RU2250988C1 - Oil deposit extraction method - Google Patents

Abstract

FIELD: oil industry.

SUBSTANCE: method for extraction of oil deposit by forcing a buffer of hydrocarbon solution into bed, containing surfactant, through force wells and extraction of oil through product wells, a buffer is forced into bed, containing non-ionized surfactant diproxamine-157 and additionally polyalkylbenzole resin at mass ratio 1:1-9 or non-ionized surfactant diproxamine-157 and additionally polyalkylbenzole resin and polyglykols with mass ratio 1:1-5.56:0.03-0.33 respectively with concentration of mixture of these components in hydrocarbon solution 0.1-5.0 percents of mass at amount 5-20% of porous volume, with following displacement of it along the bed by forcing agent. As forcing agent, water or agent buffer is used with movement ability picked for current bed conditions combined with water. In case of highly non-homogenous beds buffers of hydrocarbon solution and forcing agent are forced several times and alternately.

EFFECT: higher oil yield.

3 cl, 7 tbl

Description

The invention relates to methods for developing oil fields and can be used in the oil industry to increase oil recovery of conventional and heterogeneous, low-permeable terrigenous and carbonate formations, as well as for developing oil fields with oils with a high content of tar and asphaltic substances.

When developing productive oil reservoirs by the method of water flooding, leading well flooding occurs. Even with a favorable combination of factors affecting individual indicators of waterflooding efficiency, the current oil recovery rates for watering of producing wells of 80-95% are 0.54-0.65, and the residual oil saturation of the core ranges from 20-28%; with an unfavorable combination of factors, oil recovery decreases to 0.20-0.25 and even to 0.10-0.15. From the above data it follows that the residual oil reserves in the areas covered and not covered by the waterflooding process, with water cuts of about 90%, are huge. Part of the residual oil reserves is capillary-retained due to the microinhomogeneity of the formation and molecular-surface forces. Another part of the residual reserves is film oil, which arises due to the large adhesion to the skeleton of the reservoir. Therefore, in most fields, there is a need to increase the efficiency of water flooding by recovering the residual oil reserves covered and not covered by the water flooding process, which will lead to additional oil production.

A known method of displacing oil from the reservoir, including the cyclic injection into the reservoir of dry oil gas mixed with propane-butane fractions of oil and water (ed. Certificate of the USSR No. 1795091, MKI 5 E 21 V 43/22, publ. 15.02.93, Bull. No. 6).

A known method of developing an oil deposit, including the injection of a solution of a surface-active substance (surfactant), a wide fraction of light hydrocarbons (BFLH), a second solution of a surfactant (RF patent No. 2103492, MKI 6 E 21 V 43/22, publ. 01.27.98, )

The disadvantages of these methods is the low efficiency of the displacement of highly viscous heavy oils due to the fact that they do not provide the transfer to the gas phase of the majority of the heavy components of oil hydrocarbons at reservoir pressures and temperatures; high operating costs associated with the fact that in order to create an effective process in the reservoir - miscible displacement - it is necessary to create extremely high pressure; the process pressure at a given temperature mainly depends on the composition of the oil, the higher it is, the higher the content of heavy fractions in oil. To ensure effective displacement, a large consumption of displacing agent is required, since the displacement front is characterized by the presence of “tongues” of invasion due to the high mobility of the agent, which leads to premature breakthrough to production wells and high water cut of the wells. In addition, in the development of heavy oils with increased viscosity, asphalt-resin-paraffin components (AFS) may fall out of oil, while there is a significant decrease in the filtration characteristics of the formation and their blockage.

A known method for the extraction of viscous oil with a high content of resins and asphaltenes, providing for the injection into the formation of an aromatic solvent containing 45-60% phenols, carboxylic acids and their anhydrides (US patent No. 4469177, MKI E 21 V 43/24, publ. 04.09.84 )

The disadvantages of this method are the high cost of aromatic solvents, as well as a large amount of environmentally harmful additives (phenols, carboxylic acids and their anhydrides).

There is a method of developing an oil deposit by injecting into the formation rims of a solvent containing an oil-soluble polymer or an oil-soluble surfactant as an additive, followed by pushing it with gas or gas and water (RF patent No. 2034981, MKI 6 E 21 V 43/22, publ. 10.05. 95, Bull. No. 13).

The closest in technical essence and attainable effect is a method for development of oil pool comprising a rim joint download processing product formation of acid tars and ethoxylated alkylphenol -4 AF ₉ in hydrocarbon solution, then rim-surfactant product of an aqueous solution of joint processing of acid tars and ethoxylated alkylphenol AF ₉ -12 for two cycles (RF patent №2012787, MKI 5 E 21 B 43/22, opubl.15.05.94, Byul.№9).

The disadvantages of the above methods are the relatively low increase in oil recovery, especially in low-permeable and / or carbonate formations containing highly viscous heavy oil, since only the part that is in the cracks and pores (capillary-retained) can be selected, and the film oil due to the large adhesion to the skeleton of the collector is selected in a small amount. In addition, these methods are ineffective at the late stage of reservoir development.

The objective of the invention is to increase the oil recovery of terrigenous and carbonate formations, in particular, containing highly viscous oils with a high content of surfactants, due to the recovery of residual oil reserves in the areas of the formation covered and not covered by the process using inexpensive and affordable hydrocarbon solvents and directional additives.

The problem is solved by the method of developing an oil deposit by injecting the rim of a hydrocarbon solution containing a surfactant into the formation through injection wells and selecting oil through production wells. Moreover, a rim is injected into the formation containing, as a surfactant, a nonionic surfactant — Diproxamine-157 and an additional polyalkylbenzene resin in a weight ratio of 1: 1–9 or a nonionic surfactant — Diproxamine-157 and an additional polyalkylbenzene resin and polyglycols in a mass ratio of 1: 1–5.56: 0.03–0.33, respectively, with a concentration of a mixture of these components in a hydrocarbon solution of 0.1-5.0 wt.%, in an amount of 5-30% of the pore volume, followed by its advancement by formation push agent. As a pushing agent, water or a rim of an agent with mobility selected to the conditions of the formation and water are used. In the case of high heterogeneity of the formations, the rims of the hydrocarbon solution and the pushing agent can be injected repeatedly and alternately.

The essential features of the proposed technical solution are the following:

1. Injection through injection wells of the rim of a hydrocarbon solution miscible with oil containing surfactant.

2. Oil extraction through production wells.

3. The tip of the hydrocarbon solution contains as a surfactant a nonionic surfactant (nonionic surfactant) - Diproxamine-157 (D-157).

4. Additionally, the rim contains a polyalkylbenzene resin or a polyalkylbenzene resin (PABS) and polyglycols (PG).

5. The ratio of the components in the hydrocarbon solvent is as follows: nonionic surfactants: PABS: PG - 1: 1–5.56: 0.03–0.33 or nonionic surfactants: PABS - 1: 1–9.

6. The total concentration of the mixture of components (nonionic surfactants, PABS, PG) in a hydrocarbon solution of 0.1-5.0 wt.%.

7. The total volume of the rim of the hydrocarbon solution is 5-30% of the pore volume of the reservoir.

8. Advancement of the rim of the hydrocarbon solution by the rim of the pushing agent throughout the formation.

Signs 1-2 are common with the prototype, signs 3-8 are the salient features of the invention.

Studies of patent and scientific and technical literature, other well-known technical solutions in this and related fields of technology and analysis of known solutions selected in the search process showed that such a combination of the claimed essential features is new and has not been used before. There is no object in science and technology that is identical to the claimed combination of essential features that has high rates and allows to obtain a new technical result, namely, to increase the efficiency of developing oil terrigenous and carbonate formations, in particular, containing highly viscous oils with a high content of surfactants, due to the recovery of the covered and not covered by the process of flooding the residual oil reserves. Since the possibility of obtaining the specified technical result by implementing the claimed combination of essential features for the specialist does not explicitly follow from the prior art, this allows us to conclude that the proposed method meets the criteria of “novelty” and “inventive step”.

To implement the method as a hydrocarbon solvent, you can use both aromatic and non-aromatic solvents or mixtures thereof, for example: SHFLU TU 38.101524-93; hexane fraction TU 38.10381-83; alkylbenzene fractions TU 6-01-10-37-78, TU 38.402-62-140-42, TU 38-10297-78; nefras, gasolines GOST 443-76, TU 38101303-72; unstable gasoline - distillate from complex oil treatment units (UKPN) TU 38101524-93; Shugurovsky distillate TU 30-0147585-018-93; diesel fuel GOST 305-82, etc.

The following substances are used as directional additives:

Polyalkylbenzene resin (PABS), a by-product of isopropylbenzene production, consists of a mixture of di-, tri-, tetraisopropylbenzenes and other higher molecular weight polyalkylbenzenes. It is produced in accordance with TU 33.10296–83. It is a viscous dark colored liquid. The density at 20 ° C is 0.9-1.0 g / cm ³ ; conditional viscosity at 50 ° C - 1.0-3.0 degrees WU; fractional composition: the boiling point is not lower than 150 ° C, the temperature of 85% of the distillation of the resin is not higher than 360 ° C; mass fraction of water not more than 0.2 wt.%.

Diproxamine-157 (D-157) is a nitrogen-containing block copolymer of ethylene oxide and propylene oxide with an average molecular weight of 5000 cu contains 27-28 hydroxyethyl units and 59-61 oxypropyl units, has a trademark and is produced according to TU 6-14-614-96. Appearance - light yellow liquid; density at 20 ° C - 1.02 g / cm ³ ; kinematic viscosity at 20 ° C - 635 mm ² / s; pour point - minus 35 ° C.

Polyglycols (GH) - a waste of glycol production is obtained by hydration of ethylene oxide and is a mixture of glycols (monoethylene glycol, diethylene glycol, triethylene glycol, tetraethylene glycol, etc.). Available in accordance with TU 6-01-10-40-79. Appearance - dark viscous liquid; density at 20 ° C not less than 1,075 g / cm ³ ; boiling point at a pressure of 101.3 kPa not lower than 190 ° C.

A hydrocarbon solution is simple to prepare, it is obtained by mixing the starting components by heating to 30-40 ° C both in the factory and directly in the field. The resulting solution is stable for a long time.

To prove compliance of the claimed invention with the criterion of “industrial applicability”, tests were conducted on various physical models of the formation with different oils using the proposed method, which are presented below.

Table 1 shows the physical properties of the reservoir models, table 2 shows the physicochemical properties of the oils, table 3 shows the efficiency of oil displacement N – 1 on the terrigenous reservoir, and tables 4 and 5 show the efficiency of oil displacement N – 2 on terrigenous and carbonate reservoir, in tables 5 and 6 - the efficiency of oil displacement N – 3 on terrigenous and carbonate reservoir.

The experiments were carried out on a setup consisting of a physical model of the reservoir, a constant pressure maintenance system, pressure sensors and instrumentation.

The reservoir model for determining the oil displacing ability of agents is represented by a single linear glass tube filled with a carefully packed bulk porous medium. In studies, 2 reservoir models were used - terrigenous and carbonate. In the terrigenous model, silica sand of various grinding (fraction less than 0.63 mm) preliminarily activated with hydrochloric acid served as a porous medium. In the carbonate model, a mixture of the same quartz sand with calcium carbonate (CaCO ₃ ).

The methodology of the experiments. To create bound water and initial oil saturation in a porous medium, the porous medium is saturated with formation water under vacuum, and the pore volume, porosity, and water permeability of the model are determined in a volumetric manner. Then, the produced water is replaced with oil until anhydrous oil appears at the outlet, and the initial oil saturation, which was within 80%, is determined by volumetric method. For adsorption of heavy oil components in a porous medium, oil is kept in the model for 1 day. The properties of the terrigenous and carbonate reservoir model are presented in Table 1. In the experiments, three types of natural oil were used, with different densities, viscosities and contents of surfactants, the physicochemical properties of which are presented in table 2.

The experiment was carried out by the method of secondary oil displacement, at T = 295 K and with a constant pressure drop of 1 atm. The differential pressure is measured using a differential pressure sensor.

The initial displacement of oil is carried out with the required volume of water up to 100% of the water cut of the produced products at the outlet, which does not decrease when pumping an additional volume of liquid, and stabilization of the filtration rate. At the next stage, after creating the residual oil saturation, a rim of the hydrocarbon solution in the amount of 10% of the pore volume is introduced into the model, after which water is again pumped or the rim of the pushing agent is first introduced.

The amount of oil displaced is determined by the volumetric method, i.e. the selected liquid is defended until complete separation, and the volume of the released oil is measured.

During the experiment, the following indicators were recorded:

- oil recovery coefficient after normal water flooding (η _B ), which was in the range of 55-58% on terrigenous models of the reservoir and 48-51% on carbonate;

- total (final) oil recovery coefficient (η _K );

- the increase in oil recovery coefficient (Δη) π was calculated as the difference between the total oil recovery and oil recovery after normal water flooding, i.e. Δη = η _K -η _B.

According to the method described above, with different contents of the active substance in various hydrocarbon solvents carry out the proposed method and known (prototype). The experiments use light, low-viscosity, with a low content of CAB natural oil N – 1. A terrigenous model was taken as a reservoir model. The results are shown in table 3. As can be seen from the table, the increase in oil recovery coefficient (Δη) ο о the proposed method in the entire range of concentrations of the active substance (0.1-5.0 wt.%) Is 21.9-32.6% (experiments 8-14), while the prototype 16.8-28.1% (experiments 3-7). The results of experiments 13 and 14 show that the oil recovery coefficient when using the rim of the pushing agent with the selected mobility after the hydrocarbon rim is 5.3% higher than when the rim is promoted with water. The results of experiments 1 and 2, where rims of hydrocarbon solvents without additives were used, showed a low increase in the oil recovery coefficient - 14.1 = 14.9%.

The use of a hydrocarbon rim, with a total concentration of additive composition of less than 0.1 wt.% In a hydrocarbon solvent, shows low efficiency, therefore, a concentration of 0.1 wt.% Can be taken as the minimum. An increase in the content of the additive composition above 5.0 wt.% In the solvent does not lead to a significant increase in the oil recovery coefficient, therefore, using solutions with a content higher than this concentration is inefficient and economically impractical, since the efficiency of the method and its cost will become incommensurable.

Experiments using the same methodology are carried out using heavier, viscous, with a high content of SAW natural oil N – 2. A terrigenous and carbonate model is taken as a reservoir model. The results are shown in table 4 and 5. Analysis of the results of studies of the efficiency of the displacement of heavier oil by the prototype and the proposed method with different mass ratios of additives in the composition shows that the increase in oil recovery coefficient on the terrigenous model (see table 4) of the reservoir is 19.3- 23.4% (experiments 6-9) versus 17.4% (experiment 5) - according to the prototype, and on the carbonate (see table 5) - 23.5-29.2% (experiments 6-9) against 20 , 0% (experiment 5).

Tests 2–4 (see Tables 4 and 5) on both reservoir models show that when additives (D-157, PABS, PG) are added to a hydrocarbon solvent, a significantly smaller increase in the oil recovery coefficient is achieved (on the terrigenous model (see table) .4) - 15.5-16.8%, on the carbonate model (see table 5) - 18.2-19.2%) compared with the composition of these additives. The smallest increase in oil recovery showed the rim of the hydrocarbon solvent without additives (experiment 1 - table 4 and 5).

Then, experiments using the same technique are carried out using heavy, highly viscous, with a high content of surfactants, natural oil N – 3. A terrigenous and carbonate model is used as a reservoir model. Additionally measure the permeability of the formation by water after normal flooding and final, after the use of displacing agents. According to the data obtained, a relative increase in the permeability of the formation by water (in%) is calculated. The research results are shown in tables 6 and 7. From the tables it can be seen that the increase in the oil recovery coefficient for various mass ratios of additives in the composition is –– on the terrigenous model of the formation (see table 6) 22.7–23.5%, increase in permeability by 100 , 2-167.8%, i.e. 2-2.7 times (experiments 6-9) versus 18.7%, an increase in permeability of 77.6%, i.e. 1.8 times (experiment 5) - according to the prototype; and on carbonate (see table 7) - 18.8-27.9%, increase in permeability by 302.5-496.6%, i.e. 4-5 times (experiments 6-11) versus 16.8%, increase in permeability by 267.0%, i.e. 3.7 times (experiment 5) - according to the prototype.

As you can see, the addition of a composition of directional additives to a hydrocarbon solvent increases the water permeability of the reservoir model, which is especially important when applying the proposed method for fields with low permeability reservoirs, in addition, the injectivity of wells increases.

Tests 2–4 (see Tables 6 and 7) on both reservoir models show that when additives (D-157, PABS, PG) are added to a hydrocarbon solvent, significantly lower efficacy is achieved individually compared to the composition of these additives; the increase in oil recovery coefficient on the terrigenous model was (see table 6) - 16.4-17.1%, the increase in permeability - 46.5-55.9%, i.e. 1.5-1.6 times; and on the carbonate model (see table 7) - 12.7-13.5%, increase in permeability - 174.7-202.3%, i.e. 2.7-3 times. The smallest increase in oil recovery was shown by the rim of the hydrocarbon solvent without additives (experiment 1 of tables 5 and 6).

The results of experiments 12,13 and 14 (see Tables 6 and 7) show that the introduction of a rim of a pushing agent with selected mobility after a hydrocarbon rim increases the oil recovery coefficient by 4.9% in comparison with the promotion of the rim with water. And the use of alternating rims of a pushing agent with selected mobility and a hydrocarbon solution increases the oil recovery coefficient by 9.1%.

Studies have shown that the use of rims less than 5% of the pore volume is not very effective and does not allow the maximum displacement of oil. The size of the rim is determined by the geological structure of oil fields and the density of the grid of wells. In real conditions, field development is complicated by various types of heterogeneity, which leads to uneven effects of the rim of the hydrocarbon solution in various areas of the oil-containing reservoir. Thus, the lower boundary value of the rim value of 5% of the pore volume is justified by the possibility of realizing rim in the formation that does not deteriorate as it progresses, and is effective in the case of development of deposits with an uncomplicated reservoir heterogeneity and when using real dense well networks. The upper boundary value of the rim value of 30% of the pore volume is used on deposits in which the reservoir is characterized by heterogeneity, or when using a sparse grid of wells, and is due to the fact that at modern oil prices and based on calculations of economic indicators of the impact process, the use of a larger rim is energetically unprofitable and it is not economically feasible with real sparse well grids.

The task is to increase oil recovery by displacing hard-to-recover oil reserves (capillary-retained and film oil) in areas covered and not covered by the waterflooding process, achieved due to the complex action of a hydrocarbon solvent containing a composition of directional additives (D-157, PABS, PG), and pushing agent.

The introduction of a composition of additives of directed action in a hydrocarbon solvent leads to an increase in its oil washing properties. Due to the complex action of additives, more complete destruction of the boundary layers and films (supramolecular structures) of oil at the contact with the rock occurs, removal of heavy oil components - SAW, ASPO from the pore space, translation of all this into a mobile state and involvement in the displacement process. A mixture of a hydrocarbon solution and a residual oil dissolved in it having a low viscosity and high mobility is displaced from the porous medium by water. The result is not only the preservation of the miscibility region during its movement, but also a more complete leaching of the remaining hydrocarbon phase from the reservoir.

During the displacement of highly viscous heavy oil, as well as during the displacement of oil from poorly permeable and / or heterogeneous formations by the rim of a hydrocarbon solution pushed by water, the displacement front due to the high mobility of the agents can be characterized by the presence of “tongues” of invasion, which leads to premature breakthrough to production wells, high water cut of wells and lower reservoir coverage. In this case, it is proposed to control the movement of the hydrocarbon rim by reducing the mobility of the pushing agent, for example, by creating a certain viscosity by using the rim of the pushing agent — thickened water (aqueous polymer solutions), emulsion, disperse, polymer dispersed systems, etc. This leads to an increase in resistance during filtration, a decrease in mobility and the prevention of premature erosion of the rim of the hydrocarbon solution; as a result, the speed of movement and the mobility of the front along the formation are stabilized. The mobility and rim volume of the pushing agent is selected depending on the characteristics of the formation, for example, the higher the heterogeneity of the formation, the higher the rim volume and the lower the mobility of the pushing agent. The tip of the pushing agent is then advanced by water.

In the case of extreme heterogeneity of the collector, it is possible to use alternating rims of the pushing agent with selected mobility and a hydrocarbon solution, then with water. When developing heterogeneous highly flooded formations, it is also possible to conduct preliminary isolation of highly permeable zones. As a result, the coverage of the formation is increased and the breakthrough of the hydrocarbon solution in the production wells is prevented due to equalization of the permeability of different-permeable layers.

The implementation of the method allows you to almost completely remove the entire hydrocarbon phase from the reservoir, filling the pore space with water.

Thus, the above data indicate that when the oil is displaced by the proposed method, a miscible oil displacement is carried out with coverage of the entire oil-saturated region, the oil recovery coefficient, permeability increases, and when using the prototype such results were not obtained.

The proposed method allows you to:

1. To increase the oil recovery coefficient and production efficiency of hard-to-recover oil reserves by 18.8–32.6%.

Dispose of petrochemical waste.

Use cheap and affordable reagents.

To develop oil fields at a late stage of development.

In addition, this method does not require special equipment and is easily feasible in the field using standard equipment.

Table 1
Physical properties of reservoir models Collector Model length mm Diameter of the model, mm Porosity,% Specific surface, m ² / m ³ Permeability, μm ² Terrigenous 300 12.5 33.9 400,000 1,1 Carbonate 320 12.5 31.7 435,000 0.7

table 2
Physico-chemical properties of oils. Name of indicator Oil designation N – 1 N – 2 N – 3 Density ρ, kg / m ³ 882 889 922 Water content,% 0.8 1,0 0,075 Conventional viscosity, conv. hail.:
at 20 ° C
at 50 ° C 2,8
1,6 3,7
1.9 16.1
3.3 Dynamic viscosity at 20 ° С, MPa · s 22.6 23.9 109.7 The content of the ASV,% wt .:
Resin
Asphaltenov 12.3
10,2
2.1 17.1
13.5
3.6 42.6
38,4
4.2

Table 3
Efficiency of oil displacement N – 1 on a terrigenous reservoir The sequence of injection rims hydrocarbon solution and pushing agent Hydrocarbon solvent The mass ratio of additives in the composition,
Nonionic surfactants: PABS: PG The total concentration of the additive composition in a hydrocarbon solution,% wt. Oil recovery coefficient increase,%, Δη Experience Number rim of hydrocarbon solution (ESD), then water Nefras 0: 0: 0 0 14.9 1 Esd then water Shugurovsky distillate 0: 0: 0 0 14.1 2 Prototype Nefras 1: 0: 0 0.5 22.8 3 1,0 25.0 4 3.0 26.9 5 5,0 28.1 6 Shugurovsky distillate 1: 0: 0 3.0 16.8 7 The proposed method Esd then water Nefras 1: 1: 0.03 0.1 24.5 8 0.5 27.4 nine 1,0 29.2 10 3.0 31.7 eleven 5,0 32.6 12 Esd then water Shugurovsky distillate 1: 5.56: 0.1 3.0 21.9 thirteen ESD, matched push mobility rim (OPAP), then water Shugurovsky distillate 1: 5.56: 0.1 3.0 27,2 14

Table 4
Efficiency of oil displacement H – 2 on a terrigenous reservoir The sequence of injection rims hydrocarbon solution and pushing agent Hydrocarbon solvent The total concentration of the additive composition in a hydrocarbon solution,% wt. The mass ratio of additives in the composition,
Nonionic surfactants: PABS: PG Oil recovery coefficient increase,%, Δη Experience Number ESD, OAPP, then water Unstable gasoline, distillate with UKPN (NB) 0 0: 0: 0 15.3 1 1,0 1: 0: 0 16,2 2 0: 1: 0 16.8 3 0: 0: 1 15,5 4 Prototype NB 1,0 1: 0: 0 17.4 5 Proposed ESD, OAPP, then water NB 1,0 1: 1: 0 20,2 6 1: 9: 0 19.3 7 1: 5.33: 0.33 22.7 8 1: 1: 0.1 23,4 nine Table 5
Efficiency of oil displacement Н – 2 on a carbonate reservoir The sequence of injection rims hydrocarbon solution and pushing agent Hydrocarbon solvent The total concentration of the additive composition in a hydrocarbon solution,% wt. The mass ratio of additives in the composition,
Nonionic surfactants: PABS: PG Oil recovery coefficient increase,%, Δη Experience Number ESD, OAPP, then water NB 0 0: 0: 0 17.6 1 1,0 1: 0: 0 18.9 2 0: 1: 0 19.2 3 0: 0: 1 18.2 4 Prototype NB 1,0 1: 0: 0 20,0 5 The proposed method ESD, OAPP, then water NB 1,0 1: 1: 0 25,2 6 1: 9: 0 23.5 7 1: 5.33: 0.33 28.7 8 1: 1: 0.1 29.2 nine

Table 6
Efficiency of oil displacement N – 3 on a terrigenous reservoir The sequence of injection rims hydrocarbon solution and pushing agent Hydrocarbon solvent The total concentration of the additive composition in a hydrocarbon solution,% wt. The mass ratio of additives in the composition, nonionic surfactants: PABS: PG Oil recovery coefficient increase,%, Δη The increase in water permeability,% Experience Number ESD, OAPP, then water NB 0 0: 0: 0 15.6 34.6 1 1,0 1: 0: 0 16.7 48.7 2 0: 1: 0 17.1 55.9 3 0: 0: 1 16,4 46.5 4 Prototype NB 1,0 1: 0: 0 18.7 77.6 5 The proposed method ESD, OAPP, then water NB 1,0 1: 1: 0 22.8 145.1 6 1: 9: 0 22.7 100,2 7 1: 5.33: 0.33 23.3 123.3 8 1: 1: 0.1 23.5 167.8 nine Table 7
Efficiency of oil displacement Н – 3 on a carbonate reservoir
The sequence of injection rims hydrocarbon solution and pushing agent Hydrocarbon solvent The total concentration of the additive composition in a hydrocarbon solution,% wt. The mass ratio of additives in the composition, nonionic surfactants: PABS: PG Oil recovery coefficient increase,%, Δη The increase in water permeability,% Experience Number ESD, OAPP, then water NB 0 0: 0: 0 11.1 121.7 1 1,0 1: 0: 0 12.9 187.4 2 0: 1: 0 13.5 202.3 3 0: 0: 1 12.7 174.7 4 Prototype NB 1,0 1: 0: 0 16.8 267.0 5 The proposed method ESD, OAPP, then water NB 1,0 1: 1: 0 20.3 396.2 6 1: 9: 0 19.1 379.4 7 1: 5.33: 0.33 22.0 417.7 8 1: 1: 0.1 23.7 454.8 nine ESD and OAPP are injected repeatedly and alternately NB 1,0 1: 1: 0.1 27.9 498.6 10 Esd then water NB 1,0 1: 1: 0.1 18.8 302.5 eleven

Claims (3)

1. A method of developing an oil deposit by injecting the rim of a hydrocarbon solution containing a surfactant into the formation through injection wells and extracting oil through production wells, characterized in that a rim containing a nonionic surfactant as a surfactant is injected into the formation Diproxamine-157 and optionally a polyalkylbenzene resin in a weight ratio of 1: 1–9 or non-ionic surfactant Diproxamine-157 and optionally polyalkyl benzene resin and polyglycols in a mass ratio of 1: 1–5.56: 0.03–0.33, respectively, with a concentration of a mixture of these components in a hydrocarbon solution of 0.1-5.0 wt.%, in an amount of 5-30% of the pore volume , followed by its advancement through the reservoir with a pushing agent. 2. The method according to claim 1, characterized in that as the pushing agent, water or a rim of the agent with mobility selected to the formation conditions and water are used. 3. The method according to claim 1, characterized in that in the case of high heterogeneity of the layers, the rims of the hydrocarbon solution and the pushing agent are injected repeatedly and alternately.