Reagent for treating oil reservoir and method of using said reagent

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

 

The invention relates to the oil industry, in particular reagents for processing oil reservoir and to a method of bottomhole zone treatment to improve the productivity of producing and injection wells, as well as for completion of wells, and is intended for use in the development and exploitation of oil deposits, composed of terrigenous and carbonate rocks.

It is known ([1], Christian M., Sokol, S., Constantinescu A. Increase productivity and injectivity of the wells. M., Nedra, 1985, p.9-10)that one of the factors that significantly affect the productivity and injectivity of wells is the capillary pressure, water retention in the bottomhole formation zone (PPP) of the production well or oil in the PPP injection wells. The higher capillary pressure, the lower the productivity of wells.

where

Pwith- the capillary pressure, MPa,

σ is the interfacial tension between oil and water phase, mn/m,

the cosine of the contact angle of the breed aqueous phase and oil,

r is the average radius of the pores of the rock, m

In terms of flooding of the oil reservoir Rwithhigh not only due to the large σ on the boundary of the oil - water (28-32 mn/m), but also by the magnitude of r, due to the adsorption film of oil and asphaltenes parafinovykh deposits - ASPO on the rock formation, swelling clay component species and the presence of mechanical mudding. To improve the performance of injection and production wells is necessary to remove the residual oil and the capillary-held water from the PPP wells, respectively. The latter is achieved when Pwith→0, but rather at low σ (less than 0.1 mn/m), or when≈0, i.e≈90° - oil and water don't moisten the formation rock, and with increasing r the rock pores. For σand r is significantly affected by surface-active substances (surfactants), organic solvents and aqueous solutions of electrolytes - inorganic and organic salts, acids and bases (alkalis).

It is known the use of anionic, nonionic and cationic surfactants for enhanced oil recovery ([2] Ibragimov GS, Fazlutdinov K.S., Tran N the Use of chemical reagents for enhanced recovery of oil. Handbook, M., Nedra, 1991, p.129). However, the efficiency for processing bottom-hole zone (OPZ) wells low due to the large interfacial tension of aqueous solutions data surfactants on the border with oil (σ>0,5 mn/m) and cos>0.

The closest analogue to the proposed invention is the use of an aqueous solution of resin (HRV) from parki water-acids the CSO flow of caprolactam - aqueous ampholytic surfactants for the intensification of injection and production wells ([3] RF patent 2314332, EV 43/22). However, this reagent is not effective in a wide range of geological and physical properties of the reservoir (temperature, nature of the rock collector and salt content in the injected and formation waters).

The known method OPZ wells using VRS with an aqueous solution of electrolytes, and/or an organic solvent in various combinations [3]. However, this method is the same drawback as that of the VRS. The reason for this is that HRV and its combination with electrolytes and organic solvents, as wetting the rock collector, do not provide reliable achievement≈90° and, respectively, Pwith→0 F.1 because of the difficulty of achieving optimal hydrophilic-lipophilic balance (products HLB) molecules ampholytic surfactant included in the composition, in which Rwith→0.

The objective of the invention is the expansion of the range of surface-active substances for the treatment of bottom-hole zone of the oil reservoir and creating an efficient method of processing bottom-hole zones of oil reservoir with its use, allowing you to extend the interval efficiency SCR, geological and physical properties of the layer.

The problem is solved in that, as a reagent d is I the bottomhole zone treatment oil reservoir using the mother solution of ammonium sulfate (MRSA) from parki water and acid runoff production of caprolactam, containing not less than 41 wt.% the solids not less than 2.1 wt.% aminosalicyclic acids in terms of aminocaproic acid and having a pH environment above the 4.4. The task is also solved by creating a processing method of the bottomhole zone of oil formation comprising pumping into the bottom zone of the oil reservoir, MRSA and with an aqueous solution of electrolytes, and/or an organic solvent, and the chemicals pumped into the reservoir in order and combinations determined by the condition of the bottom-hole zone of the well.

The mother solution of ammonium sulfate is a side (secondary) of the product of large-scale production of caprolactam by the method of oxidation of cyclohexane ([4] the Production of caprolactam. Ed. Ovchinnikov V., Rokicki V.R. M, Chemistry, 1977, s). Currently MRSA is not used anywhere and it is subjected to a thermal treatment, i.e. burn in the zone of fire of the torch.

Analysis of MRSA various parties of the selection of the composition showed that it contains not less than 41 wt.% the solids and not less than 2.1 wt.% aminosalicyclic acids in terms of aminocaproic acid NH2(CH2)5COOH and has a pH above the 4.4 (see table 1). The dry residue is a mixture of aminoalkanoic acids and ammonium sulfate.

Thus, MRSA is an aqueous solution mainly ammonium sulphate and aminosalicyclic acids - low the molecular (nicolaides) ampholytic surfactant wetting type, containing in the molecule at the same time basic (amino - NH2) and acidic (carboxyl - COOH) group.

MRSA as HRV used on the prototype [3], is formed by Parke water and acid runoff caprolactam production. Since the density of MRSA (1.18 to 1.24 g/cm3) higher than the density of HRV (of 1.08-1.12 g/cm3), MRSA is at the bottom, and HRV in the upper part of the separating apparatus. Due to the high concentration of ammonium sulfate in MRSA (above 35% wt.) all condensation products of amino acids (resin) Myslivets from MRSA and form the top layer - HRV with a low content of ammonium sulfate. Thus, in HRV are high-molecular ampholytic surfactants wide molecular mass distribution (tar), and MRSA - low-molecular ampholytic surfactants narrow molecular weight distribution, mainly aminocaproic acid (ACC), which dissolves in the brine of ammonium sulfate. The difference in molecular weight and its distribution ampholytic surfactants, located in MRSA and HRV, causes the difference in their surface-active properties in relation to the breed-manifold and displaced oil, and therefore in their efficiency of oil displacement. When this ACC, located in MRSA is colloidal surfactants, i.e. does not form micelles in solution (in contrast to colloidal surfactants, forming the IIC is lly) and belongs to the group of surfactants-wetting. These surfactants weakly adsorbed at the interface of a solution of surfactant - oil (have a high interfacial tension σn/a), but actively adsorbed on a solid surface under different conditions (temperature, salt content in the solution, the nature of the surface), in particular on the breed of the oil reservoir, changing its wettability. And, as shown by laboratory studies, MRSA change the surface wettability of the reservoir rock close to neutral wettability, i.e. up to Θ≈90° or cos Θ≈0 and, respectively, Pwith→0. Thus, unlike the HRV MRSA is a more effective reagent that modifies the wettability of the surface rocks of the oil reservoir to the water and oil phases, saturating the layer.

The use of the mother liquor of ammonium sulfate from parki water and acid runoff caprolactam production in the oil industry is unknown and the reagent according to the mechanism of displacement of oil from the oil reservoir is significantly different from the known surface-active substances used in the production of oil.

For processing bottom-hole zones of oil reservoir wells, MRSA used in combination with the aqueous electrolyte solution, and/or an organic solvent, is injected into the reservoir in the manner and amount prescribed by the state of the bottom-hole zone of the well (residual in the up - and-saturation, the magnitude of the skin effect, the nature of the breed-manifold type wells etc). When the electrolyte is one or a mixture of two or more substances dissociate in ions in their aqueous solution.

This way 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 temperatures and salinity of the waters in various rocks of the reservoir by maintaining cosΘ→0, the proposed method when using these reagents.

To perform the method of the SCR using MRSA with the aqueous electrolyte solution by consecutive injection or by downloading them in a mixture, apply the following electrolytes:

aqueous solution of inorganic salts, for example water flooding of oil reservoirs on the EAST 39-225-88 with a total salt content from 0,034 to 24 wt.%;

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

alkaline electrolytes, such as sodium carbonate (soda ash) according to GOST 5100-85, or alkaline runoff of caprolactam - (AEA on THE 113-03-488-84 changes is the 1, 2, or surface-active alkaline composition PSS on THE 2432-025-00205311-03 containing sodium carbonate and water-soluble salts of organic acids and having a pH above 10.

The way the SCR using MRSA with an aqueous solution of inorganic salts allows to obtain a mixture with various content of MRSA either directly in the layer in a sequential cyclic pumping or mixing them prior to injection into the formation, for example, by dosing MRSA in water, which is pumped into the reservoir. When mixing MRSA with water containing a calcium cation, formed a suspension of crystalline gypsum, the surface of which is modified ACC. This residue creates resistance in the area of education, which redistributes the flow of the injected reagents and water in less permeable interlayer, usually saturated, thereby increasing the enrolment rate deposits flooding along with increasing the ratio of oil displacement by changing the wetting of the breed to Θ~90°. Thus the method of the SCR using MRSA and aqueous solutions of inorganic salts allows you to increase the rate of oil recovery and in contrast to the known technical solutions [2, 3] is a significant difference and novelty as the mechanism of oil displacement and machinery coverage of the oil reservoir effect of reagents and water.

SPO is about SCR using MRSA with inorganic acids allows to obtain acidic cationic surface-active composition by the reaction of NH 2(CH2)5COOH+H+→NH3+(CH2)5COOH or in formation with sequential injection into the borehole, or by mixing them prior to injection into the reservoir. This method OPZ using MRSA acid allows you not only to remove residual oil film, oil and asphaltoresinparaffin deposits - deposits) from the surface of rocks and inorganic mudding (clay, sand, slag and other), but also due to this effect to improve the access of the acid to the surface of mudding and rock and reaction with them. The use of MRSA acid provides easier removal of reaction products and impurities from PPP due to wetting and surface-active properties and their increased permeability rocks of the PPP, and accordingly, productivity of the well.

The way the SCR using MRSA with alkaline electrolytes can be obtained alkaline anionic surface-active composition by the reaction of NH2(CH2)5COOH+HE-→NH2(CH2)5COO-+H2O either in the reservoir during successive injection into the borehole, or by mixing them prior to injection into the reservoir. In addition, when mixing MRSA with an alkaline electrolyte containing a water-soluble organic acid salts, in particular sodium adipate (AEA and PSS formed water-soluble associates is aparatow NH 2(CH2)5COO-with adipinate-OOS (CH2)4Soo-due to the interaction of the partial positive charge of the amino group (-NH2) negatively charged carboxyl group (-COO-).

[-OOS (CH2)5NH2δ+...-OOS (CN)4Soo-]

These associates have dimensions comparable with the cross section of the pores and narrow pore, which causes resistance to flow of the mixture of MRSA and alkaline electrolyte in a porous medium layer, i.e. the mixture has not only a surfactant, and rheological properties, and, accordingly, the method of the SCR using MRSA with alkaline electrolytes containing salts of organic acids, allows not only to effectively displace the oil from the PPP, but also working to increase the thickness of the productive formation due to the rheological properties of mixtures thereof.

Thus, the method OPZ well 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] is a significant difference and novelty as the mechanism of oil displacement and machinery coverage of the thickness of the layer of the PPP impact of reagents and water.

For complete method OPZ well with MRSA with organic solvent can be used, for example, the following solvents:

- alcohol-based solvents such as solvent SFPR (alcohol fraction production of caprolactam) TU 2433-017-002-05311-99 with total content of alcohols of not less than 40 wt.%; the oil is purified by THE 2433-016-00205311-99 with total content of alcohols of not less than 57%by weight; VAT residue of butyl alcohols production on THE 38-1021167-85 with total content of alcohols of not less than 52 wt.%;

- hydrocarbon solvents, such as rangatiratanga oil, hexane fraction on THE 38-10388-83, wide fraction of light hydrocarbons (NGL) TU 38-101524-83, the distillate and the condensation products of primary processing of oil on UKPN oil fields.

The use of solvents with MRSA how to mix them, and by consecutive injection in their PZP well improves oil-driving properties of MRSA and, accordingly, increases the productivity of the well.

The use of hydrocarbon solvent with MRSA helps to remove the film and drip viscous oil and paraffin due to the formation of highly active mix them into the reservoir to improve the subsequent effects of acid treatment on the breed of the PPP injection wells and improves permeability for reservoir oil in the PPP of the production well. Such a complex effect of MRSA with an organic solvent improves the performance of wells and has the substantial difference from the known analogues.

Suggested ways SCR wells using MRSA can be applied in commercial practice, both separately and in various orders and combinations between them depending on the state of the PPP specific wells and objectives OPZ specific wells, with and without the use of pressure pulses (explosive perforation, termoliticheskogo impact etc) and depression or pulse depression at PPP (inkjet, ejector pumps brands CSS-1, WEOS etc).

The proposed reagent MRSA and method for processing bottom-hole formation zone with its use have been tested in laboratory conditions in comparison with known surfactants and methods of their use in oil production.

The effectiveness of MRSA and ways to assess for residual fact resistance to water and oil and oil-driving ability on a bulk linear model of the reservoir length 12-14 cm and 2.5 cm in diameter with a pressure measurement at the inlet and in the middle of the model. Experiments are performed on Sandstone (P), carbonate (K) and Pensilvania Sandstone (5% bentonite clay) (PG) at a temperature of 20-90°C with the use of injected water (SV)containing 0,034-of 24.0 wt.% a mixture of salts (electrolytes) by the following method. The model layer is saturated with formation water density of 1.17 or 1.04 g/cm3(24,0 and 4.0 wt.% the mixture of salts), followed by oil with a viscosity of 10.2 and 1.7 MPa·s to nesnera is my water saturation and injected water to residual oil saturation. Then in the model pumped with 0.9-1.1 pore volume model of the test reagent or reagents sequentially (P) or after mixing (C) and 3 pore volume model of the injected water and oil of the same viscosity. Oil-driving ability is determined by the ratio of the amount of oil displaced by the reagents, the amount of oil remaining after the flooding model (Δη, % residual oil), and the change in the wettability of the cores - residual resistance factor (Rin/n OSTin the midpoint of the model when pumping the injected water and oil after reagents, calculated by the formula:

where Ro and P is the pressure at the midpoint of the core when pumping water or oil before and after injection of reagents, ATM.

When Rin/nOST less than 1 improves the mobility of either oil or water, and if Rin/nOST the experience less than 1 for both water and oil, in this experiment, the wettability of the rock close to neutral, i.e≈90°C.

Example 1. Table 2 shows the results of experiments using the above technique with samples of MRSA various parties (see table 1) in combination with the aqueous electrolyte solution (neutral, acidic and alkaline) in comparison with the known solutions of the reagent - aqueous ampholytic surfactants (BPA) TU 2431-024-00205311-03 (prototype [3]).

From the data of table 2 shows that all the samples of the PCA and their mixtures with aqueous solutions of inorganic salts (fresh - PV and mineralized water - MB), inorganic acids (hydrochloric - HCl, hydrogen fluoride - HF and pinacolato - GK) and alkalis ((AEA and PSS) in freshwater (FW) and saltwater (MB - 12,0% wt. salt) waters more effective as a wetting any breed in a wide temperature range (40-90°C) and salinity of the injected water (SV) (1,7 to 12.0 wt. -%), than a known reagent BPA (prototype [3]) (cf. R. water and oil experiments 1-6 for MRSA with experiments 33-34 for BPA, experiments 7-13 with experiments 35 and 36 for mixes them with a solution of inorganic salts, experiments 14-18 with experiments 37-39 for their mixtures with inorganic acids and experiments 19, 24 with experiments 40-43 for their mixtures with alkali). The factors of resistance as the water and oil in 75% of the experiments is 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. On this basis, MRSA and its mixture with electrolytes is most effective for the stimulation of water injection into wells and oil production from producing wells.

Efficiency to displace residual oil after water flooding of the reservoir, MRSA also more effective than the ENEMY (see above reference).

Thus, MRSA and its mixture with electrolytes is effective for treatment of bottom-hole formation zone of the wells with the purpose of intensification of their work, and to improve oil recovery by pumping them into the reservoirs through on letatelnyy well.

Example 2 illustrates the effectiveness of the use of MRS in combination with organic solvents, as defined by the above technique. In experiments with sequential injection (P) of the reactants in the core organic solvent was pumped before MRSA in the amount of 0.1 pore volume. The results of the experiments are shown in table 3, which shows that the solvents increase oil-driving ability MRSA as sequential injection into the formation model (experiments 1, 3-6)and their mixtures (experiments 4, 5) (cf. experiments 1-3 with experience 4 table 2, experiments 5 and 6 experience 5 table 2). At the same time, MRSA in combination with an organic solvent also shows the wetting ability to the neutral (cos≈0 when ROST<1)as MRSA than the known method with the use of BPA [3] (cf. experiments 4 and 6 with experiments 8 and 7 respectively) and a separate reagents, solvents (cf. experiments 1-6 with experiments 9-13).

Thus, MRSA in combination with organic solvents exhibits a synergistic effect, since technological efficiency in 2 and more times higher than that of the individual reagents.

Example 3 illustrates the effectiveness of MRSA in combination with several different reagents, for example a mixture of MRSA freshwater (F) or saline (M) waters and various classes of solvents injected before this cm is sue in the amount of 0.1 pore volume of the core according to the aforementioned method. In table 4 the results of experiments on the proposed method and the known. They show that the integrated method with MRSA (experiments 1-9) more efficient than the known method (experiments 10-12) (compare experiments 2, 4 and 9 with experiments 10, 11 and 12, respectively).

Thus, MRSA and the way to use it and in various combinations with aqueous solutions of electrolytes and organic solvents increase the efficiency of the SCR wells in a wide range of geological and physical properties of the reservoir (temperature of the formation, the nature of the rock collector and salt content in the injected and formation waters) in comparison with the known methods OPZ wells using BPA and, accordingly, anionic, nonionic surfactants and mixtures thereof.

The claimed technical solution efficiently and industrially applicable.

The use of MRSA and method of processing bottom-hole formation zone of wells with its use in the oil industry can improve the efficiency of wells in different geological and physical conditions of the oil reservoir at different stages of development; to dispose of the chemical production waste, which will improve the ecological situation of production; the use of standard techniques in the production of commercial operation.

MRSA and how using it can also be applied to improve defeatd the Chi reservoir through periodic (cyclic) upload them to the injection and producing wells oil field in combination with water (flow) humanesociety (hydrocarbon emulsion, water-stitched and unstitched polymer compositions, sedimentation and other structures) or without them.

Table 1
Composition and physico-chemical properties of MRSA various parties
MRSA no partyContent, wt.%d, g/cm3σ, mn/mpH
the dry residueaminoalkanoic acid 1)ammonium sulfate
1462,343,71,219,14,4
2482,145,91,21-4,4
3452,842,21,20the 3.84,5
448of 5.442,61,212,5the 4.7
5413,1of 37.91,203,54,6
1) in terms of aminocaproic acid

Table 2
The use of MRSA with aqueous solutions of electrolytes (example 1)
no experienceno party on table 1MRSA and its content in the mixture, % wt. with a solution of electrolytesAn aqueous solution of electrolytesPace
the temperature of the experience, °C
Breed typeThe salt content in SV, wt.%The method of combination of reagentsRΔηnas a % of residual oil
MRSAan aqueous solution of electrolyteswatertitle
of
the electrolytes wt.%.wateroil
1234567891011121314
The proposed reagent and method
11100000060pto 12.0p0,760,900,0
23100 000060pto 12.0p0,700,800,0
35100000060pto 12.0p0,871,000,0
44100000040toto 12.0p0,790,780,0
5410000 0090to1,7p0,700,3015,0
64100000063toto 12.0p1,600,0059,0
7425750PW0,03463toto 12.00,650,570,0
8425750PW0,034pto 12.00,750,9529,0
9417750PW0,03440toto 12.00,590,6735,0
10410750PW0,03440toto 12.00,860,8588,0
11450750PW0,03480to 1,70,501,0030,0
12475250MB12,00060PGto 12.00,601,000,0
13425750MB12,00060PGto 12.00,771,100,0
14550500HCl14,50060PGto 12.0 0,371,1616,6
15510900HCl14,50040toto 12.00,341,6015,0
1649730HF70,00060pto 12.01,300,840,0
17425750HF70,00060pto 12.01,200,78 0,0
1849910GK15,00060PG1,70,610,710,0
19350500(AEA32,00040pto 12.00,360,8633,3
20350500(AEA32,00040toto 12.00,440,350,0
21/td> 350500(AEA32,00060pto 12.00,750,8014,3
22450500PDS33,00080PG1,70,370,510,0
23450500PDS33,00060PGto 12.00,300,8010,5
244 50500PDS33,00040toto 12.00,601,0071,4
254151075PDS33,00060pto 12.00,600,8611,7

1234567891011121314
26430 2050PDS33,00080PG1,70,601,000,0
2745590PDS33,00080PG1,7c0,541,300,0
2846490PDS33,00040pto 12.00,710,9133,3
29467330PDS 33,00060pto 12.00,520,7411,1
30433670PDS33,00060p1,70,250,7511,7
315331750PDS33,00080PG1,70,510,680,0
32517974PDS33,00080PG 1,70,250,600,0
Known reagents and methods
33BPA100000060pto 12.0p1,001,1023,0
34BPA100000060toto 12.0p0,921,3010,0
35BPA10900PW0,03440toto 12.00,811,0021,0
36BPA75250MB12,00060PGto 12.01,201,400,0
37BPA50500HCl14,50060PGto 12.00,751,10to 12.0
38BPA9910GK70,00060PG1,70,650,83 0,0
39BPA9730HF15,00060pto 12.01,701,100,0
40BPA50500(AEA32,00040pto 12.01,400,9018,0
41BPA50500PDS33,00040toto 12.01,851,1026,0
42 (AEA32,00040pto 12.02,601,4018,0
43PDS33,00040toto 12.03,501,8021,0

Table 3
The use of MRSA with organic solvents (example 2)
no experienceno party MRSA on table 1The content of MRSA in the mixture, wt.%SolventThe temperature of the experience, °CBreed typeThe method of combination of reagentsRΔηnas a % of residual oil
name 1)content, % wt.wateroil
123456789101112
The proposed reagent and method
14100COBS10040toto 12.0p0,671,0029,0
24100KORB10040to 12.0p0,380,9639,0
34100NGL10040toto 12.0p0,430,59a 38.5
4597SFPR380p1,70,680,7616,6
5597SFPR360pto 12.00,650,836,5
65100 NOD10060pto 12.0p0,720,8820,0
The known method
7BPA100NOD10060pto 12.0p1,501,0018,0
8BPA95SFPR580p1,71,200,9019,5
Individual reagent
9COBS10040to to 12.00,801,208,0
10KORB10040toto 12.01,001,3018,0
11NGL10040toto 12.01,100,9015,0
12NOD10060pto 12.00,901,405,0
13SFPR 10080pto 12.01,101,008,0
1) KOBS - VAT residue butyl alcohol,
KORB - CBM balance ratificatio benzene,
NGL - wide fraction of light hydrocarbons
SFPR - alcohol fraction of caprolactam,
MPOD - oil-cleaned

s/p
Table 4
The use of MRS in combination with several different reagents (example 4)
no experienceno party MRSA on table 1The content of MRSA in the mixture, wt.%An aqueous solution of electrolyteSolventTemperatureBreed type The salt content in SV, wt.%The method of combination of different reagentsRΔηnas a % of residual oil
namethe content of the electrolyte, % wt.namecontent, % wt.wateroil
1234567891011121314
The proposed method
1416,6PW0,034NGL10080to1,7 s/p0,510,9320,0
2416,6PW0,034NGL10040toto 12.0s/p0,480,9826,3
3416,6PW0,034KORB10040toto 12.0s/p0,311,0737,0
4425,0PW0,034COBS10040toto 12.00,400,6631,9
5525,0PW0,034COBS10060pto 12.0s/p0,580,8520,0
6525,0PW0,034COBS10060PGto 12.0s/p0,590,958,3
7425,0PW0,034NGL + KORB67+3360PG to 12.0s/p0,491,0027,7
8525,0MB1,7COBS10082PG1,7s/p0,911,0045,2
9525,0MB1,7NGL10082PG1,7s/p1,071,3148,0
The known method
10BPA16,6PW0,034NGL40toto 12.0s/p0,801,10to 12.0
11BPA25,0PW0,034COBS10040toto 12.0s/p1,001,3018,0
12BPA25,0MB1,7NGL10082PG1,7s/p1,201,7026,0

1. The use of the mother liquor of ammonium sulfate from parki water-acid drain of caprolactam containing not less than 41 wt.% the solids not less than 2.1 wt.% uminoor hanicheskih acids in terms of aminocaproic acid and having a pH above 4,4, as a reagent for processing oil reservoir.

2. The method of processing oil reservoir using the reagent according to claim 1, characterized in that in the zone of the oil reservoir pump the reagent according to claim 1 and an aqueous solution of electrolyte, and/or an organic solvent, and the chemicals pumped into the reservoir in order and combinations determined by the condition of the bottom-hole zone of the well.



 

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24 cl

FIELD: oil and gas production.

SUBSTANCE: method of bottom-hole zone treatment of low-permeable terrigenous formation according to the first version consists in flushing of killed well, sequential pumping of methanol, 18-20% solution of hydrochloric acid for acid bath installation, then the well is repeatedly pumped by 18-20% solution of hydrochloric acid and buffer-gas condensate, acid composition is squeezed into bottom-hole zone of formation by inert gas, then mud acid solution is pumped, gas influx from formation is caused and then reaction products are removed together with gas flow, the well is treated through flare line with removal of reaction products till it reaches design conditions and then the well is placed under production. Method of bottom-hole zone treatment of low-permeable terrigenous formation according to the second version consists in sequential pumping of methanol, 18-20% solution of hydrochloric acid and buffer-gas condensate into non-killed well through tubing casing, acid composition is squeezed into bottom-hole zone of formation by inert gas, then mud acid solution is pumped, gas influx from formation is caused and then reaction products are removed together with gas flow, the well is treated through flare line with removal of reaction products till it reaches design conditions and then the well is placed under production.

EFFECT: recovery of gas-hydro-dynamic connection of well with low-permeable and highly colmataged terrigenous productive formation in condition of abnormally low formation pressure.

2 cl

FIELD: oil and gas production.

SUBSTANCE: method of formation face zone development consists in pumping the gas-generating and acid-based reagents, where gas-generating reagent is the compound that includes, wt %: urea 28.4-38.4, sodium nitrite 18.2-27.6, water - the rest, and acid-based reagent is the compound that includes, wt %: inorganic acid 5.2-60.9, surface acting agent 2.4-3.5, ferrum inhibitor 1.4-2.3, flotation agent 7.0-11.4, water - the rest. Note that the proportion of gas-generating and acid-based reagents amounts 1:(1-3), after pumping of the reagents they are held.

EFFECT: increase of injection capacity of intake well and influx to the producing wells, start of development of leak-proof zones not covered by influence.

3 cl, 2 tbl, 2 ex, 1 dwg

FIELD: oil and gas industry.

SUBSTANCE: method for control of flooding area of oil formations includes oil extraction through production wells and pumping of margins of working agent and silicate in water phase with varying concentration of components trough injection wells. At that watering out of produced oil, capacity of injection wells, allowable pumping pressure and minimal pumping pressure are additionally checked. Pumping is started from injection wells of high capacity, connected hydrodynamicly to highly watered out production wells. At least one injection well is stopped till formation pressure is decreased by 6-24% from formation pressure in area of injection well. Pumping of working agent is started from composition of high-viscosity in quantity not less than 0.5 m3 per 1 m of productive formation with high capacity under pumping pressure exceeding minimal pumping pressure not more than by 20%, at which well accepts. Then margins of water solution of alkaline silicate and polymer are pumped in succession or jointly. Solution of alkaline silicate is used in quantity 0.1-15.0 wt %, and polymer is used in quantity 0.001-3.0 wt %, the other part of solution is water.

EFFECT: increasing oil recovery from formations.

4 cl, 3 ex

FIELD: oil and gas industry.

SUBSTANCE: method includes stages at which cloudy treating fluid with primary microbial population is provided. The fluid is placed in self-contained road mobile manifold of treatment by ultra-violet, which contains source of ultra-violet. Cloudy treating fluid is treated using source of ultra-violet in the presence of weakening reagent to form irradiated treating fluid. Then irradiated treating fluid is supplied to mixing system. Mobile system of treating fluid treatment by ultra-violet contains inlet device, source of treating ultra-violet, chamber for treatment by ultra-violet, weakening reagent, outlet device. At that system of treating fluid treatment by ultra-violet is transported using self-contained road mobile platform.

EFFECT: increasing efficiency of treating fluids disinfection.

12 cl, 2 tbl, 8 dwg

FIELD: oil and gas industry.

SUBSTANCE: well treatment method involves introduction to the well of treatment liquid containing polymer, binder, organic peroxide, soluble amine connection and functional dilution retarder, where soluble amine connection has chemical structure R3R4N((CR5R6)2-NR7)n-R8, in which n is equal to 2 to 8 and in which R3, R4, R5, R6, R7 and R8 are chosen independently from each other from hydrogen, alkyl, hydroxyalkyl and their combinations, where mass ratio of soluble amine to organic peroxide is approximately 1:1 to approximately 20:1; and treatment liquid dilution. Invention has been developed in dependent claims.

EFFECT: increasing monitoring efficiency of viscosity reduction.

16 cl, 15 ex, 15 dwg

FIELD: process engineering.

SUBSTANCE: invention relates to underground processing of formations. Proposed method comprises preparing fluid for processing formation containing water and copolymer reducing friction consisting of acrylamide in amount of 80 wt % to 90 wt % and acrylic acid in amount of 10 wt % to 20 wt %, and feeding it into underground formation. It comprises also preparing copolymer oil emulsion containing water, fluid non-miscible with water and aforesaid copolymer, combining emulsion with additional water for producing water fluid for formation processing, inverting emulsion so that said copolymer is released into water fluid to be forced into underground formation. proposed method comprises preparing copolymer oil emulsion containing water, fluid non-miscible with water containing mix of paraffin hydrocarbons and naphthenic hydrocarbons, emulsifier containing diethanolamide of fat acids of tall oil, monooleat of sorbite polyoxyethylene and sorbite monooleat, above specified copolymer and ammonium salt, 4-metoxyphenol and etoxylated alcohol C12-C16, combining said emulsion with additional water, inverting said emulsion so that copolymer reducing friction is forced into formation.

EFFECT: higher efficiency of reducing friction.

23 cl, 1 ex, 3 tbl

FIELD: chemistry.

SUBSTANCE: invention relates to oil industry, particularly to a composition for sealing influx of water into a well. The composition for sealing influx of water into a well contains an organosilicon compound - product 119-296, a curing agent - titanium (IV) chloride, polyglycols, Devonian stratal water and oligophenyl ethoxy siloxane (OPES) in the following ratio, wt %: product 119-296 40.5-61.5, OPES 15.0-25.0, TiCl4 3.5-4.5, polyglycols 20.0-30.0, wherein the Devonian stratal water is taken in ratio of 1:1 to the weight of the rest of the reagents of the composition.

EFFECT: high efficiency of sealing water influx owing to higher strength of the composition, longer inter-repair period of the well, which enables to save repair materials 1,5-fold.

1 ex, 1 tbl

FIELD: chemistry.

SUBSTANCE: invention relates to compositions for sealing influx of formation water into oil, gas and oil-and-gas wells and can be used in oil-and-gas industry. The backfilling composition for selective sealing of influx of formation water contains the following, wt %: gel-forming clay - bentonite 5.5 - 7.5, filler - expanded-clay powder 5.5-7.5, sodium silicate - liquid glass with density 1500±20 kg/m3 35-45, sodium silicofluoride 3.5-4.5, alkali metal carbonate 0.5 - 1.5, alkali metal chromate 0.05-0.09, CMC-Na 0.3-0.5, fresh water - the balance.

EFFECT: high efficiency of sealing water influx.

4 tbl

FIELD: oil and gas industry.

SUBSTANCE: above described formation is brought into contact with fluid medium, where fluid medium is at least the medium which at least partially dissolves or at least partially displaces the brine in the above formation, and subsequently, the above formation is brought into contact with composition including the following: non-ionic fluorated polymer surface-active substance - NFPSAS, which contains at least one bivalent unit represented with structural formulae, and solvent; at that, when composition is brought into contact with the above formation, the above mentioned NFPSAS has turbidity point which is higher than the temperature of the above formation. Invention is developed in dependent claims.

EFFECT: increasing production rate of wells, where brine or gas condensate is present.

25 cl, 3 ex, 20 tbl, 3 dwg

FIELD: mining.

SUBSTANCE: viscoelastic composition for the use in underground formations includes, at least, one quaternary alkylamidoamine of the given formula and at least one indicated sub-additive when the ratio by weight is within 1000:1 and 5:1. Water-base fluid for the use in oil deposit includes indicated composition. Composition of high-density brine for oil deposit includes within 30-70 wt % of organic and/or inorganic salt and the composition mentioned above. Fluid of oil deposit termination in the form of high-density brine contains within 30-70 wt % of, at least, one organic or inorganic acid, within 0.1-4 wt % of, at least, one cationic surfactant from the modified group and, at least, one sub-additive from the modified group. The method of cracking underground formation includes provision of thickened fluid for water-base hydraulic fracturing, which includes water environment and effective amount of the above mentioned composition and injection of aqueous fluid through the well bore into the underground formation at a pressure, sufficient to break the formation. The invention is developed in the formula subclaims.

EFFECT: improvement of efficiency in upgrading permeability of underground formations.

24 cl, 4 ex

FIELD: mining.

SUBSTANCE: viscoelastic composition for the use in underground formations includes, at least, one quaternary alkylamidoamine of the given formula and at least one indicated sub-additive when the ratio by weight is within 1000:1 and 5:1. Water-base fluid for the use in oil deposit includes indicated composition. Composition of high-density brine for oil deposit includes within 30-70 wt % of organic and/or inorganic salt and the composition mentioned above. Fluid of oil deposit termination in the form of high-density brine contains within 30-70 wt % of, at least, one organic or inorganic acid, within 0.1-4 wt % of, at least, one cationic surfactant from the modified group and, at least, one sub-additive from the modified group. The method of cracking underground formation includes provision of thickened fluid for water-base hydraulic fracturing, which includes water environment and effective amount of the above mentioned composition and injection of aqueous fluid through the well bore into the underground formation at a pressure, sufficient to break the formation. The invention is developed in the formula subclaims.

EFFECT: improvement of efficiency in upgrading permeability of underground formations.

24 cl, 4 ex

FIELD: mining.

SUBSTANCE: drilling mud additive ensuring thermal stability contains the mixture of: reaction product of amine and polyfunctional isocyanate and reaction product of carboxylic acid with, at least, two carboxylic fragments; of polyamine, containing two or more functional amine groups; and chemical substance, chosen out of the group, consisted of: alkoxylated alkylamine, amides of fatty acids and their compounds. The invention is developed in dependant claims.

EFFECT: providing the thermal stability of drilling muds.

29 cl, 4 tbl, 3ex

FIELD: mining.

SUBSTANCE: drilling mud additive ensuring thermal stability contains the mixture of: reaction product of amine and polyfunctional isocyanate and reaction product of carboxylic acid with, at least, two carboxylic fragments; of polyamine, containing two or more functional amine groups; and chemical substance, chosen out of the group, consisted of: alkoxylated alkylamine, amides of fatty acids and their compounds. The invention is developed in dependant claims.

EFFECT: providing the thermal stability of drilling muds.

29 cl, 4 tbl, 3ex

FIELD: mining.

SUBSTANCE: method of preparation for cementing of wells drilled using invert-emulsion drilling mud is characterised by the fact that casing column is lowered into the well and washed with invert-emulsion drilling mud; four flush fluids are pumped subsequently into the well: parting-displacement fluid, solvent fluid, washing fluid and displacement fluid, and their further forcing to behind-the-casing space with well cement mortar and flushing fluid with their complete displacement from the well and installation of well cement mortar in behind-the-casing space at the required interval; at that, mixture of invert-emulsion drilling mud with formation water and with organic solvent in volume ratio of (4-6):(2.5-5.5.):(0.5-1.5) respectively is used as parting-displacement flush fluid; mixture of organic solvent, tall oil and 40% of water solution of sodium hydroxide in volume ratio of (9.0-9.6):(0.2-0.5):(0.2-0.5) respectively is used as solvent flush fluid; water solution of detergent also acting as demulsifying agent with 0.5-4% mass concentration is used as washing flush fluid; light-weight cement slurry with density of 1.35-1.45 g/cm3 is used as displacement flush fluid. At that, rheological characteristics: plastic viscosity and dynamic shear stress of solvent flush fluid are higher than rheological characteristics of the previous one - parting-displacement fluid, and further washing flush fluid, and density and rheological characteristics of displacement flush fluid are higher than those of the previous one - washing flush fluid.

EFFECT: increasing the volume of dense contact of cement stone with enclosing surfaces.

4 cl, 1 ex, 3 tbl

FIELD: mining.

SUBSTANCE: method of preparation for cementing of wells drilled using invert-emulsion drilling mud is characterised by the fact that casing column is lowered into the well and washed with invert-emulsion drilling mud; four flush fluids are pumped subsequently into the well: parting-displacement fluid, solvent fluid, washing fluid and displacement fluid, and their further forcing to behind-the-casing space with well cement mortar and flushing fluid with their complete displacement from the well and installation of well cement mortar in behind-the-casing space at the required interval; at that, mixture of invert-emulsion drilling mud with formation water and with organic solvent in volume ratio of (4-6):(2.5-5.5.):(0.5-1.5) respectively is used as parting-displacement flush fluid; mixture of organic solvent, tall oil and 40% of water solution of sodium hydroxide in volume ratio of (9.0-9.6):(0.2-0.5):(0.2-0.5) respectively is used as solvent flush fluid; water solution of detergent also acting as demulsifying agent with 0.5-4% mass concentration is used as washing flush fluid; light-weight cement slurry with density of 1.35-1.45 g/cm3 is used as displacement flush fluid. At that, rheological characteristics: plastic viscosity and dynamic shear stress of solvent flush fluid are higher than rheological characteristics of the previous one - parting-displacement fluid, and further washing flush fluid, and density and rheological characteristics of displacement flush fluid are higher than those of the previous one - washing flush fluid.

EFFECT: increasing the volume of dense contact of cement stone with enclosing surfaces.

4 cl, 1 ex, 3 tbl

FIELD: oil-and-gas production.

SUBSTANCE: proposed method grinding raw mix, pelletizing fine batch, sieving preset-size granules, their drying, annealing and classification. Batch pelletising is performed in turbine mixer for 6-35 s at high-intensity circular motion of bulk that ensures normal acceleration of particles to 500-2500 m/s2 with batch moistening for 50-90% of normal level, and, after maturing for 0.5-6 min, granules are shaped to required sphericity in dish noduliser with addition of remaining amount of moistening solution. Proposed invention is developed in dependent claims.

EFFECT: higher yield and strength.

4 cl, 4 tbl

FIELD: production and exploratory well drilling, particularly foaming drilling fluids used during penetration through incompetent rock intervals and during primary productive oil and gas deposit opening in the case of abnormally low formation pressure.

SUBSTANCE: foam composition comprises surfactant, foam stabilizer, water, water hardness control additive and lubricant. The water hardness control additive is sodium silicate. The lubricant is VNIINP-117 emulsion. The foam stabilizer is polyacrylamide, the surfactant is sulphonole. All above components are taken in the following amounts (% by weight): sulphonole - 0.8-1.5, sodium silicate - 0.2-0.5, polyacrylamide - 0.1-0.5, VNIINP-117 - 0.5-2, remainder is water.

EFFECT: reduced power inputs for well drilling, as well as reduced coefficient of friction between drilling tool and well wall.

1 tbl

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