RU2454448C1 - Reagent for treating oil reservoir and method of using said reagent - Google Patents

Abstract

FIELD: chemistry.

SUBSTANCE: invention relates to oil industry, particularly reagents for treating an oil reservoir and methods of extracting oil and can be used on oil deposits in a wide range of reservoir temperature (20-90°C), total content of salts in the stratal and injected water (0.034-24.0 wt %) with carbonate, terrigenous and mudded rocks. The reagent is a mother solution of ammonium sulphate from stripping aqueous acidic wastes from caprolactam production containing not less than 41 wt % dry residue, not less than 2.1 wt % amino organic acids in form of amino caproic acid and having pH higher than 4.4. The method of extracting oil involves pumping said reagent and aqueous solution of electrolyte and/or organic solvent.

EFFECT: high well productivity and high reservoir recovery.

2 cl, 4 tbl

Description

The invention relates to the oil industry, in particular to reagents for treating an oil reservoir and to methods for treating a bottomhole zone to increase production productivity and injectivity of injection wells, as well as for developing wells, and is intended for use in the development and operation of oil fields composed of terrigenous and carbonate by the rocks.

It is known ([1] Christian M., Sokol S., Konstantinescu A. Increase in productivity and injectivity of wells. M., Nedra, 1985, pp. 9-10), that one of the factors significantly affecting productivity and injectivity of wells is capillary pressure holding water in the bottom-hole formation zone (BHP) of the producing well or oil in the BHP of the injection well. Moreover, the higher the capillary pressure, the lower the productivity of the wells.

Where

P _s - capillary pressure, MPa,

σ is the interfacial tension at the oil-water phase boundary, mN / m,

- косинус угла смачивания породы водной фазой и нефтью,

- cosine of the wetting angle of the rock with an aqueous phase and oil,

r is the average radius of the rock pore, m

≈0, т.е.

≈90° - вода и нефть не смачивают породу пласта, а также при увеличении r пор породы. На σ,

и r существенно влияют поверхностно-активные вещества (ПАВ), органические растворители и водные растворы электролитов - неорганических и органических солей, кислот и оснований (щелочей).In the conditions of waterflooding of the oil reservoir, P _{c is} high not only due to the large σ at the oil-water interface (28-32 mN / m), but also due to the value of r caused by the sorption of film oil and asphaltene-tar-paraffin deposits - paraffin deposits on the formation rock, clay swelling component of the breed and the presence of mechanical colmatants. To increase the productivity of injection and production wells, it is necessary to remove residual oil and capillary-retained water from the bottomhole formation wells, respectively. The latter is achieved when P _s → 0, or rather, at low σ (less than 0.1 mN / m), or at

≈0, i.e.

≈90 ° - water and oil do not wet the formation rock, as well as with increasing r pores of the rock. On σ,

and r significantly influence surface-active substances (surfactants), organic solvents and aqueous solutions of electrolytes - inorganic and organic salts, acids and bases (alkalis).

>0.It is known the use of anionic, nonionic and cationic surfactants for the intensification of oil production ([2] Ibragimov GZ, Fazlutdinov KS, Khisamutdinov NI The use of chemicals for the intensification of oil production. Handbook, M., Nedra, 1991, p.129). However, their efficiency for processing the bottom-hole zone (BHP) of wells is low due to the high interfacial tension of aqueous solutions of these surfactants at the interface with oil (σ> 0.5 mN / m) and cos

> 0.

The closest analogue to the proposed invention is the use of an aqueous resin solution (HRV) from an evaporation of an aqueous acidic effluent from the production of caprolactam - an aqueous solution of an ampholytic surfactant - to intensify the operation of injection and production wells ([3] RF patent 2314332, E21B 43/22). However, this reagent is not effective enough in a wide range of geological and physical properties of the reservoir (temperature, nature of the reservoir rock and salt content in the injected and formation waters).

≈90° и, соответственно, Р_с→0 по ф.1 вследствие трудности достижения оптимального гидрофильно-липофильного баланса (ГЛБ) молекул амфолитного ПАВ, входящего в их состав, при котором Р_с→0.A known method of SCR wells using HRV with an aqueous solution of electrolytes, and / or with an organic solvent in various combinations [3]. However, this method has the same drawback as HRV. The reason for this is that HRV and its combination with electrolytes and organic solvents, as wetting agents of the reservoir rock, do not provide reliable achievement

≈90 ° and, accordingly, Р _с → 0 according to claim 1 due to the difficulty in achieving the optimal hydrophilic-lipophilic balance (HLB) of the ampholytic surfactant molecules included in their composition, at which Р _с → 0.

The objective of the invention is the expansion of the range of surface-active substances for processing the bottom-hole zone of an oil reservoir and the creation of an effective method for processing the bottom-hole zone of an oil reservoir with its use, which allows to expand the range of SCR effectiveness in the geological and physical properties of the reservoir.

The problem is solved in that as a reagent for treating the bottom-hole zone of an oil reservoir, a mother liquor of ammonium sulfate (MRSA) is used from a stripping of an aqueous-acidic effluent from caprolactam production containing at least 41 wt.% Dry residue, at least 2.1 wt.% amino acids in terms of aminocaproic acid, and having a pH above 4.4. The problem is also solved by creating a method for treating the bottom-hole zone of an oil reservoir, including injecting into the bottom-hole zone of an MRSA oil reservoir and with an aqueous solution of electrolytes and / or with an organic solvent, while chemicals are pumped into the reservoir in the order and combinations determined by the state of the bottom-hole zone of the well .

The mother liquor of ammonium sulfate is a by-product (secondary) of large-scale caprolactam production by the cyclohexane oxidation method ([4] Caprolactam production. Ed. Ovchinnikov VI, Ruchitsky VRM, Chemistry, 1977, p. 215). Currently, MRSA is not used anywhere and is subjected to thermal neutralization, i.e. burn in the zone of the fire torch.

The analysis of MRSA of different batches of selection for the composition showed that it contains at least 41 wt.% Solids and at least 2.1 wt.% Amino acids in terms of aminocaproic acid NH ₂ (CH ₂ ) ₅ COOH and has a pH above 4.4 ( see table 1). The dry residue is a mixture of amino acids and ammonium sulfate.

Thus, MRSA is an aqueous solution, mainly of ammonium sulfate and organic amino acids - a low molecular weight (non-colloidal) ampholytic surfactant of the wetting type, containing both the main (amino-NH ₂ ) and acid (carboxyl - COOH) groups in the molecule.

MRSA, like HRV, used according to the prototype [3], is formed by evaporation of a water-acid runoff of caprolactam production. Since the density of MRSA (1.18-1.24 g / cm ³ ) is higher than the density of HRV (1.08-1.12 g / cm ³ ), MRSA is located in the lower, and HRV in the upper part of the separation apparatus. At the same time, due to the high concentration of ammonium sulfate in MRSA (above 35 wt%), all the condensation products of amino acids (resins) are salted out from MRSA and form the upper layer - HRV with a low content of ammonium sulfate. Thus, high molecular weight ampholytic surfactants of a wide molecular weight distribution (resins) are found in HRV, and low molecular weight ampholytic surfactants of a narrow molecular mass distribution, mainly aminocaproic acid (ACA), which dissolves well in ammonium sulfate brine, are found in MPA. The difference both in the molecular mass and its distribution of the ampholytic surfactants found in MRSA and HRV causes their difference in surface-active properties with respect to the reservoir rock and the displaced oil, and, accordingly, in their oil displacement efficiency. Moreover, the ACC located in MRSA is a noncolloidal surfactant, i.e. does not form micelles in solution (unlike colloidal surfactants that form micelles) and belongs to the group of surfactant wetting agents. These surfactants are weakly adsorbed at the interface between the surfactant-oil solution (they have a high interfacial tension - σ _{n /} v), but are actively adsorbed on a solid surface under various conditions (temperature, salt content in the solution, nature of the surface), in particular, on the rock of the oil reservoir changing its wettability. And, as laboratory studies have shown, MRSA change the wettability of the formation rock surface close to neutral wettability, i.e. to Θ≈90 ° or cos Θ≈0 and, accordingly, Р _с → 0. Thus, in contrast to HRV, MRSA is a more effective reagent that changes the wettability of the rock surface of the oil reservoir in relation to the water and oil phases saturating the reservoir.

The use of a mother liquor of ammonium sulfate from an evaporation of an aqueous acidic effluent from the production of caprolactam in the oil industry is unknown and this reagent by the mechanism of oil displacement from the oil reservoir is significantly different from the known surfactants used in oil production.

To process the bottom-hole zone of the oil reservoir, MRSA wells are used in combination with an aqueous electrolyte solution and / or with an organic solvent, and they are pumped into the reservoir in the order and volumes determined by the state of the bottom-hole zone of the well (residual water and oil saturation, skin- effect, the nature of the reservoir rock, type of well, etc.). In this case, the electrolyte is one or a mixture of two or more substances that dissociate into ions in their aqueous solution.

This method of using MRSA with various reagents, in contrast to similar technical solutions [3], allows more efficient use of MRSA and reagents in a wide range of reservoir temperature and salt content in water on different rocks of the reservoir by maintaining cosΘ → 0 in the proposed method when using these reagents .

To perform the SCR method using MRSA with an aqueous electrolyte solution by sequentially pumping them or by pumping them into a mixture, the following electrolytes are used:

- an aqueous solution of inorganic salts, for example water for flooding oil reservoirs according to OST 39-225-88 with a total salt content of from 0.034 to 24 wt.%;

- inorganic acids, for example, inhibited hydrochloric acid according to TU 2122-131-058-07960-97, TU 39-05765670-OP-212-95, TU 6-01-04689381-85-92, or mixed with hydrofluoric acid (hydrofluoric acid) ) according to GOST 2567-89, TU 6-09-2622-88, or an inhibited mixture of hydrochloric and hydrofluoric acids according to TU 6-01-14-78-91, TU 113-08-523-82;

- alkaline electrolytes, for example sodium carbonate (soda ash) according to GOST 5100-85, or alkaline runoff of caprolactam production - SCHSPK in accordance with TU 113-03-488-84 with changes No. 1, 2, or surface-active alkaline composition - PSA in accordance with TU 2432-025-00205311-03, containing sodium carbonate and water-soluble salts of organic acids and having a pH above 10.

The SCR method using MRSA with an aqueous solution of inorganic salts allows one to obtain a mixture of them with different levels of MRSA either directly in the formation with sequential cyclic injection of them, or by mixing them before injection into the formation, for example, by dosing MRSA in water injected into the formation. In this case, when MRSA is mixed with waters containing calcium cation, a suspension of crystalline gypsum forms, the surface of which is modified by ACC. This sediment creates resistance in the zone of its formation, which redistributes the flow of injected reagents and water into less permeable layers, usually oil-saturated, thereby increasing the coverage factor of the reservoir by water flooding along with an increase in oil displacement due to a change in the wetting of the rock to Θ ~ 90 °. Thus, the SCR method using MRSA and aqueous solutions of inorganic salts allows increasing the oil recovery coefficient and, in contrast to the known technical solutions [2, 3], has a significant difference and novelty both in the mechanism of oil displacement and in the mechanism of oil coverage by the action of reagents and water.

The SCR method using MRSA with inorganic acids makes it possible to obtain an acidic cationic surfactant by the reaction of NH ₂ (CH ₂ ) ₅ COOH + H ⁺ → NH ₃ + (CH ₂ ) ₅ COOH either in the formation by sequentially injecting them into the well, when mixing them before injection into the reservoir. This SCR method using MRSA with acid allows not only to remove residual oil products (film oil and asphaltene-tar-paraffin deposits - paraffin deposits) from the surface of the rock and inorganic colmatants (clay, sand, scale, etc.), but also due to this effect to improve acid access to surfaces of colmatants and rocks and reaction with them. The use of MRSA with acid provides easier removal of reaction products and contamination from the bottomhole zone due to their wetting and surface-active properties and an increase in the permeability of the bottomhole zone rock, and, accordingly, well productivity.

The SCR method using MRSA with alkaline electrolytes allows to obtain an alkaline anionic surface-active composition by the reaction of NH ₂ (CH ₂ ) ₅ COOH + OH ^- → NH ₂ (CH ₂ ) ₅ COO ^- + H ₂ O or in the formation upon their sequential injection into the well, or when mixing them before injection into the reservoir. Additionally, when mixed MRSA with alkaline electrolytes containing water-soluble salts of organic acids such as sodium adipate in SCHSPK and PGS, are formed water-soluble associates kapronat NH ₂ (CH _{2) 5} COO ^- with adipate ^- CCA (CH _{2) 4} COO ^- due the interaction of the partial positive charge of the amino group (—NH ₂ ) with the negative charge of the carboxyl group (—COO ^- ).

[ ^- OOS (CH ₂ ) ₅ NH ₂ ^{δ + ... -} OOS (CH) ₄ COO ^- ]

These associates are commensurate with the pore cross section and pore narrowing, which causes resistance to the flow of the mixture of MRSA and alkaline electrolyte in the porous formation environment, i.e. the mixture has not only surface-active, but also rheological properties, and, accordingly, the SCR method using MRSA with alkaline electrolytes containing salts of organic acids allows not only effectively displacing oil from the BCP, but also increasing the working thickness of the reservoir due to rheological properties of their mixture.

Thus, the method of SCR wells using MRSA with an aqueous solution of various electrolytes, in contrast to the known similar technical solutions with anionic, nonionic and ampholytic surfactants [2, 3], has a significant difference and novelty both in the oil displacement mechanism and in the thickness coverage mechanism PZP layer by exposure to reagents and water.

To perform the method of SCR wells using MRSA with an organic solvent can be used, for example, the following solvents:

- alcohol-containing solvents, such as solvent SFPK (alcohol fraction of caprolact production) according to TU 2433-017-002-05311-99 with a total alcohol content of at least 40 wt.%; POD-purified oil according to TU 2433-016-00205311-99 with a total alcohol content of at least 57 wt.%; bottoms production of butyl alcohols according to TU 38-1021167-85 with a total alcohol content of at least 52 wt.%;

- hydrocarbon solvents, such as degassed oil, hexane fraction according to TU 38-10388-83, wide fraction of light hydrocarbons (BFLH) according to TU 38-101524-83, distillate and condensate - products of primary oil refining at UKPN of oil fields.

The use of solvents with MRSA both in a mixture of them and by sequentially pumping them into the bottomhole formation zone of the well improves the oil-displacing properties of MRSA and, accordingly, increases the productivity of the well.

The use of a hydrocarbon solvent with MRSA helps to remove film and drop viscous oil and paraffin due to the formation of a highly active mixture of them in the reservoir to improve the subsequent effect of acid treatments on the formation of the bottomhole formation zone of the injection well and helps to improve the phase permeability of the formation oil in the bottomhole zone of the production well. Such a complex effect of MRSA with an organic solvent increases the productivity of wells and has a significant difference from known analogues.

The proposed methods of SCR wells using MRSA can be applied in field practice both separately and in different order and combinations among themselves, depending on the state of the PPP of a particular well and on the task assigned to the SCR of a particular well, without and using pressure pulses (explosive perforation, thermogasochemical effects, etc.) and depression or depression pulses at the bottomhole zone (jet, ejector pumps of the UOS-1, UEOS brands, etc.).

The proposed MRSA reagent and a method for treating the bottom-hole formation zone with its use were tested in laboratory conditions in comparison with known surfactants and methods for their use in oil production.

The effectiveness of MRSA and methods is assessed by the residual fact of resistance to water and oil and their oil-displacing ability on the bulk linear model of the reservoir with a length of 12-14 cm and a diameter of 2.5 cm with pressure measurement at the inlet and in the middle of the model. The experiments are carried out on sandstone (P), carbonate (K) and clay sandstone (5% bentonite clay) (PG) at a temperature of 20-90 ° C using injected water (SV) containing 0.034-24.0 wt.% Salt mixture (electrolytes) according to the following procedure. The reservoir model is saturated with formation water with a density of 1.17 or 1.04 g / cm ³ (24.0 and 4.0 wt.% Salt mixture), then with oil with a viscosity of 10.2 and 1.7 MPa · s to irreducible water saturation and injected water to a residual oil saturation. Then, 0.9-1.1 pore volumes of the test reagent model or reagents are sequentially injected into the model (P) or after mixing (C) and 3 pore volumes of the injected water and oil model of the same viscosity are each. Oil displacement ability is determined by the ratio of the amount of oil displaced by the reagents to the amount of oil remaining after the waterflooding of the model (Δηн,% of the residual oil), and the change in the wettability of the core is determined by the residual resistance factor (R _{w / ost} ) at the midpoint of the model during pumping injected water and oil after reagents, calculated by the formula:

where Po and P are the pressure at the midpoint of the core during the pumping of water or oil before and after the injection of reagents, atm.

≈90°C.When R v _{/ n} ost is less than 1, the mobility of either oil or water improves, and if R v _{/ n} ost in the experiment is less than 1 for both water and oil, then in this experiment the wettability of the rock is close to neutral, i.e.

≈90 ° C.

Example 1. Table 2 shows the results of experiments according to the above procedure with MRSA samples of various batches (see Table 1) in combination with an aqueous solution of electrolytes (neutral, acid and alkaline) in comparison with solutions of the known reagent - an aqueous solution of an ampholytic surfactant ( BPA) according to TU 2431-024-00205311-03 (prototype according to [3]).

From the data in Table 2, it can be seen that all MRSA samples and their mixtures with aqueous solutions of inorganic salts (fresh - PV and mineralized water - MB), inorganic acids (hydrochloric - HCl, hydrofluoric - HF and clay acid - HA) and alkalis (ЩСПК and PSA) in fresh (PV) and mineralized (MB - 12.0% wt. Salts) waters are more effective as wetting agents of any breed in a wide temperature range (40-90 ° C) and mineralization of injected water (SV) (1.7- 12.0% wt.) Than the known BPA reagent (prototype according to [3]) (cf. Water and oil growth experiments 1-6 for MRSA with experiments 33-34 for BPA, experiments 7- 13 with experiments 35 and 36 for mixtures thereof with a solution of inorganic salts, experiments 14-18 with experiments 37-39 for mixtures thereof with inorganic acids and experiments 19, 24 with experiments 40-43 for mixtures thereof with alkalis). In this case, the resistance factors for both water and oil in 75% of experiments are less than 1 for MRSA and its mixtures, whereas for BPA and its mixtures with electrolytes, these factors are in most cases higher than 1. Based on this, MRSA and its mixture with electrolytes most effective for intensifying water injection into wells and oil production from producing wells.

In terms of efficiency, displacing residual oil after flooding of the MRSA reservoir is also more effective than BPA (see the above comparisons).

Thus, MRSA and its mixtures with electrolytes are effective both for processing the bottom-hole zone of a well formation in order to intensify their work, and for increasing oil recovery by pumping it into the formation through injection wells.

≈0 при R_ост<1), как и МРСА и превосходит известный способ с использованием ВРА [3] (ср. опыты 4 и 6 с опытами 8 и 7 соответственно) и отдельные реагенты - растворители (ср. опыты 1-6 с опытами 9-13).Example 2 illustrates the effectiveness of the method of using MRSA in combination with organic solvents, determined by the above method. Moreover, in experiments with the sequential injection of (P) reagents into the core, the organic solvent was pumped before the MPA in a volume of 0.1 pore volume. The results of the experiments are shown in Table 3, from which it can be seen that the solvents increase the oil-displacing ability of MRSA both when sequentially injected into the reservoir model (experiments 1, 3-6) and in their mixture (experiments 4, 5) (cf. experiments 1 -3 with experiment 4 of Table 2, experiments 5 and 6 with experiment 5 of Table 2). In this case, MRSA in combination with an organic solvent also shows a wetting ability to neutral (cos

≈0 at R _ost <1), like MRSA, it surpasses the known method using BPA [3] (compare experiments 4 and 6 with experiments 8 and 7, respectively) and individual reagents are solvents (compare experiments 1-6 with experiments 9-13).

Thus, MRSA in combination with organic solvents exhibits a synergistic effect, since their technological efficiency is 2 or more times higher than that for individual reagents.

Example 3 illustrates the effectiveness of MRSA in combination with several different reagents, for example, a mixture of MRSA with fresh (P) or mineralized (M) water and a different class of solvents injected before this mixture in a volume of 0.1 core pore volume according to the above method. Table 4 shows the results of the experiments both by the proposed method, and by the known. It can be seen from them that the complex method with MRSA (experiments 1-9) is more effective than the known method (experiments 10-12) (cf. experiments 2, 4 and 9 with experiments 10, 11 and 12, respectively).

Thus, MRSA and the method of using it in various combinations with aqueous electrolyte solutions and organic solvents increase the efficiency of the SCR of wells in a wide range of geological and physical properties of the formation (reservoir temperature, nature of the reservoir rock and salt content in the injected and formation waters) compared with well-known methods of SCR wells using BPA and, accordingly, anionic, nonionic surfactants and mixtures thereof.

The claimed technical solution is effective and industrially applicable.

The use of MRSA and a method for processing the bottom-hole zone of a well formation with its use in the oil industry can improve the efficiency of wells in various geological and physical conditions of the oil reservoir at various stages of development; Dispose of chemical waste, which will improve the environmental situation of production; use standard equipment in the production of fishing work.

MRSA and a method using it can also be used to increase oil recovery by periodically (cyclically) injecting them into injection and production wells of an oil field in combination with water-isolating (flow-rejecting) chemical compositions (hydrocarbon emulsions, aqueous cross-linked and non-cross-linked polymer compositions, sediment-forming, etc. . compositions) or without them.

Table 1 Composition and physicochemical properties of MRSA of various batches MRSA party number Content, wt.% d, g / cm ³ σ, mN / m pH dry residue amino acids 1) ammonium sulfate one 46 2,3 43.7 1.21 9.1 4.4 2 48 2.1 45.9 1.21 - 4.4 3 45 2,8 42,2 1.20 3.8 4,5 four 48 5,4 42.6 1.21 2.5 4.7 5 41 3,1 37.9 1.20 3,5 4.6 1) in terms of aminocaproic acid

table 2 The method of using MRSA with aqueous solutions of electrolytes (example 1) Experience number Lot No. according to Table 1 MRSA and its content in the mixture,% wt. with electrolyte solution Aqueous solution of electrolytes Tempe
experiment, ° C Breed type The salt content in the pollutant,% wt. The method of combining reagents Growth by Δη _n ,% of residual oil MRSA aqueous electrolyte solution water least
waning electrolyte content% wt. water oil one 2 3 four 5 6 7 8 9 10 eleven 12 13 fourteen The proposed reagent and method one one one hundred 0 0 0 0 60 P 12.0 P 0.76 0.90 0,0 2 3 one hundred 0 0 0 0 60 P 12.0 P 0.70 0.80 0,0 3 5 one hundred 0 0 0 0 60 P 12.0 P 0.87 1.00 0,0 four four one hundred 0 0 0 0 40 to 12.0 P 0.79 0.78 0,0 5 four one hundred 0 0 0 0 90 to 1.7 P 0.70 0.30 15.0 6 four one hundred 0 0 0 0 63 to 12.0 P 1,60 0.00 59.0 7 four 25 75 0 PV 0,034 63 to 12.0 from 0.65 0.57 0,0 8 four 25 75 0 PV 0,034 62 P 12.0 from 0.75 0.95 29.0 9 four 17 75 0 PV 0,034 40 to 12.0 from 0.59 0.67 35.0 10 four 10 75 0 PV 0,034 40 to 12.0 from 0.86 0.85 88.0 eleven four fifty 75 0 PV 0,034 80 to 1.7 from 0.50 1.00 30,0 12 four 75 25 0 MB 12,000 60 pg 12.0 from 0.60 1.00 0,0 13 four 25 75 0 MB 12,000 60 pg 12.0 from 0.77 1.10 0,0 fourteen 5 fifty fifty 0 Hcl 14,500 60 pg 12.0 from 0.37 1.16 16.6 fifteen 5 10 90 0 Hcl 14,500 40 to 12.0 from 0.34 1,60 15.0 16 four 97 3 0 Hf 70,000 60 P 12.0 from 1.30 0.84 0,0 17 four 25 75 0 Hf 70,000 60 P 12.0 from 1.20 0.78 0,0 eighteen four 9 91 0 GK 15,000 60 pg 1.7 from 0.61 0.71 0,0 19 3 fifty fifty 0 ShchSPK 32,000 40 P 12.0 from 0.36 0.86 33.3 twenty 3 fifty fifty 0 ShchSPK 32,000 40 to 12.0 from 0.44 0.35 0,0 21 3 fifty fifty 0 ShchSPK 32,000 60 P 12.0 from 0.75 0.80 14.3 22 four fifty fifty 0 Pshch 33,000 80 pg 1.7 from 0.37 0.51 0,0 23 four fifty fifty 0 Pshch 33,000 60 pg 12.0 from 0.30 0.80 10.5 24 four fifty fifty 0 Pshch 33,000 40 to 12.0 from 0.60 1.00 71,4 25 four fifteen 10 75 Pshch 33,000 60 P 12.0 from 0.60 0.86 11.7

one 2 3 four 5 6 7 8 9 10 eleven 12 13 fourteen 26 four thirty twenty fifty Pshch 33,000 80 pg 1.7 from 0.60 1.00 0,0 27 four 5 5 90 Pshch 33,000 80 pg 1.7 c 0.54 1.30 0,0 28 four 6 four 90 Pshch 33,000 40 P 12.0 from 0.71 0.91 33.3 29th four 67 33 0 Pshch 33,000 60 P 12.0 from 0.52 0.74 11.1 thirty four 33 67 0 Pshch 33,000 60 P 1.7 from 0.25 0.75 11.7 31 5 33 17 fifty Pshch 33,000 80 pg 1.7 from 0.51 0.68 0,0 32 5 17 9 74 Pshch 33,000 80 pg 1.7 from 0.25 0.60 0,0 Known Reagents and Methods 33 VRA one hundred 0 0 0 0 60 P 12.0 P 1.00 1.10 23.0 34 VRA one hundred 0 0 0 0 60 to 12.0 P 0.92 1.30 10.0 35 VRA 10 90 0 PV 0,034 40 to 12.0 from 0.81 1.00 21.0 36 VRA 75 25 0 MB 12,000 60 pg 12.0 from 1.20 1.40 0,0 37 VRA fifty fifty 0 Hcl 14,500 60 pg 12.0 from 0.75 1.10 12.0 38 VRA 9 91 0 GK 70,000 60 pg 1.7 from 0.65 0.83 0,0 39 VRA 97 3 0 Hf 15,000 60 P 12.0 from 1.70 1.10 0,0 40 VRA fifty fifty 0 ShchSPK 32,000 40 P 12.0 from 1.40 0.90 18.0 41 VRA fifty fifty 0 Pshch 33,000 40 to 12.0 from 1.85 1.10 26.0 42 ShchSPK 32,000 40 P 12.0 2.60 1.40 18.0 43 Pshch 33,000 40 to 12.0 3,50 1.80 21.0

Table 3 The method of using MRSA with organic solvents (example 2) Experience number No. of batch MRSA according to table 1 The content of MRSA in the mixture,% wt. Solvent The temperature of the experiment, ° C Breed type The salt content in the pollutant,% wt. The method of combining reagents Growth by Δη _n ,% of residual oil name 1) content,% wt. water oil one 2 3 four 5 6 7 8 9 10 eleven 12 The proposed reagent and method one four one hundred COBS one hundred 40 to 12.0 P 0.67 1.00 29.0 2 four one hundred KORB one hundred 40 to 12.0 P 0.38 0.96 39.0 3 four one hundred ShFLU one hundred 40 to 12.0 P 0.43 0.59 38.5 four 5 97 SFPK 3 80 P 1.7 from 0.68 0.76 16.6 5 5 97 SFPK 3 60 P 12.0 from 0.65 0.83 6.5 6 5 one hundred IPOD one hundred 60 P 12.0 P 0.72 0.88 20,0 Known method 7 VRA one hundred IPOD one hundred 60 P 12.0 P 1,50 1.00 18.0 8 VRA 95 SFPK 5 80 P 1.7 from 1.20 0.90 19.5 Individual reagents 9 COBS one hundred 40 to 12.0 0.80 1.20 8.0 10 KORB one hundred 40 to 12.0 1.00 1.30 18.0 eleven ShFLU one hundred 40 to 12.0 1.10 0.90 15.0 12 IPOD one hundred 60 P 12.0 0.90 1.40 5,0 13 SFPK one hundred 80 P 12.0 1.10 1.00 8.0 1) COBS - distillation residue of butyl alcohols, KORB - VAT residue of benzene retification, NGL - a wide fraction of light hydrocarbons, SFPK - alcohol fraction of caprolactam production, MPOD - POD-refined oil

Table 4 Method of using MRSA in combination with several different reagents (example 4) Experience number No. of batch MRSA according to table 1 The content of MRSA in the mixture,% wt. Aqueous electrolyte solution Solvent Temperature Breed type The salt content in the pollutant,% wt. The method of combining various reagents Growth by Δη _n ,% of residual oil name the electrolyte content,% wt. name content,% wt. water oil one 2 3 four 5 6 7 8 9 10 eleven 12 13 fourteen The proposed method one four 16.6 PV 0,034 ShFLU one hundred 80 to 1.7 s / n 0.51 0.93 20,0 2 four 16.6 PV 0,034 ShFLU one hundred 40 to 12.0 s / n 0.48 0.98 26.3 3 four 16.6 PV 0,034 KORB one hundred 40 to 12.0 s / n 0.31 1,07 37.0 four four 25.0 PV 0,034 COBS one hundred 40 to 12.0 s / n 0.40 0.66 31.9 5 5 25.0 PV 0,034 COBS one hundred 60 P 12.0 s / n 0.58 0.85 20,0 6 5 25.0 PV 0,034 COBS one hundred 60 pg 12.0 s / n 0.59 0.95 8.3 7 four 25.0 PV 0,034 SHFLU + KORB 67 + 33 60 pg 12.0 s / n 0.49 1.00 27.7 8 5 25.0 MB 1.7 COBS one hundred 82 pg 1.7 s / n 0.91 1.00 45,2 9 5 25.0 MB 1.7 ShFLU one hundred 82 pg 1.7 s / n 1,07 1.31 48.0 Known method 10 VRA 16.6 PV 0,034 ShFLU one hundred 40 to 12.0 s / n 0.80 1.10 12.0 eleven VRA 25.0 PV 0,034 COBS one hundred 40 to 12.0 s / n 1.00 1.30 18.0 12 VRA 25.0 MB 1.7 ShFLU one hundred 82 pg 1.7 s / n 1.20 1.70 26.0

Claims (2)

1. The use of a mother liquor of ammonium sulfate from a stripping of an aqueous acidic effluent from the production of caprolactam containing at least 41 wt.% Dry residue, at least 2.1 wt.% Amino acids in terms of aminocaproic acid and having a pH above 4.4, as a reagent for treating an oil reservoir. 2. A method of treating an oil reservoir using a reagent according to claim 1, characterized in that the reagent according to claim 1 is injected into the zone of the oil reservoir with an aqueous electrolyte solution and / or with an organic solvent, while the chemicals are pumped into the reservoir in the order and combinations determined by the state of the bottom-hole zone of the wellbore.