Application of deep eutectic solvent and oil displacement agent and water flooding exploitation method for deep heavy oil reservoir

Abstract

The application provides application of a deep eutectic solvent, an oil displacement agent and a water flooding exploitation method for a deep heavy oil reservoir. The deep eutectic solvent is applied to reservoir development. The oil displacement agent contains the deep eutectic solvent, and the mass fraction of the deep eutectic solvent in the oil displacement agent is not less than 1.5% based on the total mass of the oil displacement agent. The oil displacement agent can realize self-emulsification of heavy oil in the deep heavy oil reservoir to form a water-in-oil emulsion. The water flooding exploitation method for the deep heavy oil reservoir comprises the following steps: injecting the oil displacement agent containing the deep eutectic solvent into the deep heavy oil reservoir; and injecting water into the deep heavy oil reservoir after the injection of the oil displacement agent. The water flooding exploitation method for the deep heavy oil reservoir forms a stable water-in-oil emulsion by injecting the oil displacement agent containing the deep eutectic solvent into the deep heavy oil reservoir, realizes self-adaptive profile control and displacement by means of the self-adaptive profile control and displacement of the water-in-oil emulsion, reduces the degree of water channeling in the subsequent water injection development process, and thus improves the sweep volume and the recovery efficiency.

Description

Technical Field

[0001] This invention belongs to the field of oilfield development technology, specifically relating to the application of a low eutectic solvent, an oil displacement agent containing a low eutectic solvent, and a waterflooding method for deep heavy oil reservoirs using a low eutectic solvent. Background Technology

[0002] Deep heavy oil reservoirs are difficult to develop economically and effectively due to their deep burial depth, poor physical properties, and low single-well production. Heavy oil, due to its high viscosity, is primarily extracted using thermal recovery methods such as steam injection. However, because deep heavy oil reservoirs are buried at depths greater than 1600m, conventional steam injection methods suffer from significant heat loss along the extraction path and poor adaptability, making it difficult to achieve economically and effectively develop deep heavy oil reservoirs.

[0003] Deep heavy oil reservoirs are typically developed using cold recovery methods, such as waterflooding, chemical flooding, and CO2 flooding. Waterflooding for deep heavy oil reservoirs often results in severe water channeling after a period of development, leading to high water cut in the produced fluid (generally greater than 50%) and low oil recovery. Chemical flooding can form oil-in-water emulsions to reduce crude oil viscosity, but mass transfer is poor, and water channeling remains difficult to control, limiting the affected volume and keeping recovery rates low. CO2 flooding effectively reduces water and rate sensitivity, but continuous CO2 injection is currently difficult due to limitations in CO2 sources and costs. Furthermore, CO2 flooding produced fluid treatment is challenging and highly corrosive to equipment and pipelines. Using foaming agents for deep heavy oil reservoir development suffers from poor foam stability, making it difficult to guarantee development results. In short, the development of deep heavy oil reservoirs still faces enormous challenges and difficulties, with the vast majority of reserves difficult to utilize, and there is an urgent need to explore effective extraction technologies. Summary of the Invention

[0004] The purpose of this invention is to provide a technical solution that can promote the recovery rate of deep heavy oil reservoirs.

[0005] To achieve the above objectives, the present invention provides the following technical solution.

[0006] In a first aspect, the present invention provides the application of eutectic solvents in reservoir development.

[0007] According to a preferred embodiment of the first aspect, the eutectic solvent is used as an oil displacement agent in reservoir development.

[0008] According to a preferred embodiment of the first aspect, the reservoir development is deep heavy oil reservoir development.

[0009] According to a preferred embodiment of the first aspect, the hydrogen bond acceptor compound in the eutectic solvent includes choline chloride; the hydrogen bond donor compound in the eutectic solvent includes sodium bicarbonate, carbamide, or glycerol, etc.

[0010] Furthermore, the molar ratio of the hydrogen bond acceptor compound to the hydrogen bond donor compound in the eutectic solvent is 1:1 to 1:2;

[0011] Furthermore, the eutectic solvent is composed of a hydrogen bond acceptor compound and a hydrogen bond donor compound; in a specific embodiment, choline chloride and the hydrogen bond donor compound sodium bicarbonate are mixed in a molar ratio of 1:1 to 1:2 to obtain the eutectic solvent, and the mixture is continuously stirred at a constant temperature; wherein, the mixing temperature is 85°C, the mixing time is 4.5 h, and the mixing is carried out by stirring.

[0012] Eutectic solvents, as an alternative to ionic liquids, have gained increasing attention in recent years due to their advantages of being green, inexpensive, and easy to synthesize. They offer significant advantages in chemical synthesis, electrodeposition, ionization, CO2 adsorption, and fuel oil desulfurization and denitrification, demonstrating broad prospects. This invention utilizes eutectic solvents in oil reservoir development. Under the action of the eutectic solvent, crude oil in the reservoir can form a stable water-in-oil emulsion. Combined with waterflooding development, this can effectively improve the development effect of oil reservoirs (especially deep heavy oil reservoirs).

[0013] In a second aspect, the present invention provides an oil displacement agent, wherein the oil displacement agent comprises a eutectic solvent; based on the total mass of the oil displacement agent as 100%, the mass fraction of the eutectic solvent in the oil displacement agent is not less than 1.5%.

[0014] According to a preferred embodiment of the second aspect, based on the total mass of the oil displacement agent being 100%, the mass fraction of the eutectic solvent in the oil displacement agent is 1.5%-3.5%.

[0015] According to a preferred embodiment of the second aspect, the oil displacement agent further comprises a nanoparticle stabilizer, wherein the mass ratio of the nanoparticle stabilizer to the eutectic solvent in the oil displacement agent is 1:2-2:3.

[0016] Furthermore, the nanoparticle stabilizer includes SiO2 nanoparticles and / or nano-clay particles;

[0017] For example, the oil displacement agent is composed of a eutectic solvent, a nanoparticle stabilizer, and reservoir formation water.

[0018] After the oil displacement agent provided by this invention is injected into a deep heavy oil reservoir, it can form a water-in-oil emulsion with the help of a eutectic solvent. The addition of nanoparticle stabilizers helps to better stabilize the formed water-in-oil emulsion.

[0019] According to a preferred embodiment of the second aspect, the hydrogen bond acceptor compound in the eutectic solvent includes choline chloride; the hydrogen bond donor compound in the eutectic solvent includes sodium bicarbonate, carbamide, or glycerol.

[0020] Furthermore, the molar ratio of hydrogen bond acceptor compound to hydrogen bond donor compound in the eutectic solvent contained in the oil displacement agent is 1:2;

[0021] Furthermore, the eutectic solvent is composed of a hydrogen bond acceptor compound and a hydrogen bond donor compound.

[0022] According to a preferred embodiment of the second aspect, the oil displacement agent is prepared by the following manner:

[0023] Preparation of eutectic solvents;

[0024] A nanoparticle stabilizer is added to a eutectic solvent to obtain the oil displacement agent mother liquor;

[0025] The oil displacement agent is obtained by diluting the mother liquor of the oil displacement agent;

[0026] Furthermore, the oil displacement agent mother liquor is diluted using reservoir formation water.

[0027] In one specific embodiment, choline chloride and carbamide are mixed at a constant temperature with continuous stirring according to a molar fraction of 1:1-1:2 for pure components to obtain a eutectic solvent; wherein, the mixing temperature is 85°C, the mixing time is 4.5 h, the mixing is carried out by stirring, and after mixing, the solid phase changes into a liquid phase, and remains a liquid phase after cooling;

[0028] Adding a nanoparticle stabilizer to a eutectic solvent yields an oil displacement agent mother liquor;

[0029] The oil displacement agent is obtained by diluting the mother liquor of the oil displacement agent with reservoir formation water.

[0030] The oil displacement agent containing a eutectic solvent provided by this invention can achieve self-emulsification of heavy oil in deep heavy oil reservoirs, forming a water-in-oil emulsion. This oil displacement agent containing a eutectic solvent is inexpensive, environmentally friendly, and has good application prospects.

[0031] Thirdly, the present invention provides a waterflooding method for deep heavy oil reservoirs, the method comprising:

[0032] Oil displacement agent injection procedure: Inject the oil displacement agent provided in the second aspect into the deep heavy oil reservoir;

[0033] Water injection procedure: Water is injected into the deep heavy oil reservoir after the oil displacement agent provided in the second aspect is injected.

[0034] The second aspect provides that, after the oil displacement agent comes into full contact with the underground crude oil in deep heavy oil reservoirs, it can form a water-in-oil emulsion with the help of a eutectic solvent. This increases the viscosity of the formation crude oil by 5-8 times, playing a role in viscosity enhancement, adaptive displacement and profile control. It improves the oil-water mobility ratio in the subsequent waterflooding process, controls the degree of fingering and tongueing, and reduces water channeling, thereby expanding the displacement sweep volume and improving the recovery rate of deep heavy oil reservoirs. In particular, the asphaltenes contained in the underground crude oil in deep heavy oil reservoirs can act as a naturally occurring catalyst to further facilitate the stable formation of the water-in-oil emulsion.

[0035] According to a preferred embodiment of the third aspect, the method includes:

[0036] Gas injection procedure: Gas is injected into the deep heavy oil reservoir before the oil displacement agent provided in the second aspect is injected;

[0037] Injected gas can reduce the viscosity of crude oil in deep heavy oil reservoirs, increase displacement mobility, and make the heavy oil easier to displace. Using injected gas in combination with injected oil displacement agents containing eutectic solvents and injected water can further improve the recovery rate of deep heavy oil reservoirs. In a specific laboratory one-dimensional sand-packed pipe displacement experiment (see...),... Figure 1 The displacement efficiency was increased from 25% in conventional water drive to over 70% (see...). Figure 2 In a specific field implementation, the recovery rate can be increased from 15% to 39.7% with water drive, taking into account a formation swept volume of 65%.

[0038] According to a preferred embodiment of the third aspect, the method includes:

[0039] Gas injection procedure: Injecting gas into deep heavy oil reservoirs;

[0040] Oil displacement agent injection procedure: After gas injection, the oil displacement agent provided in the second aspect is injected into the deep heavy oil reservoir;

[0041] Water injection procedure: After injecting the oil displacement agent provided in the second aspect, water is injected into the deep heavy oil reservoir;

[0042] Alternating injection steps: Repeated steps of gas injection followed by water injection;

[0043] In this preferred technical solution, gas, an oil displacement agent containing a eutectic solvent, and water are sequentially injected in a slug-type manner for displacement. The gas can reduce the viscosity of crude oil and increase displacement mobility, while the eutectic solvent can form a stable water-in-oil emulsion, playing an adaptive emulsification and profile control role. This controls the fingering and tongueing of the subsequent water-driven heavy oil and reduces water channeling during the water-drive process, forming four zones: water, water-in-oil emulsion, gas, and oil. This better expands the swept volume and improves the recovery rate of deep heavy oil reservoirs.

[0044] According to the preferred embodiment of the third aspect, gas is injected into a deep heavy oil reservoir while production is carried out using a production well;

[0045] At this point, deep heavy oil reservoirs utilize gas displacement.

[0046] According to the preferred embodiment of the third aspect, while injecting the oil displacement agent provided in the second aspect into the deep heavy oil reservoir, production is carried out using production wells.

[0047] At this point, the deep heavy oil reservoir is displaced using the displacement agent provided in the second aspect.

[0048] According to the preferred embodiment of the third aspect, water is injected into a deep heavy oil reservoir while production is carried out using a production well;

[0049] At this point, water is used to displace the deep heavy oil reservoir.

[0050] According to a preferred embodiment of the third aspect, in the oil displacement agent injection step, the injection amount of the oil displacement agent provided in the second aspect is 0.05PV-0.1PV;

[0051] In one specific embodiment, the amount of oil displacement agent provided by the second aspect is 1000-2000 tons.

[0052] According to a preferred embodiment of the third aspect, in the gas injection step, the gas is methane gas;

[0053] Furthermore, in the gas injection step, the amount of methane gas injected is 0.1-0.2 PV.

[0054] According to a preferred embodiment of the third aspect, in the water injection step, the amount of water injected is 0.05PV-0.2PV.

[0055] The oil displacement effect can be further improved by optimizing the injection volume.

[0056] According to a preferred embodiment of the third aspect, in the oil displacement agent injection step, the injection rate of the oil displacement agent provided in the second aspect is 100-300 tons / day.

[0057] According to a preferred embodiment of the third aspect, in the water injection step, the injection-to-production ratio is 0.9-1.1;

[0058] Maintaining an injection-production ratio of 0.9-1.1 helps stabilize formation pressure and effectively prevents severe water channeling caused by excessive injection speed. Once the well shows improvement, fluid extraction can be considered.

[0059] According to the preferred embodiment of the third aspect, the well spacing between the injection and production wells in the deep heavy oil reservoir is 100-200 meters.

[0060] According to the preferred embodiment of the third aspect, the water cut of the deep heavy oil reservoir is not less than 70%.

[0061] The waterflooding method for deep heavy oil reservoirs provided by this invention effectively solves the technical challenges of waterflooding for deep heavy oil production. By injecting an oil displacement agent with added eutectic solvents to form a stable water-in-oil emulsion, the self-adaptive profile control of the water-in-oil emulsion enhances the swept volume, thereby significantly improving oil recovery. This provides a new technical approach for the effective development of deep heavy oil reservoirs. Compared to steam injection development, the waterflooding method for deep heavy oil reservoirs provided by this invention is lower in cost and carbon emissions, contributing to the stable, green, economical, and efficient development of deep heavy oil reservoirs.

[0062] Compared with the prior art, the technical solution provided by the present invention has the following beneficial effects:

[0063] The oil displacement agent provided by this invention has advantages in reducing interfacial tension, altering wettability, emulsification stability, and thermal stability; this oil displacement agent can effectively achieve crude oil self-emulsification to form a water-in-oil emulsion, and can reduce interfacial tension by 85-90% (see...). Figures 3-5 It can achieve deep profile and displacement adjustment, greatly improving oil displacement efficiency.

[0064] (2) The oil displacement agent provided by the present invention has readily available raw materials, low cost, and quick preparation process, and has excellent application prospects in mines.

[0065] (3) The water-drive exploitation method for deep heavy oil reservoirs provided by the present invention breaks away from the traditional concept of water-in-oil emulsion to reduce viscosity and improve recovery rate in heavy oil exploitation. By injecting an oil displacement agent with added low eutectic solvent to form a stable water-in-oil emulsion, adaptive displacement and profile adjustment are achieved to reduce water channeling and increase swept volume, thereby significantly improving the recovery rate (in one specific embodiment, the swept volume can be increased from 30% to 60%, and the recovery rate can be increased from 12% to 40% of conventional water drive), opening up a new idea for cold exploitation technology of deep heavy oil reservoirs.

[0066] (4) The water-drive exploitation method for deep heavy oil reservoirs provided by this invention can achieve effective development of deep heavy oil reservoirs without the need for steam injection. Compared with steam injection exploitation, the cost can be reduced by about 40%, resulting in considerable economic benefits. The elimination of heating can reduce CO2 emissions by more than half, which helps to achieve green development of heavy oil.

[0067] (5) Compared with conventional chemical viscosity-reducing waterflooding technology, the waterflooding method for deep heavy oil reservoirs provided by this invention breaks with conventional thinking and goes against the grain. It first increases viscosity to block water channeling channels and then injects water to advance the oil. It uses waterflooding to replace the oil wall formed by emulsified oil, thereby reducing the risk of water channeling, expanding the swept volume and oil displacement efficiency, and making up for the shortcomings of poor waterflooding efficiency for deep heavy oil, poor mass transfer and diffusion capacity of chemical viscosity-reducing technology, and high cost of measures. Attached Figure Description

[0068] Figure 1 This is a diagram of the experimental setup for sand-filled pipe displacement.

[0069] Figure 2 This is a comparison chart of the extraction rates in the sand-filled pipe experiment.

[0070] Figure 3 This is a diagram of an interfacial tension measuring device.

[0071] Figure 4A This is a graph showing the measurement of water interfacial tension.

[0072] Figure 4B The diagram shows the interfacial tension of an oil displacement agent with a concentration of 0.125%.

[0073] Figure 5 This is a diagram showing the change in interfacial tension of the oil phase.

[0074] Figure 6 This is a schematic diagram of the displacement mode of the waterflooding method for deep heavy oil reservoirs provided in Embodiment 1 of the present invention.

[0075] Figure 7 This is a schematic diagram of the displacement mode of the waterflooding method for deep heavy oil reservoirs provided in Embodiment 1 of the present invention. Detailed Implementation

[0076] To make the objectives, technical solutions, and advantages of the embodiments of the present invention clearer, the technical solutions of the embodiments of the present invention will be clearly and completely described below with reference to the accompanying drawings. Obviously, the described embodiments are only some, not all, of the embodiments of the present invention. Based on the embodiments of the present invention, all other embodiments obtained by those skilled in the art without creative effort are within the protection scope of the present invention.

[0077] In this invention, deep heavy oil reservoirs refer to reservoirs with a depth greater than 1600m and a crude oil viscosity of 3000-20000cp at 50℃. Deep heavy oil reservoirs typically exhibit characteristics such as deep burial, poor physical properties, high salinity, and poor adaptability to conventional thermal recovery technologies.

[0078] In this invention, a eutectic solvent refers to a two- or three-component eutectic mixture composed of hydrogen bond acceptors and hydrogen bond donors in a certain stoichiometric ratio, whose freezing point is significantly lower than the melting point of each component pure substance.

[0079] In this invention, emulsification refers to the uniform dispersion of one liquid into extremely small droplets in another immiscible liquid.

[0080] Example 1

[0081] This embodiment provides an oil displacement agent, which is prepared by the following method:

[0082] Sodium bicarbonate and choline chloride were mixed in a molar ratio of 2:1 to obtain a eutectic solvent (the melting point of sodium bicarbonate is 270℃, the melting point of choline chloride is 305℃, and the freezing point of the resulting eutectic solution is 150℃, lower than the melting points of the two components); the mixing temperature was 85℃, and the mixing time was 4.5 hours; SiO2 nanoparticle stabilizer was added to the eutectic solvent to obtain an oil displacement agent mother liquor; the mass ratio of the nanoparticle stabilizer to the eutectic solvent was 1:2.

[0083] The oil displacement agent is obtained by diluting the mother liquor with reservoir formation water; wherein, based on the total mass of the oil displacement agent being 100%, the mass fraction of the mother liquor is 2.5 wt%.

[0084] This embodiment provides a water-drive development method for deep heavy oil reservoirs. This method is used for the further development of a deep extra-heavy oil reservoir. The average burial depth of this deep extra-heavy oil reservoir is 1650m, the oil layer thickness is 30m, the reservoir temperature is 52℃, the formation pressure is 16.9MPa, the average porosity is 20%, the average permeability is 80mD, the average crude oil viscosity under formation conditions is 900mPa·s, and the crude oil viscosity at 50℃ is 3200mPa·s. The reservoir was initially developed using the nine-point vertical well water-drive method. The current average water cut has reached about 85%, and the current water-drive recovery rate is only 10%. The injection-production well spacing of the well network in the target deep heavy oil reservoir is 100m.

[0085] The waterflooding exploitation method for this deep heavy oil reservoir is as follows: Figure 6 As shown, the specific steps include the following:

[0086] (1) Gas injection procedure: 0.15 PV of methane gas is injected into the target deep heavy oil reservoir using an injection well at an injection rate of 2400 m / s. 3 / day, injection duration 15 days; among which, the production well group maintains production status, the gas production of the production well is 80%, and the oil production of the production well group is 6t / day;

[0087] (2) Oil displacement agent injection step: After step (1) is completed, the oil displacement agent provided in this embodiment is injected into the target deep heavy oil reservoir using the injection well; wherein, the oil displacement agent injection amount is 0.05PV, the injection rate is 200t / day, and the injection period is 5 days; wherein, the production well maintains the production state, and the production output of the production well group is 7.5t / day.

[0088] When the oil displacement agent, formation water, and crude oil come into full contact, a high-viscosity water-in-oil emulsion is formed.

[0089] (3) Water injection step: After step (2) is completed, water is injected into the target deep heavy oil reservoir using injection wells; the water injection rate is 200t / day, the continuous water injection time is 10 days, and the water injection volume is 0.1PV; the production wells maintain production status, and the well group production is 9t / day; the injection-production ratio is maintained at an average of 1.0.

[0090] (4) Alternate injection steps: Repeat steps (1)-(3); After six months of production, the oil production of the well group can be increased to 15t / day.

[0091] Compared with conventional heavy oil thermal recovery, the waterflooding method for deep heavy oil reservoirs requires zero heat, greatly reducing operating costs and carbon emissions. Compared with conventional waterflooding, it can significantly improve the recovery rate. The chemical formula provided in this method is low in cost and has good development effect, making it suitable for large-scale promotion, testing and application.

[0092] The water-drive production method for deep heavy oil reservoirs provided by this invention is used to develop target deep heavy oil reservoirs. The expected economically effective production time is about 11 years, and the final crude oil recovery rate during the economically effective production period can reach 29%, with a corresponding water cut of 82% in the produced fluid. Without considering economic benefits, the final recovery rate can reach 39.7%.

[0093] If conventional water drive (injection rate of 200t / day, injection-production ratio maintained at around 1.0) is used to develop the target deep heavy oil reservoir, the expected economically effective production time is about 5.2 years, the final crude oil recovery rate during the economically effective production period can reach 12%, and the corresponding produced fluid water cut is 95%; without considering economic benefits, the final recovery rate can reach 15%.

[0094] The water-drive development method for deep heavy oil reservoirs provided by this invention can increase the recovery rate of target deep heavy oil reservoirs from 15% to 39.7% by water-drive, considering a formation swept volume of 65%.

[0095] Example 2

[0096] This embodiment provides an oil displacement agent, which is prepared by the following method:

[0097] Carbamide and choline chloride were mixed in a molar ratio of 2:1 to obtain a eutectic solvent; the mixing temperature was 80℃ and the mixing time was 4 hours; the melting point of carbamide was 132.7℃ and the melting point of choline chloride was 305℃, and the freezing point of the eutectic solution formed after mixing was 105℃, which was lower than the melting points of the two components.

[0098] Adding nano-particle stabilizer nano-clay particles to a eutectic solvent yields an oil displacement agent mother liquor; wherein the mass ratio of nano-clay particle stabilizer to eutectic solvent is 2:3.

[0099] The oil displacement agent mother liquor is diluted with mineralized water corresponding to the oil reservoir to obtain the oil displacement agent; wherein, based on the total mass of the oil displacement agent being 100%, the mass fraction of the oil displacement agent mother liquor is 2 wt%.

[0100] This embodiment provides a water-drive development method for deep heavy oil reservoirs, used for the further development of a certain deep extra-heavy oil reservoir. This deep extra-heavy oil reservoir has an average burial depth of 2000m, an oil layer thickness of 40m, a reservoir temperature of 52℃, a formation pressure of 25MPa, an average porosity of 22%, an average permeability of 380mD, and a crude oil degassed viscosity of 8620mPa·s at 50℃. Initially, the reservoir was developed using a nine-point vertical well water-drive method, and the current average water cut has reached approximately 80%. However, the initial water-drive development of this reservoir was ineffective, resulting in extremely low economic benefits. The injection-production well spacing of the well pattern in the target deep heavy oil reservoir is 150m.

[0101] The waterflooding exploitation method for this deep heavy oil reservoir is as follows: Figure 7 As shown, the specific steps include the following:

[0102] (1) Oil displacement agent injection step: The oil displacement agent provided in this embodiment is injected into the target deep heavy oil reservoir using the injection well; wherein, the oil displacement agent injection amount is 0.3PV, the injection rate is 250t / day, and the injection period is 30 days; wherein, the production well maintains production status, and the production well group produces 6.5t / day.

[0103] When the oil displacement agent, formation water, and crude oil come into full contact, a high-viscosity water-in-oil emulsion is formed.

[0104] (2) Water injection steps: After step (1) is completed, water is injected into the target deep heavy oil reservoir using injection wells; the water injection rate is 200t / day, the continuous water injection time is 45 days, and the water injection volume is 0.45PV; the production wells maintain production status, and the well group production is 12t / day; the injection-production ratio is maintained at an average of 1.1.

[0105] (3) Alternate injection steps: repeat steps (1)-(2); after six months of production, the oil production of the well group can be increased to 13.8t / day.

[0106] The waterflooding-chemical slug extraction mode can effectively increase the daily oil production of well groups, improve development efficiency, extend the economically effective development period, and increase the ultimate recovery rate. Specifically, the average peak daily oil production of well groups can increase from 9 tons / day in pure waterflooding to 13.8 tons / day, and the ultimate recovery rate can be increased from 13% in waterflooding to 30%, which is economically beneficial for the development of deep heavy oil. The chemical formulation provided in this study is low-cost, has good development effects, and can effectively improve the problem of water channeling in waterflooding, making it suitable for large-scale promotion, testing, and application.

[0107] Experimental Example 1

[0108] In this experimental example, an indoor one-dimensional sand-filled pipe displacement experiment and an interfacial tension experiment were conducted to test the performance of the oil displacement agent.

[0109] Indoor one-dimensional sand-filled pipe displacement experiment:

[0110] Experiment 1:

[0111] Utilize Figure 1 The sand-filled pipe displacement experimental setup shown was used for indoor one-dimensional sand-filled pipe displacement experiments, specifically including:

[0112] 1) Saturate oil into a one-dimensional sand-packed pipe with a permeability of 10D;

[0113] 2) The confining pressure is controlled at 2MPa and the temperature is controlled at 50℃. Water drive is performed by injecting 1PV of formation water into the one-dimensional sand-filled pipe at a flow rate of 0.5ml / min.

[0114] 3) Utilizing the waterflooding method for deep heavy oil reservoirs provided by this invention to develop the remaining oil in the one-dimensional sand-packed pipe after waterflooding in step 2); specifically including:

[0115] A. Oil displacement agent injection step: After step A is completed, the oil displacement agent provided in Example 1 is injected into the one-dimensional sand-filled tube; wherein, the oil displacement agent injection volume is 1PV and the injection rate is 0.5ml / min;

[0116] B. Water Injection Step: After step B is completed, inject 1 PV of formation water into the one-dimensional sand-filled pipe at a rate of 0.5 ml / min.

[0117] C. Alternate injection steps: Repeat steps A-B for 2 rounds.

[0118] Experiment 2:

[0119] The difference between Experiment 2 and Experiment 1 is that the oil displacement agent used is the one provided in Example 2, rather than the one provided in Example 1.

[0120] Experiment 3:

[0121] The only difference between Experiment 3 and Experiment 1 is step 3). In Experiment 3, step 3) involves injecting the remaining oil in the one-dimensional sand-filled pipe after water flooding in step 2) into formation water at a rate of 0.5 ml / min until the water content of the produced fluid reaches more than 80%.

[0122] The results are as follows Figure 2 As shown, by Figure 2 It is known that by using the oil displacement agent provided by this invention in conjunction with the water flooding extraction method provided by this invention, the displacement efficiency can be increased from 25% in conventional water flooding to over 70%.

[0123] Interfacial tension experiment:

[0124] To prepare test solutions of different concentrations, specifically, the oil displacement agent mother liquor was prepared according to the method in Example 2. The oil displacement agent mother liquor was diluted with mineralized water corresponding to the reservoir to obtain the test solutions. The mass fractions of the oil displacement agent mother liquor were 0.0625 wt%, 0.125 wt%, and 0.25 wt%, respectively, based on the total mass of the test solutions as 100%.

[0125] Utilize Figure 3 The interfacial tension measuring device shown is used to test the interfacial tension of water and various solutions to be tested. Specifically, the experiments include:

[0126] (1) Clean the high-temperature and high-pressure IFT chamber. If the instrument has not been used for a long time, it needs to be calibrated. (2) Preheat the high-temperature and high-pressure IFT chamber to 60°C. (3) Install the oil droplet injection needle from the bottom of the chamber. (4) Fill the chamber with the sample to be tested. (5) Wait for the pressure in the chamber to stabilize at 2MPa and the temperature to stabilize at 60°C. (6) Slowly inject oil droplets into the chamber. (7) Fill in the required parameters in the DROPimage Advanced software and start the interfacial tension measurement. (8) Clean the high-temperature and high-pressure IFT chamber and measure the next sample.

[0127] The results are as follows Figure 5 As shown, the interfacial tension side view of water and the test solution with a concentration of 0.125% is as follows. Figure 4A , Figure 4B As shown. By Figure 5 It is known that the interfacial tension of water is 22.7 mN / m, while the interfacial tension of the test solution with a concentration of 0.125% is 4.8 mN / m. The 0.125% test solution reduces the interfacial tension by 78.9% compared to water. The oil displacement agent provided by this invention has a higher concentration than the 0.125% test solution, resulting in an even lower interfacial tension, reducing the interfacial tension by 85-90% compared to water.

Claims

1. A waterflooding method for deep heavy oil reservoirs, the method comprising: Oil displacement agent injection step: Injecting an oil displacement agent into a deep heavy oil reservoir; wherein the oil displacement agent comprises a eutectic solvent and a nanoparticle stabilizer; the mass ratio of the nanoparticle stabilizer to the eutectic solvent in the oil displacement agent is 1:2 to 2:3; based on the total mass of the oil displacement agent as 100%, the mass fraction of the eutectic solvent in the oil displacement agent is 1.5%-3.5%; wherein, after the oil displacement agent, formation water, and crude oil come into contact, a water-in-oil emulsion is formed; Water injection procedure: Water is injected into the deep heavy oil reservoir after the oil displacement agent is injected.

2. The method according to claim 1, wherein, The nanoparticle stabilizer includes SiO2 nanoparticles and / or nanoclay particles.

3. The method according to claim 1 or 2, wherein, The hydrogen bond acceptor compound in the eutectic solvent includes choline chloride; the hydrogen bond donor compound in the eutectic solvent includes sodium bicarbonate, carbamide, or glycerol.

4. The method according to claim 1 or 2, wherein, The oil displacement agent contains a eutectic solvent in which the molar ratio of hydrogen bond acceptor compound to hydrogen bond donor compound is 1:1 to 1:

2.

5. The method according to claim 1 or 2, wherein, The eutectic solvent is composed of hydrogen bond acceptor compounds and hydrogen bond donor compounds.

6. The method according to claim 1, wherein, The oil displacement agent is prepared by the following method: Preparation of eutectic solvents; Adding a nanoparticle stabilizer to a eutectic solvent yields an oil displacement agent mother liquor; The oil displacement agent is obtained by diluting the mother liquor of the oil displacement agent.

7. The method according to claim 1, wherein, The method includes: Gas injection procedure: Gas is injected into the deep heavy oil reservoir before the oil displacement agent is injected.

8. The method according to claim 7, wherein, The method includes: Gas injection procedure: Injecting gas into deep heavy oil reservoirs; Oil displacement agent injection step: After gas injection, the oil displacement agent is injected into the deep heavy oil reservoir; Water injection procedure: Water is injected into the deep heavy oil reservoir after the oil displacement agent is injected; Alternating injection steps: repeating gas injection step - water injection step.

9. The method according to claim 7 or 8, wherein, While injecting gas into deep heavy oil reservoirs, production wells are used for production.

10. The method according to any one of claims 1, 7, and 8, wherein, While injecting the aforementioned oil displacement agent into deep heavy oil reservoirs, production is carried out using production wells.

11. The method according to claim 8, wherein, While injecting water into deep heavy oil reservoirs, production wells are used for production.

12. The method according to claim 11, wherein, In the water injection step, the injection-to-production ratio is 0.9-1.

1.

13. The method according to any one of claims 1, 7, and 8, wherein, In the oil displacement agent injection step, the injection amount of the oil displacement agent is 0.05-0.1 PV; In the water injection step, the amount of water injected is 0.05-0.2 PV.

14. The method according to claim 7 or 8, wherein, In the gas injection step, the gas is methane gas.

15. The method according to claim 14, wherein, In the gas injection step, the amount of methane gas injected is 0.1-0.2 PV.

16. The method according to any one of claims 1, 7, and 8, wherein, In the oil displacement agent injection step, the injection rate of the oil displacement agent is 100-300 tons / day.

17. The method according to any one of claims 1, 7, and 8, wherein, The well spacing between injection and production in the deep heavy oil reservoir is 100-200 meters; The water cut of the deep heavy oil reservoir is not less than 70%.

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