Emulsion oil-displacing agent and method for improving recovery efficiency of heavy oil reservoir

Abstract

The invention provides an emulsified oil-displacing agent and a method for improving the recovery efficiency of a heavy oil reservoir. The emulsified oil-displacing agent comprises water-soluble carbonate, choline chloride and urea in a molar ratio of 1: 2: 1. The method for improving the recovery efficiency comprises the steps that gas 0.1-0.2 PV is injected into a reservoir through an injection well in an injection-production well pattern of a target oil reservoir; after gas injection is completed, the 0.05-0.2 PV emulsified oil-displacing agent is continuously injected into the reservoir stratum through the injection well, and the concentration of the total mass of the water-soluble carbonate, choline chloride and urea is not lower than 0.5% on the basis that the total mass of the oil-displacing agent is 100%; and after injection of the emulsified oil-displacing agent is completed, hot water with the temperature of 50-80 DEG C and the pressure of 0.1-0.3 PV is continuously injected into the reservoir stratum through the injection well. According to the technical scheme, in-situ profile control and displacement of the remaining oil of the heavy oil reservoir entering the later stage of steam flooding can be effectively achieved, the longitudinal swept volume is increased, and the recovery efficiency is improved.

Description

Technical Field

[0001] The invention belongs to the technical field of oil field production, and in particular relates to an emulsified oil displacement agent suitable for heavy oil reservoirs that have undergone steam flooding development and a method for improving the recovery rate of heavy oil reservoirs. Background Art

[0002] At present, heavy oil reservoirs are mainly developed through thermal recovery technology. Existing thermal recovery technologies mainly include steam stimulation, steam drive, steam-assisted gravity drainage and fire drive. Steam drive technology is the earliest replacement technology after steam stimulation development of heavy oil reservoirs. So far, 80% of thermal recovery heavy oil production comes from steam drive heavy oil production. During the steam drive development of heavy oil reservoirs, when the instantaneous oil-gas ratio reaches the economic limit, it is usually necessary to end steam drive and switch to other production methods. Once the steam drive development of heavy oil reservoirs enters the late stage, it usually has problems such as low oil-gas ratio, severe steam channeling, high water content, continuous decline in production, and poor benefits due to heterogeneity and steam overburden. How to expand the swept volume, improve displacement efficiency, and maintain stable production in heavy oil reservoirs entering the late stage of steam drive is an urgent problem to be solved.

[0003] In order to solve the problems existing in the late stage of steam flooding development of heavy oil reservoirs, multi-media assisted steam flooding technology and steam flooding profile control technologies such as gas foam and high-temperature gel have been proposed. 2 The development effect can be regulated by adjusting the gas-steam ratio. For example, a steam-driven profile control agent that can withstand a high temperature of 200°C is injected with steam to adjust the formation profile, so as to alleviate the problem of large pores between injection and production wells caused by steam drive affecting the swept volume. However, these methods usually have problems such as limited improvement in development effect and difficulty in field application.

[0004] In summary, there is still a need to study the heavy oil reservoir steam flooding development succession technology that is suitable for the later field application of heavy oil reservoir steam flooding and can effectively improve the development effect. Summary of the invention

[0005] The purpose of the present invention is to provide a technical solution that can effectively improve the recovery rate of heavy oil reservoirs that have undergone steam flooding. In order to achieve the above purpose, the present invention proposes the following three technical solutions.

[0006] In a first aspect, the present invention provides an emulsified oil-displacing agent, wherein the emulsified oil-displacing agent comprises a water-soluble carbonate, choline chloride and urea (ie, carbamide) in a molar ratio of 1:2:1-1:2:2.

[0007] The emulsified oil displacement agent provided by the present invention is suitable for emulsified oil displacement in heavy oil reservoirs, especially heavy oil reservoirs that have undergone steam flooding development. After being injected into the reservoir stratum of the heavy oil reservoir, the heavy oil can be emulsified to form a water-in-oil emulsion under reservoir conditions under the joint action of water-soluble carbonate, choline chloride and urea, laying a foundation for effectively improving the recovery rate of the heavy oil reservoir that has undergone steam flooding development.

[0008] According to a preferred embodiment of the first aspect, the water-soluble carbonate is sodium carbonate and / or sodium bicarbonate.

[0009] According to a preferred embodiment of the first aspect, the emulsified oil displacement agent preferably includes a solid phase particle stabilizer;

[0010] More preferably, the solid phase particle stabilizer may include, but is not limited to, silicon dioxide particles and / or clay particles (aluminum silicate);

[0011] More preferably, the particle size of the solid phase particle stabilizer is <2 μm; further preferably, the particle size of the solid phase particle stabilizer is 55 nm-2 μm;

[0012] More preferably, the mass ratio of the solid phase particle stabilizer to the chemical solution is between 2:3 and 3:4.

[0013] According to a preferred embodiment of the first aspect, the emulsified oil-displacing agent preferably includes solvent water; more preferably, based on the total mass of the oil-displacing agent being 100%, the total mass concentration of the water-soluble carbonate, choline chloride and urea is not less than 0.5%;

[0014] Further preferably, the total mass concentration of the water-soluble carbonate, choline chloride and urea is 0.5%-2%.

[0015] In a second aspect, the present invention provides a method for preparing the emulsified oil-displacing agent provided in the first aspect, wherein the method comprises: uniformly mixing the components contained in the emulsified oil-displacing agent to obtain the emulsified oil-displacing agent.

[0016] According to a preferred embodiment of the third aspect, the method comprises: mixing a carbonate aqueous solution having a water-soluble carbonate mass concentration of 65%-70%, a choline chloride aqueous solution having a choline chloride mass concentration of 65%-70% and a urea solution having a urea mass concentration of 65%-70% at 80°C in a ratio of 1:2:1 of water-soluble carbonate, choline chloride and urea; optionally adding a solid phase particle stabilizer to the mixed solution and stirring and mixing; obtaining an emulsified oil displacement agent mother liquor; and then diluting the emulsified oil displacement agent mother liquor with formation water according to on-site requirements to a concentration that is economically feasible and effective on-site to obtain an emulsified oil displacement agent, wherein the formation water (mineralized water) is used.

[0017] In a third aspect, the present invention further provides a method for improving the recovery of heavy oil reservoirs, wherein the method comprises:

[0018] Gas injection step: inject 0.1-0.2PV of gas into the reservoir using the injection wells in the injection-production well network of the target oil reservoir, and simultaneously produce using the production wells in the injection-production well network;

[0019] Emulsified oil displacement agent injection step: after completing the gas injection step, continue to inject 0.05-0.2PV of the emulsified oil displacement agent provided in the first aspect into the reservoir using the injection well, and simultaneously use the production wells in the injection-production well network to produce the emulsified oil displacement agent; wherein, based on the total mass of the oil displacement agent being 100%, the total mass concentration of the water-soluble carbonate, choline chloride and urea is not less than 0.5%;

[0020] Hot water injection step: After the emulsified oil displacement agent injection step is completed, 0.1-0.3PV of hot water at 50-80°C is continuously injected into the reservoir using the injection well, and production is carried out using the production wells in the injection-production well network while the hot water is injected.

[0021] The method for improving the recovery rate of heavy oil reservoirs provided by the present invention injects gas, emulsified oil displacement agent and hot water in a plug-type manner for displacement. The gas injected into the reservoir can replenish the formation pressure deficit to achieve energy replenishment, reduce the viscosity of crude oil, and increase the displacement fluidity to make the heavy oil easier to be displaced, laying a foundation for subsequent displacement. After the gas injection, the emulsified oil displacement agent is injected, and after the emulsified oil displacement agent is injected, the hot water is injected to form four zones of water-water-in-oil emulsion-gas-oil. The emulsified oil displacement agent contacts the underground crude oil and emulsifies to form an oil-in-water emulsion (the asphaltene contained in the heavy oil during the emulsification process will promote the formation of the oil-in-water emulsion to a certain extent), and the viscosity increases to 3-5 times or even more than the viscosity of the formation crude oil. The emulsified viscosity increases the effect of adjusting the profile, realizes the blocking of high permeability channels, reduces the degree of fingering and tongue advancement in the subsequent hot water flooding process of heavy oil, thereby controlling the water channeling phenomenon, expanding the longitudinal swept volume, and then improving the recovery degree of heavy oil.

[0022] According to a preferred embodiment of the third aspect, the method comprises:

[0023] The gas injection step, the emulsified oil displacement agent injection step, and the hot water injection step are repeated to achieve repeated and alternating injection of gas, emulsified oil displacement agent, and hot water in plug-like manner.

[0024] According to a preferred embodiment of the third aspect, the gas may include but is not limited to methane, nitrogen, CO 2 and flue gas, one or a combination of two or more.

[0025] According to a preferred embodiment of the third aspect, the injection rate of gas during the gas injection process is 10,000-20,000 cubic meters per day.

[0026] According to a preferred embodiment of the third aspect, the injection rate of the emulsified oil-displacing agent during the injection process is 20-40 tons / day.

[0027] According to a preferred embodiment of the third aspect, the step of injecting the emulsified oil displacement agent further comprises: after injecting the emulsified oil displacement agent provided in the first aspect, shutting down the well;

[0028] Preferably, the stewing time is not less than 1 day.

[0029] According to the preferred implementation of the third aspect, the injection-production ratio during hot water injection is 0.9-1.1; controlling the injection-production ratio at 0.9-1.1 helps to ensure pressure stability, and the water injection rate is not too fast to avoid serious water channeling. After the oil well is effective, liquid extraction can be appropriately carried out.

[0030] According to a preferred embodiment of the third aspect, the target oil reservoir is a heavy oil reservoir that has undergone steam flooding development;

[0031] More preferably, the injection-production well pattern is a steam drive well pattern used in steam drive development;

[0032] After the steam in a heavy oil reservoir that has undergone steam flooding is stopped, a certain amount of gas is first injected into the reservoir through the injection well, followed by a certain amount of chemical formula solution, and then hot water flooding is switched.

[0033] According to a preferred embodiment of the third aspect, the oil-gas ratio of the target reservoir is lower than 0.1 and the water content is higher than 90%;

[0034] According to a preferred implementation of the third aspect, the injection-production well spacing of the injection-production well network is 50-70m.

[0035] According to a preferred embodiment of the third aspect, the injection-production well network includes a vertical well-vertical well combination and / or a vertical well-horizontal well combination.

[0036] The technical solution provided by the present invention forms an emulsified oil displacement agent for the late stage of steam flooding and a method for improving oil recovery by combining gas, emulsified oil displacement agent and hot water, which can effectively achieve in-situ adjustment and displacement of the remaining oil in the heavy oil reservoir in the late stage of steam flooding, increase the vertical sweep volume and improve the recovery rate. Compared with the existing technology, it has the following excellent effects:

[0037] 1. The emulsified oil displacement agent provided by the present invention has excellent performance in reducing interfacial tension, changing wettability, emulsification stability and thermal stability: the emulsified oil displacement agent provided by the present invention can withstand high temperatures of 300-350°C, can reduce interfacial tension by 80-95% when in full contact with crude oil, and can form a stable water-in-oil emulsion with crude oil to increase the viscosity of crude oil by 3-5 times or even more, which can effectively change the wettability of the reservoir. The emulsified oil displacement agent provided by the present invention can achieve deep profile adjustment and improve oil displacement efficiency.

[0038] 2. The method for improving the recovery rate of heavy oil reservoirs provided by the present invention is an emulsified thickening hot water flooding method using gas, emulsified oil displacement agent, and hot water. This method can be well applied to heavy oil reservoirs entering the late stage of steam flooding. Under the high water content condition of heavy oil reservoirs in the late stage of steam flooding, it can still form four zones of water-water-in-oil emulsion-gas-oil by injecting gas, emulsified oil displacement agent, and hot water, thereby relying on the underground in-situ formation of water-in-oil emulsion to increase the viscosity of crude oil to play the role of profile adjustment and flooding to plug high-permeability pores, so that the subsequent water flooding swept volume is increased and the water channeling is reduced, so as to achieve the improvement of the recovery rate of heavy oil reservoirs entering the late stage of steam flooding. The method for improving the recovery rate of heavy oil reservoirs provided by the present invention is a replacement technology after steam flooding of heavy oil reservoirs, which can increase the recovery rate by more than 10 percentage points, and achieve a final recovery rate of 60%-70% and a longitudinal swept volume of 80%-90%.

[0039] 3. The method for improving the recovery rate of heavy oil reservoirs provided by the present invention is used for the development of heavy oil reservoirs entering the late stage of steam flooding, which has high economic benefits. The cost of injected reagents is low and the oil exchange rate is significantly increased compared with the late stage of steam flooding, which effectively solves the thorny problem of extremely low oil-gas ratio and non-profit development in the late stage of steam flooding of heavy oil reservoirs.

[0040] 4. The method for improving the recovery rate of heavy oil reservoirs provided by the present invention does not require steam injection, effectively reduces carbon emissions caused by heating to produce steam, and helps to achieve green transformation and development of heavy oil.

[0041] The method for improving the recovery rate of heavy oil reservoirs is a method for promoting emulsification and improving the development effect of heavy oil reservoirs. It can promote the emulsification of heavy oil in heavy oil reservoirs that have undergone steam development, improve the utilization degree of heavy oil reservoirs that have undergone steam development, and improve the steam utilization rate and development efficiency of heavy oil reservoirs that have undergone steam development, effectively improving the recovery rate and development effect of heavy oil reservoirs. Compared with the existing technology, it has the following advantages:

[0042] (1) The technical solution provided by the present invention takes into account the actual reservoir conditions of heavy oil reservoirs that have undergone steam development, and utilizes the continuous water phase near the wellbore after steam development, thereby improving the utilization rate of steam.

[0043] (2) The technical solution provided by the present invention combines the phase change of steam underground with emulsification to improve the recovery rate, greatly improving the efficiency of the entire process and reducing operating costs.

[0044] (3) The technical solution provided by the present invention re-gasifies the stored water near the wellbore to form a steam plug and pushes it into the deep of the reservoir, effectively expanding the scope of utilization. At the same time, the injected non-condensable gas and the steam plug cooperate to increase the elastic energy of the formation, increase the swept volume and increase the oil production rate.

[0045] (4) The technical solution provided by the present invention can be used to extend the steam development cycle. Compared with conventional steam development, the oil production rate can be increased by about 25%, the cost per ton of oil can be reduced by more than 20%, and the overall recovery rate of heavy oil reservoirs can reach about 70%. BRIEF DESCRIPTION OF THE DRAWINGS

[0046] Figure 1 This is the flow chart of the core flooding experimental device.

[0047] Figure 2 This is a diagram showing the recovery effect of the chemical core flooding experiment.

[0048] Figure 3 Flowchart for interfacial tension and contact angle measurements

[0049] Figure 4 This is a graph showing the measurement of water interfacial tension.

[0050] Figure 5 This is the interfacial tension measurement diagram of the oil displacement agent with a concentration of 1.25%.

[0051] Figure 6 This is a diagram showing the changes in interfacial tension and contact angle of the oil phase.

[0052] Figure 7 Test results for thermal stability evaluation of chemical agents

[0053] Figure 8 This is a graph of viscosity change. DETAILED DESCRIPTION

[0054] In order to make the purpose, technical solution and advantages of the embodiment of the present invention clearer, the technical solution in the embodiment of the present invention will be clearly and completely described below in conjunction with the drawings in the embodiment of the present invention. Obviously, the described embodiment is a part of the embodiment of the present invention, not all of the embodiments. Based on the embodiment of the present invention, all other embodiments obtained by ordinary technicians in this field without making creative work belong to the protection scope of the present invention.

[0055] In the late stage of steam flooding development of heavy oil reservoirs, problems such as severe steam channeling, many high permeability pores, and high water content are usually shown, which makes the oil-gas ratio approach the economic limit, resulting in poor benefits of steam injection development. In order to effectively improve the recovery of heavy oil reservoirs that have undergone steam flooding development, the present invention provides an emulsified oil displacement agent that can emulsify the heavy oil under reservoir conditions to form an oil-in-water emulsion after being injected into the reservoir of the heavy oil reservoir in the late stage of steam flooding, and a method for improving the recovery of heavy oil reservoirs that can effectively adjust the flooding of heavy oil reservoirs in the late stage of steam flooding and increase the swept volume.

[0056] A specific embodiment of the present invention provides an emulsified oil-displacing agent, wherein the emulsified oil-displacing agent comprises a water-soluble carbonate, choline chloride and urea (ie, carbamide) in a molar ratio of 1:2:1-2.

[0057] Furthermore, the water-soluble carbonate is sodium carbonate and / or sodium bicarbonate.

[0058] Furthermore, the emulsified oil displacement agent further includes a solid phase particle stabilizer; for example, SiO 2 Particles and / or clay particles. The mass ratio of the solid phase particle stabilizer to the chemical agent is preferably 2-3:3-4. The particle size of the solid phase particle stabilizer is preferably <2μm, more preferably 55nm-2μm;

[0059] Furthermore, the emulsified oil displacement agent further comprises solvent water. Wherein, based on the total mass of the oil agent as 100%, the total mass concentration of the water-soluble carbonate, choline chloride and urea is preferably not less than 0.5%, more preferably 0.5%-2%.

[0060] The emulsified oil-displacing agent provided in the above specific embodiment of the present invention can be prepared by the following method: the components contained in the emulsified oil-displacing agent are mixed uniformly to obtain the emulsified oil-displacing agent.

[0061] For example: at 80° C., a carbonate aqueous solution with a water-soluble carbonate mass concentration of 65%-70%, a choline chloride aqueous solution with a choline chloride mass concentration of 65%-70%, and a urea solution with a urea mass concentration of 65%-70% are mixed in a ratio of 1:2:1 of water-soluble carbonate, choline chloride and urea; a solid phase particle stabilizer is optionally added to the mixed solution and stirred to mix; an emulsified oil displacement agent mother liquor is obtained; and then the emulsified oil displacement agent mother liquor is diluted with formation water according to on-site needs to a concentration that is economically feasible and effective on-site, to obtain an emulsified oil displacement agent, wherein the formation water (mineralized water) is used.

[0062] The emulsified oil displacement agent provided in the above specific embodiment of the present invention, after being injected into a heavy oil reservoir (including a heavy oil reservoir that has undergone steam flooding development), contacts with the heavy oil under reservoir conditions to achieve heavy oil emulsification, and further forms an oil-in-water emulsion with the assistance of asphaltenes in the heavy oil. The asphaltenes contained in the heavy oil are a naturally occurring catalyst that can promote the transformation of the water-in-oil emulsion into the oil-in-water emulsion, achieving an effect of dynamic emulsification diversion.

[0063] A specific embodiment of the present invention provides a method for improving the recovery of heavy oil reservoirs, wherein the method comprises:

[0064] Step S1: injecting 0.1-0.2 PV of gas into the reservoir using the injection wells in the injection-production well network of the target oil reservoir, and producing using the production wells in the injection-production well network at the same time of gas injection;

[0065] Step S2: After completing step S1, the injection well is used to continue injecting 0.05-0.2 PV of the emulsified oil displacement agent provided in the first aspect into the reservoir, and the production is carried out using the production wells in the injection-production well network while the emulsified oil displacement agent is emulsified; wherein, based on the total mass of the oil displacement agent being 100%, the total mass concentration of the water-soluble carbonate, choline chloride and urea is not less than 0.5%;

[0066] Step S3: After completing step S2, continue to inject 0.1-0.3PV of hot water at 50-80°C into the reservoir using the injection well, and while injecting hot water, use the production wells in the injection-production well network for production.

[0067] When this method is used to develop heavy oil reservoirs that have undergone steam flooding, after the steam is stopped, a certain amount of gas is first injected into the reservoir through the injection well to replenish the formation pressure deficit after the steam is stopped, while reducing the viscosity of the crude oil in the front section, increasing the displacement start-up fluidity, and making the heavy oil easier to be displaced. Then a certain amount of emulsified oil displacement agent is injected, and the emulsified oil displacement agent contacts the underground crude oil and emulsifies in situ to form an oil-in-water emulsion, and the viscosity increases to 3-5 times or even more than the viscosity of the formation crude oil. Then it is switched to hot water flooding. At this time, the underground oil reservoir will form four zones of water-oil-in-water emulsion-gas-oil. Under the mutual cooperation of hot water, oil-in-water emulsion, and gas, a stable displacement zone is formed, which effectively increases the swept volume of water flooding, reduces the degree of fingering and tongue advancement, and improves the overall oil recovery efficiency.

[0068] Furthermore, the method comprises: repeating step S1, step S2 and step S3, so as to achieve repeated injection of gas, emulsified oil displacement agent and hot water in a plug-like manner.

[0069] Furthermore, the gas may include, but is not limited to, methane, nitrogen, CO 2 and flue gas, one or a combination of two or more.

[0070] Furthermore, the injection speed of the gas during the gas injection process is.

[0071] Furthermore, the injection rate of the emulsified oil displacement agent is 20-40 tons / day.

[0072] Furthermore, step S2 also includes: after the injection of the emulsified oil displacement agent, the well is kept warm. The time of keeping warm is preferably not less than 1 day, which is more conducive to the emulsified oil displacement agent to fully contact with the underground crude oil to form an oil-in-water emulsion by in-situ emulsification.

[0073] Furthermore, during the hot water injection process, the injection-production ratio is 0.9-1.1; controlling the injection-production ratio at 0.9-1.1 helps to ensure pressure stability, and the water injection speed is not easy to be too fast to avoid serious water breakthrough. After the oil well is effective, liquid extraction can be appropriately carried out.

[0074] Furthermore, the target oil reservoir is a heavy oil reservoir that has undergone steam flooding development; further, the injection-production well pattern is a steam flooding well pattern used in steam flooding development.

[0075] Furthermore, the oil-gas ratio of the target reservoir is lower than 0.1, and the water content is higher than 90%.

[0076] Furthermore, the injection-production well spacing of the injection-production well network is 50-70m.

[0077] Furthermore, the injection-production well pattern includes a vertical well-vertical well combination and / or a vertical well-horizontal well combination.

[0078] Example 1

[0079] This embodiment provides an emulsified oil displacement agent and a method for improving the recovery rate of a heavy oil reservoir.

[0080] The emulsified oil displacement agent provided in this embodiment is prepared by the following method:

[0081] At 80° C., a sodium carbonate aqueous solution with a sodium carbonate mass concentration of 65%, a choline chloride aqueous solution with a choline chloride mass concentration of 65%, and a urea solution with a urea mass concentration of 65% are mixed in a ratio of water-soluble carbonate, choline chloride and urea of ​​1:2:1 to obtain a mixed solution;

[0082] Add 100 nm SiO2 solid phase stabilizer to the mixture. 2 The particles are stirred and mixed to obtain an emulsified oil displacement agent mother solution, wherein the mass ratio of the solid phase particle stabilizer to the mixed solution is 2:3;

[0083] The emulsified oil displacement agent mother solution is then diluted with water to a total mass concentration of carbonate, choline chloride and urea of ​​1% to obtain an emulsified oil displacement agent.

[0084] The method for improving the recovery rate of a heavy oil reservoir provided by the present invention is used for developing an A oil reservoir.

[0085] Reservoir A is a heavy oil reservoir that has entered the late stage of steam flooding development. The reservoir temperature of Reservoir A is 20°C, and the crude oil viscosity under formation conditions is 15000mPa·s. Reservoir A is a set of braided river delta front deposits with an average porosity of 31.3% and an average permeability of 2.524μm 2 , the average oil saturation is 78%, and the average effective thickness of the reservoir is 20m. Reservoir A is developed using an inverse nine-point area well pattern (vertical well-vertical well combination), with an injection-production well spacing of 50m, a water content of 94%, and an oil-gas ratio of 0.07. It is severely affected by vertical heterogeneity, and some layers have been ineffectively steam-circulated, and the swept volume cannot be increased. Steam is seen in production wells, and the steam cavity expansion is poor. The current recovery rate is 43%. Due to severe steam channeling, it is no longer possible to effectively mine normally.

[0086] The method for improving the recovery rate of heavy oil reservoirs provided by the present invention comprises:

[0087] 1. Stop steam injection and use the injection wells in the existing injection-production well network of reservoir A to inject 0.15 PV of nitrogen into the reservoir. The steam injection rate is 10,000 cubic meters per day and the injection cycle is 5 days. Among them, the production wells are in normal production and the injection-production ratio is controlled at 1.1;

[0088] 2. After completing step 1, 1000 t of the emulsified oil displacement agent provided in this embodiment, i.e., 0.1 PV, is continuously injected into the reservoir through the injection well, with an injection rate of 200 t / day and an injection cycle of 5 days; wherein, the production well is in normal production, and the injection-production ratio is controlled at 1.1;

[0089] 3. After completing step 2, shut down the well for 1 day, during which the production well will be shut down;

[0090] 4. After completing step 3, continue to inject 2000t of hot water at 50°C into the reservoir through the injection well, i.e. 0.2PV, with an injection rate of 200t / day and an injection cycle of 10 days; the production well is in normal production, and the injection-production ratio is controlled at 1.1;

[0091] 5. Repeat steps 1, 2 and 3 to achieve repeated injection of gas, emulsified oil displacement agent and hot water in a plug-like manner.

[0092] Economic benefit analysis: Compared with continuing steam drive development (producing until the water content is greater than 98%, see Table 1 for forecast data), the development using the method provided in this embodiment can better solve the problem of poor utilization caused by severe steam channeling in the later stage of steam drive. The development using the method provided in this embodiment can achieve emulsification profile adjustment, increase the longitudinal swept volume, and improve the recovery rate. The development using the method provided in this embodiment, with zero steam injection, can reduce development costs and reduce carbon emissions. In short, the development using the method provided in this embodiment has low development costs and good development effects.

[0093] Table 1

[0094]

[0095] As can be seen from Table 1, if steam drive development is continued, the oil-gas ratio is only 0.033, which cannot be developed economically and effectively. At the same time, saving steam injection can greatly reduce carbon emissions. However, the method provided in this embodiment can be used for development to increase the recovery rate by 15.3%.

[0096] Example 2

[0097] This embodiment provides an emulsified oil displacement agent and a method for improving the recovery rate of a heavy oil reservoir.

[0098] The emulsified oil displacement agent provided in this embodiment is prepared by the following method:

[0099] At 80° C., a sodium carbonate aqueous solution with a sodium carbonate mass concentration of 65%, a choline chloride aqueous solution with a choline chloride mass concentration of 65%, and a urea solution with a urea mass concentration of 65% are mixed in a ratio of water-soluble carbonate, choline chloride and urea of ​​1:2:1 to obtain a mixed solution;

[0100] Adding 1 μm clay particles as a solid-phase particle stabilizer to the mixed solution and stirring and mixing, to obtain an emulsified oil displacement agent mother solution; wherein the mass ratio of the solid-phase particle stabilizer to the mixed solution is preferably 3:4;

[0101] The emulsified oil displacement agent mother solution is then diluted with water to a total mass concentration of carbonate, choline chloride and urea of ​​1.5% to obtain an emulsified oil displacement agent.

[0102] The method for improving the recovery rate of a heavy oil reservoir provided by the present invention is used for developing a B oil reservoir.

[0103] Reservoir B is a heavy oil reservoir that has entered the late stage of steam flooding development. The reservoir temperature of Reservoir B is 36.8℃, and the crude oil viscosity under formation conditions is 3000cp. The average porosity of Reservoir B is 31.5%, and the average permeability is 2.1μm 2, the average oil saturation is 75%, and the average effective thickness of the reservoir is 35m. The B reservoir is developed using a vertical well-horizontal well pattern (one horizontal production well, corresponding to six vertical well injection wells, 210m horizontal wells, and 35m vertical-horizontal well spacing), with a water content of 90% and an oil-gas ratio of 0.1. The steam drive efficiency of the B reservoir is poor, the production wells have obvious steam, and the steam cavity expansion is poor. The current recovery rate is 45.7%. Due to severe steam channeling, it can no longer be effectively mined.

[0104] The method for improving the recovery rate of heavy oil reservoirs provided by the present invention comprises:

[0105] 1. Stop steam injection and use the injection wells in the existing injection-production well network of reservoir B to inject 0.15 PV of methane gas into the reservoir at a rate of 12,000 cubic meters per day. Among them, the production wells are in normal production, and the injection-production ratio is controlled at 1.0;

[0106] 2. After completing step 1, 1470 tons of the emulsified oil displacement agent provided in this embodiment, i.e., 0.05 PV, are continuously injected into the reservoir through the injection well, with an injection rate of 210 tons / day (the injection rate of each vertical well is 70 tons / day), and an injection cycle of 7 days; wherein, the production well is in normal production, and the injection-production ratio is controlled at 1.0;

[0107] 3. After completing step 2, the well is shut down for 2 days, during which the production well is shut down;

[0108] 4. After completing step 3, continue to inject 2940 tons of hot water at 80°C into the reservoir through the injection well, i.e. 0.1PV, with an injection rate of 210 tons / day and an injection cycle of 14 days; the production well is in normal production, and the injection-production ratio is controlled at 1.0;

[0109] 5. Repeat steps 1, 2 and 3 to achieve repeated injection of gas, emulsified oil displacement agent and hot water in a plug-like manner.

[0110] Economic benefit analysis: Compared with continuing steam drive development (producing until the water content is greater than 98%, see Table 2 for forecast data), the development using the method provided in this embodiment can better solve the problem of poor utilization caused by severe steam channeling in the later stage of steam drive. The development using the method provided in this embodiment can achieve emulsification profile adjustment, increase the longitudinal swept volume, and improve the recovery rate. The development using the method provided in this embodiment, with zero steam injection, can reduce development costs and reduce carbon emissions. In short, the development using the method provided in this embodiment has low development costs and good development effects.

[0111] Table 2

[0112]

[0113] As shown in Table 2, if the steam drive development is continued, the oil-gas ratio is only 0.05, which is not economical and effective development; however, the development method provided in this embodiment can increase the recovery rate by 14.8%.

[0114] Example 3

[0115] This embodiment provides an emulsified oil-displacing agent.

[0116] The emulsified oil displacement agent provided in this embodiment is prepared by the following method:

[0117] At 80° C., a sodium carbonate aqueous solution with a sodium carbonate mass concentration of 65%, a choline chloride aqueous solution with a choline chloride mass concentration of 65%, and a urea solution with a urea mass concentration of 65% are mixed in a ratio of water-soluble carbonate, choline chloride and urea of ​​1:2:1 to obtain a mixed solution;

[0118] Add 100 nm SiO2 solid phase stabilizer to the mixture. 2 The particles are stirred and mixed to obtain an emulsified oil displacement agent mother solution, wherein the mass ratio of the solid phase particle stabilizer to the mixed solution is 2:3;

[0119] The emulsified oil displacement agent mother solution is then diluted with water to a total mass concentration of carbonate, choline chloride and urea of ​​1.25% to obtain an emulsified oil displacement agent.

[0120] The indoor performance evaluation of the emulsified oil displacement agent provided in this embodiment specifically includes:

[0121] Performance evaluation 1 (core displacement experiment):

[0122] Use Figure 1 The device shown in the figure is carried out, and the specific steps include:

[0123] a) Saturate the core with a permeability of 10D with oil; the confining pressure is controlled at 2MPa and the temperature is controlled at 20℃; the oil used in this experiment is dehydrated crude oil from a certain block, and the viscosity of the crude oil at 20℃ is 14150mpa.s;

[0124] b) Inject the emulsified oil displacement agent provided in this embodiment at a driving speed of 0.5 ml / min, displace 0.5 PV at a constant speed, and simultaneously record the time, oil production, liquid production, inlet and outlet pressures, pressure difference and temperature parameters.

[0125] c) After step b), water injection was used with a driving speed of 0.5 ml / min and a constant displacement rate of 1 PV; wherein the experimental water was simulated water with the same properties as the formation water in a block of the reservoir.

[0126] d) After step c), the emulsified oil displacement agent provided in this embodiment was injected at a rate of 0.5 ml / min and a constant displacement rate of 0.5 PV, and the time, oil production, liquid production, inlet and outlet pressures, pressure difference and temperature parameters were recorded at the same time.

[0127] e) After step d), water injection was used for displacement, with a driving speed of 0.5 ml / min and a constant displacement speed of 0.5 PV.

[0128] Among them, the records were encrypted at the initial stage of water breakthrough. As the oil production continued to decrease, the recording time interval was gradually lengthened. The experiment was ended when the water content reached more than 99.5% and the pressure difference was stable.

[0129] The results are as follows Figure 2 shown.

[0130] Performance evaluation 2 (interfacial tension (contact angle) test experiment):

[0131] Use Figure 3 The device shown in the figure is carried out, and the specific steps include:

[0132] 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;

[0133] 2) Preheat the high temperature and high pressure IFT chamber to 60°C;

[0134] 3) Install the needle for oil injection from the bottom of the cavity;

[0135] 4) Filling the cavity with the emulsified oil displacement agent or water provided in this embodiment;

[0136] 5) Wait for the pressure in the cavity to stabilize at 2MPa and the temperature to stabilize at 60℃;

[0137] 6) Slowly inject oil droplets into the cavity;

[0138] 7) Fill in the required parameters in the DROPimage Advanced software and start the interfacial tension (contact angle) measurement;

[0139] 6) Clean the high temperature and high pressure IFT chamber and proceed to measure the next concentration or chemical agent.

[0140] The results are as follows Figure 4-Figure 8 As shown, the interfacial tension of water is 22.7 mN / m, and that of the emulsified oil displacement agent provided in this embodiment is 3.1 mN / m.

Claims

1. An emulsified oil displacement agent, wherein: The emulsified oil displacement agent comprises water-soluble carbonate, choline chloride and urea in a molar ratio of 1:2:1-2.

2. The emulsified oil-displacing agent according to claim 1, wherein The water-soluble carbonate is selected from sodium carbonate and / or sodium bicarbonate.

3. The emulsified oil-displacing agent according to claim 1, wherein The emulsified oil displacement agent comprises a solid-phase particle stabilizer; wherein the ratio of the mass of the solid-phase particle stabilizer to the mass sum of the water-soluble carbonate, choline chloride and urea is 2-3:3-4.

4. The emulsified oil-displacing agent according to claim 3, wherein The solid phase particle stabilizer comprises SiO2 particles and / or clay particles; and / or The particle size of the solid phase particle stabilizer is less than 2 μm, preferably 55 nm-2 μm.

5. The emulsified oil-displacing agent according to any one of claims 1 to 4, wherein The emulsified oil-displacing agent preferably includes solvent water; based on the total mass of the oil-displacing agent being 100%, the total mass concentration of the water-soluble carbonate, choline chloride and urea is not less than 0.5%.

6. The emulsified oil-displacing agent according to claim 5, wherein The total mass concentration of the water-soluble carbonate, choline chloride and urea is 0.5%-2%.

7. A method for improving the recovery of heavy oil reservoirs, wherein: The method includes: Gas injection step: inject 0.1-0.2PV of gas into the reservoir using the injection wells in the injection-production well network of the target oil reservoir, and simultaneously produce using the production wells in the injection-production well network; Emulsified oil displacement agent injection step: after completing the gas injection step, continue to inject 0.05-0.2PV of the emulsified oil displacement agent according to any one of claims 1 to 6 into the reservoir using the injection well, and simultaneously use the production wells in the injection-production well network to produce the emulsified oil displacement agent; wherein, based on the total mass of the oil displacement agent as 100%, the total mass concentration of the water-soluble carbonate, choline chloride and urea is not less than 0.5%; Hot water injection step: After the emulsified oil displacement agent injection step is completed, 0.1-0.3PV of hot water at 50-80°C is continuously injected into the reservoir using the injection well, and production is carried out using the production wells in the injection-production well network while the hot water is injected.

8. The method according to claim 7, wherein: The method includes: The gas injection step, the emulsified oil displacement agent injection step, and the hot water injection step are repeated to achieve repeated and alternating injection of gas, emulsified oil displacement agent, and hot water in plug-like manner.

9. The method according to claim 7 or 8, wherein: The gas injection rate during the gas injection process is 10,000-20,000 cubic meters per day; and / or During the emulsified oil displacement agent injection process, the injection rate of the emulsified oil displacement agent is 20-40 tons / day.

10. The method according to claim 7 or 8, wherein: The step of injecting the emulsified oil displacement agent also includes: shutting down the well after the injection of the emulsified oil displacement agent is completed; wherein the time of shutting down the well is not less than 1 day.

11. The method according to claim 7 or 8, wherein: The injection-production ratio during hot water injection is 0.9-1.

1.

12. The method according to claim 7 or 8, wherein: The target reservoir is a heavy oil reservoir that has undergone steam flooding development.

13. The method according to claim 7 or 8, wherein: The oil-gas ratio of the target reservoir is less than 0.1 and the water content is more than 90%.

14. The method according to claim 7 or 8, wherein: The injection-production well spacing of the injection-production well network is 50-70m.

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