CN110776899B - High-temperature high-salinity oil reservoir in-situ emulsification and viscosification system and application thereof - Google Patents
High-temperature high-salinity oil reservoir in-situ emulsification and viscosification system and application thereof Download PDFInfo
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- CN110776899B CN110776899B CN201911174244.0A CN201911174244A CN110776899B CN 110776899 B CN110776899 B CN 110776899B CN 201911174244 A CN201911174244 A CN 201911174244A CN 110776899 B CN110776899 B CN 110776899B
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Abstract
The invention discloses an in-situ emulsification and viscosification system for a high-temperature and high-salinity oil reservoir and application thereof, belonging to the technical field of oilfield chemistry ‑1 mN/m～10 ‑3 mN/m, under the shearing condition, crude oil can form W/O type emulsion with an injection system, the viscosity of the emulsion is increased along with the increase of the water content, the high-water-content area has large flow resistance, the low-water-content area has small flow resistance, and finally the balanced displacement is realized; the dispersed water drops effectively block the large pore roar through the Jamin effect, and the liquid flow is forced to turn; the system has good ageing resistance under the conditions of high temperature and high salinity, and the expanded swept volume can meet the requirement of improving the recovery ratio of the high-temperature and high-salinity oil reservoir.
Description
Technical Field
The invention relates to the technical field of oilfield chemistry, in particular to a high-temperature high-salinity reservoir in-situ emulsification and viscosification system and application thereof.
Background
At present, many oil fields enter a high water content development stage after water injection development for many years, and the oil field is more and more difficult to stabilize the yield. Meanwhile, with the increasing demand of crude oil, the contradiction between the supply and demand of crude oil is more and more intense. Thus, chemical flooding including polymer flooding, alkali water flooding, combination flooding (polymer/surfactant binary flooding and polymer/surfactant/alkali ternary combination flooding), surfactant flooding and foam flooding has been widely used.
However, for high-temperature and high-salinity oil reservoirs, due to the limitation of the temperature resistance of the polymer, polymer flooding, combination flooding and (polymer) enhanced foam flooding mainly based on fluidity control have poor long-term stability, short effective action time and poor oil reservoir adaptability under the high-temperature condition, and are only suitable for the conditions that the temperature is lower than 80 ℃ and the mineralization degree is lower than 10 multiplied by 10 4 mg/L of oil reservoir; although the alkali flooding is simple in operation and low in cost, the fingering phenomenon, alkali corrosion and alkali decomposition under high-temperature conditions in a high-permeability layer limit the applicability of the alkali flooding in high-temperature and high-salinity oil reservoirs. Because the reservoir hypertonic layer is washed by injected water for a long time in the water drive process, the reservoir heterogeneity is further enhanced, the surfactant with the main interface is reduced from entering the stratum and then flowing along the dominant channel, and finally the swept volume is small and the recovery ratio is low.
In order to solve the problem that the fluidity control and the reduction of interfacial tension are difficult to simultaneously realize in the process of improving the recovery ratio of a high-temperature and high-salinity oil reservoir, a scholars has proposed that the W/O type emulsion is used for displacing crude oil. The W/O type emulsion is a dynamic stable system with the viscosity larger than that of crude oil, and has two forming modes, 1) ground preparation and formation; 2) the reservoir is formed in situ. The ground preparation method requires a large amount of organic phase, is complex to operate and has high cost. Meanwhile, the emulsifier starts the residual oil of the reservoir by reducing the interfacial tension and then forms W/O type emulsion, thereby realizing the mobility control under the conditions of high temperature and high salt.
Based on the "phase volume theory" proposed by Ostward, if the dispersed phases are all of uniform size, the volume of spherical closest packed beads of any size can only account for 74.02% of the total volume. If the volume of the dispersed phase is greater than 74.02%, the emulsion will invert. At present, after most oil reservoirs are water-driven, the oil saturation of a high permeability layer is lower than 25%, the oil saturation of a low permeability layer is higher, if the phase change of an emulsion is not properly interfered, a W/O type emulsion is formed in the high permeability layer (a low oil saturation area), the viscosity of the emulsion is higher than that of crude oil, an O/W type emulsion is formed in the low permeability layer (a high oil saturation area), the viscosity of the emulsion is lower than that of the crude oil, and further, the oil reservoir development contradiction is aggravated. Therefore, the key is how to carry out in-situ emulsification, viscosity-increasing and oil displacement of the high-temperature and high-salt oil reservoir and carry out manual intervention on a phase change point, and the realization of balanced displacement of the high-temperature and high-salt oil reservoir under the heterogeneous condition.
Disclosure of Invention
In order to solve the problems, the invention aims to provide a high-temperature high-salinity reservoir in-situ emulsification and viscosification system, which can emulsify in situ in a reservoir to form a W/O emulsion, and the emulsion has the characteristics of stable kinetics and unstable thermodynamics, so that the emulsion is easy to break after crude oil is produced.
Another object of the present invention is to provide an emulsion system with manually adjustable phase transition point, which can achieve balanced displacement under different water-containing conditions.
In order to achieve the aim, the invention provides a high-temperature high-salinity reservoir in-situ emulsification and viscosification system which is composed of a nonionic surfactant with a low HLB value, an anionic-nonionic surfactant with a higher HLB value and a nanomaterial. The emulsifying capacity and the oil washing capacity of an emulsifying and tackifying system are adjusted by adjusting the proportion of the nonionic surfactant and the anionic-nonionic surfactant, and the phase transition point of the emulsion is intervened by adjusting the addition amount of the nano material. The composition of the system is as follows:
nonionic surfactant: 0.05 percent to 0.2 percent;
anionic-nonionic surfactant: 0.1 to 0.3 percent;
nano materials: 0.01 to 0.1 percent;
the other components are injection water, preferably, the mineralization degree of the injection water is 0-22 multiplied by 10 4 mg/L。
The structural formula of the nonionic surfactant is one of (I) or (II), and the specific structural formula is as follows:
the structural formula of the anionic-nonionic surfactant is as follows:
wherein n is the polymerization degree of polyoxyethylene ether, and n is more than or equal to 7 and less than or equal to 40
The nano material is at least one of gamma-aminopropyltriethoxysilane modified carbon nano tube, graphene and gamma- (methacryloyloxy) propyltrimethoxysilane modified nano silicon dioxide.
The invention has the following beneficial effects:
(1) the interfacial tension between the high-temperature high-salinity oil reservoir in-situ emulsification and viscosification system and the crude oil reaches 10 -1 mN/m～10 -3 mN/m, the oil washing efficiency can be improved by reducing the interfacial tension.
(2) Under the shearing condition, the crude oil and the injection system can form W/O type emulsion, the viscosity of the emulsion is increased along with the increase of the water content, the high-water-content area has high flow resistance, the low-water-content area has low flow resistance, and finally the balanced displacement is realized.
(3) The dispersed water drops effectively block the large pore roar through the Jamin effect to force the liquid flow to turn, the system has good ageing resistance under the conditions of high temperature and high salt, and the expanded swept volume can meet the requirement of improving the recovery ratio of the high temperature and high salt reservoir.
Drawings
FIG. 1 is a graph of oil displacement performance testing of the in-situ emulsification and viscosification system in example 1.
Detailed Description
The technical solutions of the present invention will be described in detail below in order to clearly understand the technical features, objects, and advantages of the present invention, but the present invention should not be construed as limiting the implementable scope of the present invention.
Example 1
Preparing an in-situ emulsification and tackifying system: adding the in-situ emulsification and viscosity increasing system into the injection water under the stirring condition (500r/min) until the system isThe surfactant is dissolved in water, and the nano material is uniformly dispersed in the water. The in-situ emulsification and tackifying system comprises the following components (by mass): 0.1% of nonionic surfactant with a structural formula (I), 0.2% of anionic-nonionic surfactant with a structural formula (III) (n is 30), 0.08% of gamma-aminopropyltriethoxysilane modified carbon nanotubes, and the balance of injected water. Degree of mineralization of injected water 20X 10 4 mg/L of wherein Ca 2+ The content is 5000 mg/L.
(II) example 2
Preparing an in-situ emulsification and tackifying system: under the condition of stirring (500r/min), the in-situ emulsification and tackifying system is added into the injection water until the surfactant in the system is dissolved in the water and the nano material is uniformly dispersed in the water. The in-situ emulsification and tackifying system comprises the following components: 0.15% of nonionic surfactant with the structural formula (I), 0.15% of anionic-nonionic surfactant with the structural formula (III) (n is 7), 0.05% of graphene and the balance of injected water. Degree of mineralization of injected water 20X 10 4 mg/L of wherein Ca 2+ The content is 5000 mg/L.
(II) Performance test
(1) Aging resistance: the in-situ emulsification and tackifying system prepared in example 1 is placed in an oven at 90 ℃, taken out periodically, and an SVT20 rotary interfacial tensiometer is used for testing the interfacial tension at corresponding temperature, so as to evaluate the anti-aging performance of the system. The results of the experiment are shown in table 1.
TABLE 1 anti-aging Properties of in situ emulsion viscosification System
(2) Emulsifying property: the in-situ emulsification and viscosity-increasing system configured in example 1 and crude oil were added in different proportions to sealable glassware and placed in a 90 ℃ oil bath with a magnetic stirrer. Stirring for 1h after the temperature in the glassware is raised to 90 ℃, and testing the viscosity of the emulsion by using an Antopa high-temperature high-pressure rheometer after the stirring is finished. The results of the experiment are shown in table 2. As can be seen from Table 2, under the conditions of different oil-water ratios, the crude oil and the in-situ emulsification and viscosity-increasing system can form W/O type emulsion, and simultaneously, the viscosity of the emulsion increases along with the increase of water content, so that the fluidity self-control capability is shown, and the balanced displacement under different water content conditions is realized.
TABLE 2 viscosity values of emulsions at different oil-to-water ratios
(3) Oil displacement performance: the three-layer heterogeneous core was used to study the oil displacement capability of the in-situ emulsification and viscosification system configured in example 1 at 90 ℃. The gas logging permeability of the three layers of heterogeneous rock cores is respectively as follows: 50mD, 150mD and 400 mD; porosity: 19.6 percent; oil saturation: 58.7 percent; the width and height are 4.5cm, and the length is 30 cm; the injection rate during the displacement was 0.8 mL/min. The experimental result is shown in figure 1, and in the water flooding stage, due to reservoir heterogeneity and unfavorable oil-water fluidity ratio, the recovery ratio of water flooding to 98% water is 20.56%; and then injecting an in-situ emulsification and tackifying system, wherein the injection pressure is increased and the water content is reduced in the injection process, the output of W/O type emulsion is observed at the outlet end of the core, which shows that the in-situ emulsification and tackifying system is emulsified with crude oil in situ, the fluidity ratio in the displacement process is improved, and meanwhile, the dispersed water drops block the roar of a large hole through the Jamin effect, so that the heterogeneity of a reservoir is improved, the sweep efficiency is enlarged, and the recovery ratio is finally increased by 31.96%.
Claims (3)
1. The in-situ emulsification and viscosification system for the high-temperature and high-salinity oil reservoir is characterized by being prepared from the following components in mass content:
0.05 to 0.2 percent of nonionic surfactant with the structural formula (I),
0.1 to 0.3 percent of anionic-nonionic surfactant with a structural formula (II),
0.01 to 0.1 percent of nano material,
the other components are water which is injected into the reactor,
wherein n is the polymerization degree of polyoxyethylene ether, and n is more than 7 and less than 40;
the nano material is at least one of gamma-aminopropyltriethoxysilane modified carbon nano tube, graphene and gamma- (methacryloyloxy) propyltrimethoxysilane modified nano silicon dioxide.
2. The in-situ emulsification and viscosification system for the high-temperature and high-salinity oil reservoir as claimed in claim 1, wherein the mineralization degree of the injected water is 0-22 x 10 4 mg/L。
3. Use of a high-temperature high-salt reservoir in-situ emulsification and viscosification system according to any one of claims 1-2 in a high-temperature high-salt reservoir.
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| CN113122217B (en) * | 2021-04-23 | 2022-07-05 | 西南石油大学 | Carbon-based amphiphilic nano-flow for oil displacement and preparation method thereof |
| CN113292978B (en) * | 2021-05-28 | 2022-03-08 | 西南石油大学 | Amphoteric two-dimensional nanosheet and preparation method and application thereof |
| CN113356814B (en) * | 2021-07-14 | 2022-03-11 | 西南石油大学 | Method for improving recovery ratio of thickened oil by using high-phase-change oil-water in-situ emulsion |
| CN113462375A (en) * | 2021-07-15 | 2021-10-01 | 西南石油大学 | Chemical intervention in-situ emulsification system |
| CN114525121B (en) * | 2022-01-13 | 2023-10-13 | 东北石油大学 | In-situ emulsification type surfactant oil displacement system and application thereof |
| CN114479819A (en) * | 2022-01-24 | 2022-05-13 | 西安石油大学 | Thickening agent, fracturing fluid and preparation method thereof, gel breaking method of fracturing fluid and application method |
| CN114940893B (en) * | 2022-07-04 | 2023-06-23 | 西南石油大学 | Tackifying nano calcium carbonate oil displacement agent and preparation method thereof |
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