least the following advantages:

the nanoemulsion imbibition oil-displacing agent that this application embodiment provided maintains lower interfacial tension, therefore the initial flow resistance of liquid reduces, and in whole crack network, nanoemulsion imbibition oil-displacing agent can migrate more deeply farther, reduces the required driving pressure differential of oil gas flow in the matrix simultaneously by a wide margin to crude oil is extracted more efficiently. The nanoemulsion imbibition oil displacement agent provided by the embodiment of the application can be used for adding in a fracturing pad fluid, so that the swept volume can be increased, the contact area between a fracture wall surface and a reservoir matrix is increased, and meanwhile, the pressure difference required by seepage of fluid in the matrix to a fracture is increased, thereby improving the final yield.

In addition, in some embodiments, the nano emulsion imbibition oil displacement agent has a small molecular size, easily enters a nano pore throat, can greatly increase swept volume, easily removes water lock, indirectly improves the core permeability, and accordingly increases the crude oil conductivity. The nano emulsion imbibition oil displacement agent enters the stratum microporous throat, and residual oil adsorbed on the surface of rock is stripped through the wetting action, so that the fluidity of the oil displacement agent in a porous medium, a natural or artificial crack network is promoted and accelerated.

The nano emulsion imbibition oil displacement agent provided by the embodiment of the application can also be used for old well injection huff and puff, the molecular size of the nano emulsion is small, the nano emulsion can easily enter a pore throat, the Zeta potential on the surface of a rock is changed, the Zeta potential value is higher than the Zeta potential absolute value of a common cleanup additive, and the wetting reversal is easily realized, so that the water lock effect is removed, and meanwhile, the crude oil in the nano pore throat can be replaced, and the oil displacement efficiency is improved.

The features and properties of the present application are described in further detail below with reference to examples.

Example 1

The embodiment provides a gemini surfactant containing molybdenum, and the preparation method comprises the following steps:

(1) adding 125 g of fatty acid and 40 g of N, N-dimethylaminopropylamine into a container with a condensing reflux pipe, carrying out amidation condensation reaction, adding 0.3 g of potassium hydroxide as a catalyst, and carrying out stirring reflux reaction for 6 hours at the reaction temperature of 150 ℃ to obtain an intermediate product, namely tertiary amine;

(2) adding 45 g of dichloroethyl ether into the intermediate product tertiary amine to carry out a contracture reaction at the temperature of 140 ℃, and carrying out stirring reflux reaction for 3 hours to obtain an intermediate product contracture tertiary amine;

(3) adding the prepared intermediate product of the contracture tertiary amine and 120 g of isopropanol into a container, adding 40 g of molybdenum dichloride, stirring and refluxing at 80 ℃ for 4h to react to obtain yellow thick liquid, namely the molybdenum-containing gemini surfactant, wherein the mass percentage content of the effective component multi-branched gemini amphoteric surfactant is 60%.

Example 2

The embodiment provides a nano emulsion imbibition oil displacement agent, and the preparation method comprises the following steps:

50 parts of the molybdenum-containing gemini surfactant prepared in example 1, 10 parts of organic solvent limonene, 20 parts of mutual solvent glycerol carbonate and 20 parts of distilled water are taken.

Adding a gemini surfactant containing molybdenum, an organic solvent limonene and a mutual solvent glycerol carbonate into a reactor; mixing uniformly, heating to keep the temperature in the reactor at 75 ℃, and then adding distilled water; and reacting for 2 hours under the action of electromagnetic waves and stirring to obtain a light yellow transparent liquid sample.

Test example 1

The nano emulsion imbibition oil-displacing agent (hereinafter referred to as nano emulsion) provided in example 2 was subjected to performance test, and the results of the performance test are shown in table 1.

TABLE 1

Serial number	Index (I)	Measurement results
			1	Density (20 ℃ +/-1 ℃) and g/cm ³	1.05
2	pH value	7.0
			3	Median particle diameter, nm	25
4	Surface tension (0.1% add), mN/m	24.3
			5	Interfacial tension (0.1% addition, with kerosene) mN/m	0.004
6	Wetting Angle (0.2% aqueous solution), degree	125.8
			7	Zeta potential Absolute value (0.2% aqueous solution), mV	43.8

Test example 2

The nanoemulsion provided in example 2 was tested for its ability to increase swept volume.

Specifically, 2 rock samples are selected, cleaned and dried (105 ℃, 48 hours), and the length, the diameter and the gas porosity of the rock sample are measured and marked as No. 1 and No. 2 samples. The experimental rock data are shown in table 2; the nuclear magnetic resonance T2 spectrum test and the imaging test were carried out on 2 rock samples by different treatments, the test results are shown in Table 3, and in Table 3, the 0.2% nano solution represents the 0.2% aqueous solution of the nano emulsion imbibition displacement agent provided in example 2.

TABLE 2

The nuclear magnetic resonance imaging images of the 2 rock samples are shown in figures 1-6; wherein, FIG. 1 is a nuclear magnetic resonance imaging chart of a No. 1 conglomerate dry sample; FIG. 2 is a nuclear magnetic resonance imaging chart of No. 1 conglomerate after being soaked in water under pressure for 2 h; FIG. 3 is a nuclear magnetic resonance imaging chart of No. 1 conglomerate after being soaked in water under pressure for 24 h; FIG. 4 is the MRI image of the dry conglomerate sample No. 2; FIG. 5 is a NMR image of conglomerate No. 2 after soaking in 0.2 wt% of the nanoemulsion provided in example 2 for 2 h; FIG. 6 is a NMR image of conglomerate No. 2 after soaking in 0.2 wt% of the nanoemulsion provided in example 2 for 24 h. Fig. 7 shows the nuclear magnetic resonance T2 spectrum.

As can be seen from fig. 1-7: after the No. 1 core is soaked for 2 hours under the pressure of 10MPa, purified water enters 39.79% of movable pore space. After being soaked for 24 hours under the pressure of 10MPa, the purified water enters 78.73 percent of movable pore space of the No. 1 conglomerate. After the core 2 was immersed under 10MPa pressure for 2 hours, 0.2 wt% of the aqueous nanoemulsion solution provided in example 2 entered 75.05% of the mobile pore space. After being soaked for 24 hours under the pressure of 10MPa, the 0.2 wt% of the nanoemulsion aqueous solution provided by the example 2 enters 98.76% of movable pore space of the No. 2 core, and the 0.2 wt% of the nanoemulsion provided by the example 2 has stronger capability of entering the internal pore space of the rock sample than water.

Test example 3

The method comprises the steps of carrying out oil washing treatment on a drilled and cut natural rock core obtained from a site, putting the washed oil into an oil washing instrument according to the ratio of toluene to alcohol being 3:1 by adopting a distillation extraction method, and carrying out extraction and oil washing on the rock core through a high-temperature condensation circulation process, wherein the experimental temperature is 90 ℃, and the experimental pressure is atmospheric pressure. The cores marked as No. 3 and No. 4 are placed in solution preparation water for soaking, the cores marked as No. 5 and No. 6 are soaked in 0.2 wt% of the nano emulsion aqueous solution provided by the embodiment 2 for soaking and seepage, and the cores marked as No. 7 and No. 8 are soaked in 0.5 wt% of the nano emulsion aqueous solution provided by the embodiment 2 for soaking and seepage experiments. The experiment is carried out by adopting a mass method, and the principle is as follows: the method comprises the steps of completely soaking a columnar core saturated with formation crude oil in a water sample (oil displacement agent solution), obtaining the initial mass of the core in the water sample (oil displacement agent solution), wherein the initial mass is influenced by wettability, tubular force and the like, water (oil displacement agent solution) is spontaneously absorbed into core pores to play a role in oil drainage, the total pore volume is unchanged in the whole process, but the total pore volume is influenced by the oil drainage effect of the water (oil displacement agent solution), the mass of the core in the water (oil displacement agent solution) is increased, the discharged oil quantity is equal to the ratio of the mass increment of the core in the water (oil displacement agent solution) to the oil-water density difference according to the Archimedes buoyancy principle, and therefore the soaking spontaneous absorption recovery ratio can be calculated, and the calculation method is shown in formula (1).

In formula (1): r-soaking spontaneous imbibition recovery ratio, decimal;

V _o -total saturated oil volume in core, mL;

Δ m — the mass difference of the core in water (oil-displacing agent solution), g;

ρ _w 、ρ _o density of water (oil-displacing agent solution), oil density, g/cm ³ ；

Fig. 8 shows photographs (water for solution preparation) before, during, and after the No. 3 and No. 4 core experiments. Fig. 9 shows photographs (0.2 wt% of the nanoemulsion provided in example 2) before, during, and after the core experiment No. 5, 6; fig. 10 shows photographs (0.2 wt% of the nanoemulsion provided in example 2) before, during, and after the core experiment No. 7, 8. Fig. 11 shows the imbibition recovery versus imbibition time for cores No. 3, 6, and 7. Fig. 12 shows the plot of imbibition recovery versus imbibition time for cores No. 4, 5, 8. Table 4 shows the core soak imbibition experiments.

Table 4 and fig. 8-11 show that the recovery ratio of the nanoemulsion provided by adding example 2 is significantly higher than that without adding nanoemulsion, the recovery ratio can be improved by more than 30% by 0.2% of the nanoemulsion provided by example 2, and the recovery ratio is improved with the increase of the dosage of the nanoemulsion provided by example 2, but the recovery ratio is only 5.65% higher by 0.5% of the nanoemulsion provided by example 2 than that of 0.2%, and the dosage in the field is 0.2%. This experiment further shows that the nanoemulsion provided in example 2, due to its particular small size, is more likely to enter the fine pore throat, making the oil in the core more likely to be emulsified and stripped under the action of the surfactant molecules.

TABLE 4

Test example 4

An experiment is designed according to a method for determining the relative permeability of the two-phase fluid in GB/T28912-. According to the requirements of simulation conditions, a constant pressure difference or constant speed water-driven oil test is carried out on an oil reservoir rock sample, the output of each fluid and the change of the pressure difference at two ends of the rock sample along with time are recorded at the outlet end of the rock sample, the oil-water relative permeability is obtained by calculation through a J.B.N. method, and a relation curve of the oil-water relative permeability and the water saturation is drawn. The specific experimental process comprises the following steps: (1) drying the core, weighing the dry weight, vacuumizing the saturated formation water with the pressure of 20MPa, weighing the wet weight, and determining the porosity and the pore volume; (2) after the connection device is finished, the pressure is increased by 10MPa, so that the whole displacement system is ensured to have no loss; (3) loading the rock core into a rock core holder, respectively loading formation water and simulated oil into an intermediate container, keeping the confining pressure 3MPa higher than the displacement pressure, and keeping the temperature at normal temperature for 1 d; (4) displacing simulated oil, determining proper speed, finding out proper pressure difference and displacement speed of 23.6MPa and 0.03mL/min in a mode of increasing the pressure difference until no water flows out, and determining the saturation of the bound water of the rock core; (5) aging the rock sample of the saturated simulation oil for 3d under the conditions of normal temperature and oil phase stable pressure of 13.4MPa, so that the fluid is fully contacted and saturated with the pore throat of the rock sample to simulate the original wettability of the rock sample; (6) accurately recording the water production time at the outlet end of the rock sample, the accumulated oil production during water production, the accumulated liquid production amount, the water displacement speed and the displacement differential pressure at the inlet and the outlet ends of the rock sample; (7) at the initial stage of water production, recording is encrypted, and proper time intervals (which can be recorded once in 5s, 10s, 15s, 20s and 30 s) are selected according to the oil production quantity at the outlet end of the rock sample. With the continuous reduction of the oil production at the outlet end, the recording time is gradually increased (the recording time can be once for 3min, 5min, 10min, 20min and 30 min). When the water yield at the outlet end is more than 99.95 percent or the injection volume of the rock sample is more than 50 times of the pore volume, measuring the water phase permeability under the saturation degree of the residual oil, and ending the experiment; (8) and cleaning the experimental rock sample, drying and recovering the wettability, re-measuring the porosity and the permeability of the rock sample after recovering the wettability, repeating the above experimental steps, and performing a displacement experiment under the condition of the nano emulsion.

FIG. 13 shows different system displacement pressure variations; it can be seen from fig. 13 that after the end water breakthrough, the pressure rises briefly and then drops gradually. The nano emulsion tends to be stable in 24 hours, the oil-water phase osmotic pressure difference of the nano emulsion drive is lower than that of formation water only, although the pressure difference is higher than that of the formation water phase at the initial moment, the pressure difference can be rapidly reduced in a short time, and is kept level with the water drive after 2.5 hours, and then the pressure difference is lower than that of the water drive. The antihypertensive effect after the nano emulsion is used is proved to be obvious.

FIG. 14 shows a graph of oil and water permeability changes. As can be seen from fig. 14, during the displacement, the relative permeability of the oil phase gradually decreased and the relative permeability of the water phase gradually increased. The nano emulsion changes the wettability of the pore throat wall surface of the rock core, increases the flowing property of water, generates an imbibition effect, increases the relative permeability of the water, allows more water phase to enter micro pores, and allows small pore oil to be replaced to enter large pores, thereby improving the oil extraction efficiency. Residual oil saturation at water flooding was 20.9%; the residual oil saturation at nanoemulsion flooding was 10.8%, which reduced the residual oil saturation by 10.1%.

Test example 5

And (3) selecting natural rock cores of the X blocks of the Xinjiang oil field, washing oil, drying, and testing the pore volume and the porosity of the rock cores. And treating the treated core by adopting a mode of saturating crude oil for 72 hours under the pressure of 30MPa, placing the saturated core in a water bath environment at 60 ℃ for an imbibition oil displacement experiment, recording oil output at different moments, and calculating the recovery ratio after the experiment is balanced.

TABLE 5

TABLE 6

Fig. 15 and 16 are graphs of permeability changes of cores No. 9 and No. 10 with time, respectively, and it can be seen from fig. 15 and fig. 16 that the permeability of the core shows a certain downward trend along with the injection of a fracturing fluid system of 0.2% nano-emulsion; gradually recovering along with the increase of the displacement multiple of the standard saline water, recovering from blockage along with the increase of the displacement multiple, and increasing the permeability along with time; also, the core permeability returned to the initial value after 15PV displacement. The permeability of the nano emulsion after displacement is increased, which indicates that the nano emulsion has better permeability increasing effect.

Test example 6

Cleaning 20-40 mesh quartz sand, drying, uniformly mixing with Xinjiang crude oil according to a ratio of 6:1, and standing for more than 2 hours; adding 500mL of 0.2% nano emulsion into a ground scale imbibition bottle, and keeping the temperature at 90 ℃ for 60 min; about 14g of oil sand was added and the oil was washed at 90 c and the amount of oil washed out was observed and recorded. And comparing the oil washing performance of the nano emulsion with that of a conventional oil displacement agent (JS-02) under the same concentration.

TABLE 7

FIG. 17 shows the results of an oil sand wash experiment (JS-02 on the left, nanoemulsion flooding agent on the right); the oil washing effect of the nano-emulsion oil displacement agent is obvious from the experimental result, when the concentration is 0.2%, the oil washing rate reaches 46.76%, and the oil washing rate of 0.2% JS-02 is 11.68%.

Test example 7

And (3) after the rock core is treated, testing the permeability, then testing saturated water and saturated oil, displacing by adopting different displacement media, reading the oil quantity, and calculating the recovery ratio.

TABLE 8

TABLE 9

Dynamic displacement experiments show that the crude oil recovery rate is only 54.32% when water flooding is carried out at 8PV, the crude oil recovery rate is 64.55% after water flooding is carried out at 4PV, and the crude oil recovery rate is improved by 10.23% compared with that of water flooding; if the 0.2% nano emulsion flooding 8PV is adopted, the crude oil recovery rate is 72.38%, which is 18.06% higher than that of water flooding.

Test example 8

The fracturing flowback fluid and different oil displacement agents are preferably selected for field test, the oil displacement effect of the nano emulsion is evaluated, and a basis is provided for later-stage tests such as repeated fracturing energization and liquid injection huff and puff. Preferably, experiments are carried out on xx6 and xx7 wells with similar geological and engineering conditions of the Ma 18-block ai lake 1 fault block and 2 wells, and no yield exists and the conditions are adjusted before the construction of the two wells.

Watch 10

The injection amount isThe void content is 50 percent. Simultaneously, the injection is carried out under the condition of low discharge capacity, and the injection discharge capacity is 1-2 m ³ /min。

TABLE 11

Item	xx6	xx7
			Deficiency amount, m ³	10533	12083.2
Injection medium	Conventional oil displacement agent	Nano-emulsion
			Concentration of implant	Concentration at the same cost	0.2％
Amount of injection, m ³	5000	5500
			Injection displacement, m ³ /min	1-2	1-2
Injection voltage limiting, MPa	60	60
			Time of soaking	15-20	15-20

xx6 (conventional oil displacement agent), opening the well after the well is stewed to be pressure balance, the oil production time is 6 days, the self-spray period is 115d, the oil production is 202.3t, the post-pumping production is carried out, the accumulated oil production is 578.5t, the accumulated oil production is 1932.6t, and the flowback rate is 24.08%.

xx7 (nano emulsion), opening the well after stewing until the pressure is balanced, and obtaining the oil production time of 2 days, the self-blowout period of 112d, the oil production of 363.8t, and the oil production of 899.8t by pumping. The accumulated yield is 1718.3t, and the flowback rate is 14.88%.

Fig. 18 and 19 show xx6 and xx7 well production profiles, respectively. Mine tests show that the xx7 well has higher oil yield and lower flowback rate, which shows that the nano emulsion has better imbibition and replacement effects, and also proves that the throughput effect of the nano emulsion oil displacement agent is better than that of the conventional oil displacement agent.

Test example 9

Through the comparison experiment of injecting the nano emulsion into the fracturing head of the new well and not injecting the nano emulsion, the basis for judging that the nano emulsion can play the roles of increasing yield and increasing efficiency on the fracturing of the new well is provided. Two groups of adjacent wells with similar geological conditions in the Mar 18 block are selected for carrying out a control experiment, and 4 wells are fractured by new wells. FIGS. 20 and 21 show production curves for xxH1 wells versus xxH2 wells, respectively; and xxH1 the production is started after the nano emulsion is added into the front liquid of the well and xxH2 wells are stewed for 10 days without the nano emulsion, xxH1 wells are compared with xxH2 wells, xxH1 with the nano emulsion is added, the oil is quickly seen, the water content is quickly reduced, and the short-term average daily oil production level is high.

FIGS. 22 and 23 show production curves for xxH3 wells versus xxH4 wells, respectively; and (3) adding the nano emulsion into a xxH3 well and not adding the nano emulsion into a xxH4 well, opening the well for production after stewing for 1d, wherein the production level is relatively close to that of a xxH3 well and a xxH4 well, and the reason is that the stewing time is short, the nano emulsion cannot effectively enter the pore throat for carrying out, and the oil-water replacement is insufficient.

Comparing the xxH1 well with the xxH2 well shows that after the nano emulsion is injected before fracturing the new well, oil is quickly seen, the water content is quickly reduced, and the short-term average daily oil production level is high. Meanwhile, two well group tests show that the soaking time is favorable for the nano emulsion to enter the pore throat for displacement of reservoir oil.

The above description is only a preferred embodiment of the present application and is not intended to limit the present application, and various modifications and changes may be made to the present application by those skilled in the art. Any modification, equivalent replacement, improvement and the like made within the spirit and principle of the present application shall be included in the protection scope of the present application.

Claims

1. A preparation method of a gemini surfactant containing molybdenum is characterized by comprising the following steps:

2. The method for preparing the gemini surfactant containing molybdenum according to claim 1, wherein the step of preparing the tertiary amine containing contracture chain further comprises the following steps:

fatty acid and N, N-dimethylamino propylamine react for 6 to 8 hours at the temperature of between 140 and 160 ℃ under the condition that potassium hydroxide is used as a catalyst.

3. The method for preparing the gemini surfactant containing molybdenum according to claim 2, wherein the weight parts of the components are as follows:

4. A molybdenum-containing gemini surfactant, characterized in that it is obtained by the process for the preparation of a molybdenum-containing gemini surfactant according to any one of claims 1 to 3.

5. The nano emulsion imbibition oil-displacing agent is characterized in that the raw materials of the nano emulsion imbibition oil-displacing agent mainly comprise the following components in parts by weight:

40 to 50 parts of the molybdenum-containing gemini surfactant described in claim 4, 5 to 10 parts of an organic solvent and 15 to 20 parts of a mutual solvent.

6. The nanoemulsion imbibition oil-displacing agent of claim 5, wherein the organic solvent comprises at least one of limonene, cyclopentadiene, jasmone, gamma lactone, and delta lactone.

7. The nanoemulsion imbibition oil-displacing agent of claim 5, wherein the mutual solvent comprises at least one of glycerol carbonate, dimethyl carbonate, and diethyl carbonate.

8. The nanoemulsion oil-displacing agent according to claim 5, wherein the particle size of the nanoemulsion oil-displacing agent is 20-30 nm.

9. The nanoemulsion oil-displacing agent according to claim 5, wherein the raw material of the nanoemulsion oil-displacing agent further comprises 20-40 parts of water.

10. The method for producing the nanoemulsion imbibition oil-displacing agent according to any one of claims 5 to 9, comprising: