RU2770192C1 - Acid composition for treatment of the bottomhole zone of a high-temperature carbonate reservoir - Google Patents

Abstract

FIELD: oil industry.

SUBSTANCE: invention relates to the oil industry. The acid composition for treatment of the bottomhole zone of a high-temperature carbonate reservoir contains, wt.%: at least one inorganic or organic acid selected from the range: hydrochloric, hydrofluoric, acetic, formic, sulfamic, chloroacetic 9.0 - 24.0; zwitterionic surfactant erucylamidopropylsulfobetaine 1.0 - 10.0; contains non-ionic synthetic polymer polyethyleneimine 0.01 - 0.09; water - the rest.

EFFECT: increasing viscosity at high temperatures, leveling the injectivity profile of injection or production wells in formations that are heterogeneous in terms of permeability, creating new fluid-conducting channels throughout the perforated thickness of the formation, increasing self-diverting properties.

1 cl, 9 dwg, 1 tbl, 15 ex

Description

The invention relates to the oil industry, in particular to the treatment of the bottomhole zone of high-temperature carbonate reservoirs, and can also be applied in drilling fluids, well completion solutions, well repair fluids.

Further in the text, the applicant gives the terms that are necessary to facilitate an unambiguous understanding of the essence of the claimed materials and to exclude contradictions and / or controversial interpretations when performing an examination on the merits.

Zwitterion (bipolar ion; German Zwitter - “hermaphrodite”) is a molecule that, being generally electrically neutral, has parts in its structure that carry both negative and positive charges [https://ru.wikipedia.org/ wiki/Zwitterion].

Self- diverting mud is a solution of surfactants and/or polymers in an organic or inorganic acid that changes its viscosity as the acid reacts with the carbonate rock of the oil reservoir.

Viscoelastic surfactants, due to their ability to dramatically increase the viscosity of aqueous solutions, are widely used as thickeners in various industries. In particular, in the oil industry they are used in enhanced oil recovery technologies [Kreh, K.A. Viscoelastic Surfactant-Based Systems in the Niagaran / K.A. Kreh // SPE eLibrary paper number 125754. – 2009. - September], [Pat. 2007142235 (A1) US, international classification C09K8/58, C09K8/58. Process for oil recovery using surfactant gels [Text] / Berger P.D., Berger C.H.; Applicant(s) Berger P.D., Berger C.H.; Priority number(s) US20070706474 20070215, US20050081232 20050316, US20040557346P 20040329; Publication date 2007-06-21], [New Viscoelastic Fluid for Chemical EOR / M. Morvan, G. Degré, J. Leng, C. Masselon, P. Moreau, J. Bouillot, A. Zaitoun // SPE eLibrary paper number 121675-MS. – 2009. - April.], are part of fracturing fluids [Fracture Geometry Optimization: Designs Utilizing New Polymer-free Fracturing Fluid and Log-derived Stress Profile/Rock Properties / B. Rimmer, C. MacFarlane, C. Mitchell, H Wolfs, M. Samuel // SPE eLibrary paper number 58761. - 2000. - February], [Polymer-free Fluid for Fracturing / M. Samuel, R.J. Card, E.B. Nelson, J.E. Brown, P.S. Vinod, H.L. Temple, Q.Qu, D.K. Fu // SPE eLibrary paper number 38622. - 1997. - October], [Viscoelastic Surfactant Fracturing Fluids: Applications in Low-permeability Reservoirs / M. Samuel, D. Polson, D. Graham, W. Kordziel, T. Waite, G Waters, P.S. Vinod, D. Fu, R. Downey // SPE eLibrary paper number 60322. - 2000. - March], and are also used for sand packing in the bottomhole zone of an oil reservoir [Gravel Packing Long Openhole Intervals With Viscous Fluids Utilizing High Gravel Concentrations: Toe -to-Heel Packing Without the Need for Alternate Flow Paths / M. Tolan, R.J. Tibbles, J. Alexander, P. Wassouf, L. Schafer, M. Parlar // SPE eLibrary paper number 121912-MS. - 2009. - August]. Another promising area of application of viscoelastic surfactants are compositions for the stimulation of oil production [Diyarov, I.N. Review of gel-forming materials used for directional acid treatment of the bottomhole formation zone [Text] / I.N. Diyarov, N.Yu. Bashkirtseva, D.A. Kuryashov // Geology, geophysics and development of oil and gas fields. - 2005. - No. 11. - S. 32-34].

In the case of production intensification in carbonate reservoirs, such technologies are usually based on hydrochloric acid compositions that are able to dissolve carbonates - limestone, dolomite, dolomitic limestone, which make up the productive horizons of oil and gas fields. In this case, chemical reactions proceed according to the following simple schemes:

CaCO ₃ + 2HCl → CaCl ₂ + CO ₂ + H ₂ O

CaMg(CO ₃ ) ₂ + 4HCl → CaCl ₂ + MgCl ₂ + 2CO ₂ + 2H ₂ O

The reaction products of hydrochloric acid with carbonates, i.e. calcium chloride (СаС1 ₂ ) and magnesium chloride (MgCl ₂ ), due to their high solubility, do not precipitate from the solution of the reacted acid. After processing, they are removed from the well along with the well products. Carbon dioxide CO ₂ is also easily removed to the surface.

When a reservoir is treated with hydrochloric acid, the latter reacts with the rock both on the walls of the well and in the pore channels, and the diameter of the well practically does not increase. A greater effect is the expansion of the pore channels and their cleaning from silt and carbonate materials soluble in acid. It is known from the prior art that under the action of acid, narrow long cavernous channels are formed, which, ultimately, form a complex, highly permeable network, which significantly increases the drainage area of wells and their flow rates. Therefore, hydrochloric acid treatments are mainly intended to introduce acid into the formation, as far as possible, at significant distances from the well in order to expand the channels and improve their communication [Muravyov, V.M. Exploitation of oil and gas wells / V.M. Ants. – M.: Nedra, 1973. – 315 p.].

Extensive experience in carrying out standard acid treatments in fields with a large productive formation suggests that high permeability intervals are mainly affected, while the rest remain untreated and do not participate in the formation of the flow rate. Non-working areas can be up to 75% of the perforated formation thickness. It is obvious that such a situation significantly reduces the efficiency of hydrochloric acid treatments, does not provide a uniform selection of products from the entire effective thickness of the productive section and, as a result, worsens the field development indicators as a whole (on average, the oil recovery factor is 0.18 - 0.25). Therefore, in general, the efficiency of work on intensification of inflow is 45 - 65%.

This is explained by the predominant flow of working fluids, which, as a rule, have rather low viscosities into highly permeable and drained parts of the reservoir, as a result of which low-permeability intervals are not treated. This is especially true for productive formations of high thickness with heterogeneous sections of the formation in terms of physical characteristics. Thus, one of the most important tasks of improving reservoir treatment methods is to achieve its maximum coverage over the entire thickness. To this end, acid diversion methods have been developed that can provide uniform stimulation of carbonate reservoirs.

So, from the studied level of technology, the TatNIPIneft technology was identified - directed hydrochloric acid treatment (NSKO), which includes the sequential injection of a high-viscosity inverse emulsion and hydrochloric acid into the well [Khisamov, R.S. The concept of development and rational use of hydrochloric acid treatments of wells [Text] / R.S. Khisamov, G.A. Orlov, M.Kh. Musabirov // Oil industry. - 2003. - No. 4. - S. 43-45]. The reverse emulsion fills the drained (working) sections of the reservoir and prevents the flow of acid into them. The acid then injected enters the non-performing sections of the formation and treats them. During the development of the well, the temporarily blocking composition is liquefied by the oil coming from the reservoir and releases the drained sections of the reservoir. As a result of treatment of the bottomhole zone (BHT), inflow into the well is carried out both in the old, previously working areas, and in the newly treated, previously inactive areas.

Known technology NIIneftepromkhim - directional hydrochloric acid treatment, based on the blocking of water-saturated formation zones with high-viscosity emulsion systems formed during the injection of a low-viscosity composition of a hydrocarbon solvent and surfactant (reagents SNPKh-9630 and SNPKh-9633). The emulsions that occur in the washed zones of the reservoir effectively divert the hydrochloric acid injected afterward into the oil-saturated low-permeability sections of the reservoir. Thus, complete zonal coverage of the reservoir by acid treatment is achieved [Sobanova, O.B. The use of hydrocarbon compositions of surfactants for the intensification of oil production and enhanced oil recovery [Text] / O.B. Sobanova, G.B. Fridman, N.N. Bragina, I.L. Fedorova, O.G. Lyubimtseva // Oil Industry 1998 - No. 2. - P. 35-38].

The technology of the Russian State University of Oil and Gas named after I.M. Gubkin - large-volume (directional) acid treatments of the bottomhole formation zone, the so-called BOPZ, where, in addition to acid solutions, aqueous or hydrocarbon gels are used that act as diverters that block high-permeability formation zones [Technological fluids for directional acid treatments of a carbonate reservoir [Text] / R.S. . Magadov [et al.] // In the materials of the III All-Russian Scientific and Practical Conference "Oilfield Chemistry". - Moscow, 2008. - S. 91 - 93]. For the preparation of an aqueous gel, the Himeko-V gelling complex manufactured by Himeko-Gang CJSC is used. Below is the amount of reagents included in the Himeko-B complex for water gelation:

gelling agent GPG-3 3.5-4.0 kg/ ^m3 Surfactant-destruction regulator 2.0 l/ ^m3 stapler BS-1.3 2.0-2.5 l/ ^m3 biocide "Biolan" 3.0 l per 50 m ³ gels

For the preparation of hydrocarbon gels, the Himeko-N gelling complex, also produced by Himeko-Gang CJSC, is used. Below is the amount of oil gelling reagents:

gelling agent "Khimeko-N" ^10.0-16.0 l/m3 activator "Himeko-N" 12.0-16.0 l/m ³ destructor "Himeko-N" 1.5-3.0 kg/ ^m3

The results of large-volume (directional) acid treatments of the bottomhole formation zone showed the high efficiency of the reagents used in these technologies: gelling complexes "Khimeko-V" and "Khimeko-N".

As can be seen from the above, all existing technologies, as a rule, are based on the sequential injection of diverting material and acid solution. The acid injected after the diverting material penetrates into the low permeability oil zones because the high permeability zones are mostly plugged. As a result, the permeability of low-permeability zones increases. As a deflecting material, viscous hydrophobic emulsions, polymer gels, cement mortars, etc. are used.

However, the known technical solutions have a number of significant drawbacks. One of the disadvantages is the low selectivity of materials, which leads to blocking of both high-permeability and low-permeability sections of the formation. In addition, the presence of polymeric or solid particles in the composition of known materials often leads to a violation of the filtration characteristics of the reservoir. It should also be noted that the injection of viscous materials into the reservoir leads to increased energy costs.

The above disadvantages are deprived of "self-deviating" acid compositions, which are a solution of a viscoelastic surfactant (surfactant) in an organic or inorganic acid. The action of such compositions is based on the ability of surfactants to form a viscoelastic gel in the presence of reaction products of an acid with a carbonate rock. The resulting gel creates an effective local deviation of new portions of the acid composition to previously untreated low-permeability sections of the formation. After treatment, the diverting gel breaks down upon contact with formation fluids. Thus, the use of an acid composition based on a viscoelastic surfactant ensures uniform stimulation of the entire productive interval of the reservoir.

Currently, oilfield service companies have proposed many "self-diverting" acid compositions, which differ primarily in the type of viscoelastic surfactant used.

For example, the Schlumberger technology is known - the VDA system, in which a zwitterionic surfactant is used as a gelling agent [Impact of Acid Additives on the Rheological Properties of Viscoelastic Surfactants and Their Influence on Field Application [Text] / A.H. Al-Ghamdi, H.A. Nasr-El-Din, A..A. Al-Qahtani, M.M. Samuel // SPE eLibrary paper number 89418. – 2004. - April], [Chang, F. A Novel Self-Diverting-Acid Developed for Matrix Stimulation of Carbonate Reservoirs [Text] / F. Chang, Qi Qu, W. Frenier / / SPE eLibrary paper number 65033. - 2001. - February], [Pat. 03054352 WO], [Pat. 2006018778 (A1) WO], [Pat. 2006085132 (A1) WO], [Pat. 2004005672 (A1) WO], [Pat. 2005020454 US], [Pat. 6399546 (B1) US], [Brady, M. Positive Reactions in Carbonate Reservoir Stimulation [Text] / M. Brady, S. Davies, C. Fredd // Oilfield Review. - 2003. - No. 12. - R. 28-45]. The VDA system has a low viscosity when injected into the well. As the acid reacts with the rock, the viscosity of VDA increases rapidly, creating a temporary barrier that deflects the rest of the "fresh" acid into more contaminated or low-permeability interlayers [patent WO 2004005671 (A1)]. Due to the increase in the viscosity of the system, further penetration of the liquid into the formation is reduced, and self-deviation of the injected flow occurs, which makes it possible to cover the entire treatment interval.

Halliburton technology is known, similar to VDA, in which a quaternary ammonium salt of a long-chain fatty acid is used as a gelling agent [Optimization of Surfactant-Based Fluids for Acid Diversion [Text] / H.A. Nasr-El-Din, A. Al-Nakhli, S. Al-Driweesh, T. Welton, L. Sierra, M. Van Domelen // SPE eLibrary paper number 107687. - 2007. - May]. A solution of this surfactant in concentrated hydrochloric acid (20 wt.%) has a low viscosity, during the reaction of the acid with the rock, the viscosity of the acid composition increases rapidly, and the system becomes self-deflecting. The advantage of using cationic surfactants over zwitterionic surfactants is that there is no need to use solvents and co-surfactants, as well as a low adsorption of cationic surfactants to carbonate rock.

Known technology company Halliburton, in which there is a "self-deviating" acid composition based on sulfonated methyl esters of fatty acids [Pat. 2006087525 (A1) WO], [Pat. 2006180309 (A1) US]. The use of anionic surfactants as a gelling agent makes it possible to reduce processing costs, since anionic surfactants are much cheaper than cationic and zwitterionic ones.

Known technology company BJ Services with a "self-deviating" acid composition based on alkylamine oxide [Lessons Learned and Guidelines for Matrix Acidizing With Viscoelastic Surfactant Diversion in Carbonate Formations [Text] / H.A. Nasr-El-Din, J.B. Chesson, K.E. Cawiezel, C.S. Devine // SPE eLibrary paper number 102468. – 2006. - September], [Study of a Successful Matrix Acid Stimulation Treatment in Horizontal Wells Using a New Diversion Surfactant in Saudi Arabia [Text] / S.A. Chatriwala, Y. Al-Rufaie, H.A. Nasr-El-Din, Y.M. Altameimi, K. Cawiezel, A Case // SPE eLibrary paper number 93536. - 2005. - March], [Pat. 2405421 (A) GB], [Pat. 6506710 (B1) US], [Pat. 2005137095 (A1) US]. A distinctive feature of the known technology is the destruction of the deflecting gel after the complete neutralization of hydrochloric acid, which makes it possible to more efficiently and effectively clean the bottomhole formation zone after treatment. The bottom-hole zone treatment technology using a known acid composition involves the sequential injection of the following reagents: hydrochloric acid (20 wt.%), oil-acid emulsion, "self-diverting" acid composition.

Despite the obvious advantages, self-diverting acid compositions based on viscoelastic surfactants have a number of significant disadvantages:

- significant filtrate flow into the reservoir, despite the high viscosity, which causes their insufficient deflecting properties. High filtrate recovery is associated with the inability of surfactant molecules to form a filter cake on the porous surface of the rock;

– a significant drop in viscosity upon heating, which limits their use in oil production, since the temperature in the oil reservoir can reach 150 °C. The high susceptibility of surfactant solutions to temperature is due to the low binding energy of surfactant molecules in a micelle.

A well-known way to increase the thermal stability and strength of surfactant solutions is to add polymers to compositions with surfactant. Polymers are embedded in the cores of surfactant micelles, increasing the number of entanglements in the system [Molchanov, V.S. Solutions with controlled viscoelastic properties based on potassium oleate and modified polyacrylamide / dis. for the Cand. physical and mathematical sciences. Moscow state. University - Moscow - 2008], [Kvyatkovsky, A.L. Rheological properties and structure of polymer-like micelles of a surfactant in saline solutions and their complexes with an uncharged linear polymer / dis. for the Cand. physical and mathematical sciences. Moscow state. University named after V.M. Lomonosov - Moscow - 2018]. The addition of polymers to solutions of cylindrical micelles often not only increases the viscosity and elastic modulus of the system, but also widens the temperature range in which high viscosity and elastic modulus are retained.

From the studied prior art, the applicant identified acidic compositions using polymers.

Thus, the application for the invention of the Russian Federation No. 2018140774 "Self-deflecting acid system" is known. The essence is a method of acidizing a formation through which the wellbore passes, including the steps: a. pumping into the wellbore, at a pressure below that required for fracturing, a treatment fluid that contains a gelling fluid containing a gelling agent and a hydrophobically modified associative polymer, and an aqueous acid solution; and b. enabling acid treatment of the formation under the action of the treatment fluid.

The disadvantage of the known technical solution in comparison with the claimed technical solution is that the known method uses a composition containing a hydrophobically modified associative polymer, which does not provide sufficient values for the viscosity of the acidic composition at high temperatures, in contrast to the non-ionic synthetic polymer in the claimed technical solution.

The advantage of non-ionic synthetic polymers, in particular polyethyleneimine, is their ability to maintain high viscosity of acidic solutions at elevated temperatures.

Acid compositions for treating the bottomhole zone of a high-temperature carbonate reservoir using non-ionic synthetic polymers, in particular polyethyleneimine, have not been identified by the applicant from the studied prior art.

The closest in technical essence to the claimed composition is the invention according to the patent of the Russian Federation No. 2598959 "Thickened viscoelastic fluids and their applications". The essence is an aqueous viscoelastic fluid for treating an underground formation, which contains at least one composition of a gelling agent, where the specified composition of the gelling agent contains at least one viscoelastic surfactant of general formula (I)

in which R1 is a saturated or unsaturated hydrocarbon group containing from 17 to 29 carbon atoms, R2 and R3 are independently selected from linear or branched chain alkyl or hydroxyalkyl groups containing from 1 to 6 carbon atoms, R4 is selected from H, hydroxyl group , alkyl or hydroxyalkyl groups containing from 1 to 4 carbon atoms; k is an integer from 2 to 20, m is an integer from 1 to 20, and n is an integer from 0 to 20, and a solvent system that contains water, a monohydric alcohol, and a dihydric or polyhydric alcohol, wherein the weight ratio of said monohydric alcohol and the specified dihydric or polyhydric alcohol in the specified composition of the gelling agent is from 1.0 to 2.2.

The disadvantages of the composition according to the prototype in comparison with the claimed composition are:

– insufficient (low) viscosity at elevated temperatures in low-density brines and acid solutions;

– insufficient alignment of the injectivity profile of injection or production wells in heterogeneous permeability high-temperature interlayers due to low viscosity;

– the impossibility of creating new fluid-conducting channels throughout the perforated thickness of the formation due to low viscosity at elevated temperatures;

– insufficient self-deflecting properties due to the inability to form a filter cake on the rock surface.

The technical result of the claimed technical solution is to eliminate the shortcomings of the prototype by introducing a non-ionic synthetic polymer of polyethyleneimine into the composition, namely:

– increase in viscosity at high temperatures;

– alignment of the injectivity profile of injection or inflow of production wells in formations that are heterogeneous in terms of permeability;

– creation of new fluid-conducting channels throughout the perforated thickness of the formation;

– increase of self-deflecting properties.

The essence of the claimed technical solution is an acidic composition for treating the bottomhole zone of a high-temperature carbonate reservoir containing at least one inorganic or organic acid from the series: hydrochloric, hydrofluoric, acetic, formic, sulfamic, chloroacetic; a zwitterionic surfactant and water, characterized in that it contains erucylamidopropylsulfobetaine as a zwitterionic surfactant and additionally contains a non-ionic synthetic polymer polyethyleneimine in the following ratio, wt.%:

inorganic or organic acid – 9.0 - 24.0 erucylamidopropylsulfobetaine – 1.0 - 10.0 polyethyleneimine – 0.01 - 0.09 water - the rest

The claimed technical solution is illustrated in Fig.1 - Fig.9.

Figure 1 shows the dependence of viscosity on shear rate on the concentration of PEI (molecular weight 800 and 1300 g/mol) for EASB 1.0 wt.% at a temperature of 25 ° C, solvent 3.0 wt.% NaCl solution, where :

– без полимера,

- no polymer

– 0,001 мас.% ПЭИ (800 г/моль),

– 0.001 wt.% PEI (800 g/mol),

– 0,05 мас.% ПЭИ (800 г/моль),

– 0.05 wt.% PEI (800 g/mol),

– 0,001 мас.% ПЭИ (1300 г/моль),

- 0.001 wt.% PEI (1300 g/mol),

– 0,04 мас.% ПЭИ (1300 г/моль).

- 0.04 wt.% PEI (1300 g/mol).

Figure 2 shows:

2a - dependence of viscosity on the concentration of PEI (molecular weight 800 and 1300 g/mol) at a temperature of 25 °C, where:

– ПЭИ (800 г/моль),

– PEI (800 g/mol),

–ПЭИ (1300 г/моль);

–PEI (1300 g/mol);

2b - dependence of viscosity on temperature for EASB 1.0 wt.%, solvent 3.0 wt.% NaCl solution, where:

– без полимера,

- no polymer

– 0,01 мас.% ПЭИ (1300 г/моль).

- 0.01 wt.% PEI (1300 g/mol).

Figure 3 shows the dependence of the elastic modulus G′ and the viscosity modulus G″ on frequency for EASB 1.0 wt.% at a temperature of 25 ° C and different concentrations of PEI (molecular weight 800 and 1300 g/mol), solvent 3.0 wt. .% NaCl solution, where:

G'

G'' – без полимера,

G'

G'' - no polymer,

G'

G'' – 0,01 мас.% ПЭИ,

G'

G'' - 0.01 wt.% PEI,

G'

G'' – 0,05 мас.% ПЭИ.

G'

G'' - 0.05 wt.% PEI.

Figure 4 shows the dependence of the elastic modulus on the plateau for EASB 1.0 wt.% at a temperature of 25 ° C and different concentrations of PEI (molecular weight 800 and 1300 g/mol), solvent 3.0 wt.% NaCl solution, where:

– ПЭИ (1300 г/моль);

– PEI (1300 g/mol);

– ПЭИ (800 г/моль).

– PEI (800 g/mol).

Figure 5 shows the dependence of the effective viscosity of the acid composition on pH at a temperature of 120 °C.

Figure 6 shows the dependence of pressure on the pumping volume. Filtration tests of the developed SCS, where:

Kprn1 is the coefficient of core permeability for oil before treatment with an acid composition,

Кprn2 is the coefficient of core permeability for oil after treatment with an acid composition,

Q is the consumption of the acid composition during the experiment, cm ³ /min,

SCS - self-deflecting acid composition,

Kpr1 (Q \u003d 0.1 cm ³ / min) - blue line,

SCS injection Q = 0.5 cm ³ /min - red line,

Kpr2 (Q \u003d 0.1 cm ³ / min) - green line.

Figure 7 shows a photo of the core:

7a - before injection of SCSv - 2.5 wt.% EASB at 120 °C,

7b - after injection of SCSv - 2.5 wt.% EASB at 120 °C.

Figure 8 presents Table 1, which shows the composition of the claimed composition.

Figure 9 shows Table 2, which shows the results of laboratory tests to assess the effect of the claimed acid composition with an EASB concentration of 2.5 wt.% on the filtration characteristics of the core model, where: Kprn1 is the core permeability coefficient for oil before treatment with an acid composition, Kprn2 – coefficient of core permeability for oil after treatment with an acid composition.

Further, the applicant shows the implementation of the claimed technical solution.

To prepare the claimed composition, the following components are used.

Inorganic or organic acids , for example:

- inhibited hydrochloric acid, for example, according to TU 2458-264-05765670 with change 1;

- hydrofluoric acid (HF), for example, according to GOST 10484-78;

- acetic acid (UK), for example, according to GOST 19814-74;

- formic acid (FA), for example, according to GOST 9285-78;

- sulfamic acid (SA), for example, according to TU 2121-083-05800142-2001;

- chloroacetic acid (HC), for example, see Rabinovich V.A., Khavin Z.Ya. "Brief chemical reference book" L .: Chemistry, 1977, pp. 191-192;

- or mixtures thereof at a ratio of acids (1 - 9) : (9 - 1).

Erucylamidopropylsulfobetaine (hereinafter - EASB) , which is a zwitterionic surfactant with the following structure:

,

,

where:

R1 is a saturated or unsaturated hydrocarbon group containing from 17 to 29 carbon atoms,

R2 and R3 are independently selected from straight or branched chain alkyl or hydroxyalkyl groups containing from 1 to 6 carbon atoms,

R4 is selected from H, a hydroxyl group, alkyl or hydroxyalkyl groups containing from 1 to 4 carbon atoms;

k is an integer from 2 to 20, m is an integer from 1 to 20, and n is an integer from 0 to 20, and a solvent system that contains water, a monohydric alcohol, and a dihydric or polyhydric alcohol, wherein the weight ratio of said monohydric alcohol and the specified dihydric or polyhydric alcohol in the specified composition of the gelling agent is from 1.0 to 2.2.

Non-ionic synthetic polymer polyethyleneimine (hereinafter referred to as PEI) with the following structure:

,

,

where: n=100-300.

The claimed technical result is achieved by introducing a nonionic synthetic polymer, polyethyleneimine (PEI), into the solution of erucylamidopropyl betaine (EASB).

While the applicant found that the addition of different concentrations of PEI (molecular weight of 800 and 1300 g/mol) to aqueous solutions of EASB leads to an increase in their viscosity with increasing concentration of PEI (Figure 1).

It was found that with increasing PEI concentration, the dependence of the viscosity of EASB solutions passes through a maximum (Fig. 2a).

So, from figure 2 it is seen that the initial addition of non-ionic synthetic polymer (PEI) leads to an increase in viscosity several times. If the viscosity of individual solutions of EASB (1.0 wt.%) and PEI (0.01 wt.%) is 66.91 and 0.01 Pa s, respectively, then the viscosity of the mixed solution with the addition of a non-ionic synthetic polymer (PEI) is 356 .8 Pa s Such a mixed system is a physical gel.

It should also be noted that in the presence of PEI (0.01 wt.%), the viscosity of aqueous solutions of EASB increases in a wide temperature range, up to 90 °C (Fig. 2b). According to the Applicant, this fact is explained by the fact that the polymer chains formed by strong covalent bonds do not undergo reduction and destruction processes, which is typical for micellar chains.

The effect of an increase in viscosity upon the addition of a nonionic synthetic (hydrophilic) polymer is as follows: when a nonionic synthetic polymer is added, additional topological entanglements appear in the system due to the penetration of the hydrophilic side groups of the polymer into surfactant micelles, i.e. a π-cationic interaction is observed between the hydrophilic part of EASB and the hydrophilic group of the PEI polymer. The formation of additional topological entanglements, according to the Applicant, also explains the fact that PEI with a higher molecular weight (1300 g/mol) forms more viscous solutions than with PEI with a molecular weight of 800 g/mol.

When the PEI polymer is added to an aqueous solution of EASB, a change in the dynamic properties of the system is also observed. Thus, the value of the elastic modulus G' becomes greater than the viscosity modulus G" in the entire frequency range available for measurements (Fig.3).

The modulus of elasticity passes through a maximum with increasing concentration of PEI, regardless of the molecular weight (Fig.4).

The increase in the elastic modulus on the plateau G ₀ ' (Figure 3 and Figure 4) indicates the penetration of hydrophilic side groups of PEI in surfactant micelles, which confirms the known information [Molchanov, V.S. Solutions with controlled viscoelastic properties based on potassium oleate and modified polyacrylamide / dis. for the Cand. physical and mathematical sciences. Moscow state. University - Moscow - 2008]. Also confirmed is the known information that the decrease in the viscosity of solutions of worm-like micelles with increasing polymer concentration is associated with a decrease in the contour length of micelles [Massiera, G. Role of the Size Distribution in the Elasticity of Entangled Living Polymer Solutions / Massiera G., Ramos L., Ligoure C // Europhys. Lett.– 2002.– Vol. 57, No. 1.– P. 127–133] (Fig. 2).

Further, the applicant provides examples of obtaining the claimed composition.

The claimed acid composition is prepared in the laboratory as follows.

Example 1. Obtaining the claimed composition, composition No. 1 (Table 1, Fig.8).

To 1.0 wt.% (for example, 1.0 g) EASB is added 0.01 wt.% (for example, 0.01 g) of PEI, 9.0 wt.% (for example, 9.0 g) of hydrochloric acid and 89.99 wt% (eg 89.99 g) water. The resulting mixture is stirred for 40 minutes until a homogeneous composition is obtained.

Get the claimed composition. The composition of the finished composition is shown in Fig.8 in Table 1, composition No. 1.

Examples 2-14. Obtaining the claimed composition with different components and their different content.

Compositions according to Examples 2-14 with different composition and different content of components in the ranges of the declared values are prepared similarly to Example 1, varying the components and their content.

The compositions of the finished compositions are shown in Fig.8 in Table 1, compositions No. 2 - 14.

Example 15. Obtaining a composition according to the prototype.

To 9.0 wt.% (for example, 9.0 g) of hydrochloric acid are added 1.0 wt.% (for example, 1.0 g) of EASB and 90 wt.% (for example, 90.0 g) of water. The resulting mixture is stirred for 40 minutes until a homogeneous composition is obtained.

Get the composition of the prototype. The composition of the finished composition according to the prototype is shown in Fig.8 in Table 1, composition No. 15.

Further, the applicant describes the use of the claimed composition in the treatment of the bottomhole zone of a high-temperature carbonate reservoir.

The effectiveness of the claimed composition was evaluated by changing the viscosity of the resulting acid gel during the treatment of the bottomhole zone of a high-temperature carbonate reservoir (see graph in Fig.5). When conducting the experiment, composition No. 6 of the claimed composition from Table 2 was used. As can be seen from the graph in Fig. 5, at low pH values, the composition has a low viscosity. As the hydrochloric acid reacts with the carbonate rock and the pH increases, the viscosity of the resulting gel increases.

To determine the effectiveness of the claimed acid compositions, studies were carried out on their action in a porous medium - on natural cores. A core sample of 15.940 mD was chosen for research. For core samples simulating an oil-saturated interlayer, filtration tests of the intensifying composition were carried out as follows:

a) oil filtration was carried out through an oil-saturated reservoir model with residual water saturation (Row) in the "formation-well" direction with the determination of the oil permeability coefficient (Кprn1), at a minimum filtration rate of 0.1 cm ³ /min .;

b) in the direction of "well-formation" produced the injection of the claimed composition (for example, composition No. 6 from Table 1) in the amount of 1-1.5 Vpor, at an injection rate of 0.5 cm ³ /min;

c) the compositions were kept for 3 hours in the pore space of the core models of the reservoir in order to simulate the technological process during the acid treatment;

d) in the "reservoir-well" direction, the reservoir oil model was filtered until the pressure in the system stabilized, followed by determination of the oil permeability coefficient (Кprn2);

e) in the third filtration experiment, petroleum ether was pumped on the core sample after determining the oil permeability coefficient (Кprn2) in order to flush the pore space;

f) Calculate the residual resistance factor RRF0.

The results of laboratory tests to assess the effect of the claimed acid composition on the example of a composition with 2.5 wt.% EASB on the filtration characteristics of core models are shown in Table 2 in Fig.9.

From the data shown in Table 2, it can be seen that the acid composition claimed in the present invention makes it possible to increase the permeability of the carbonate core by almost 2.5 times, which in turn will increase the flow rate of oil wells. Thus, the applicant has achieved the claimed technical results - increased self-deflecting properties, resulting in the creation of new fluid-conducting channels throughout the perforated thickness of the formation.

In the process of testing the technology of pumping the acid composition into cores, the pressure dynamics, pumping volumes were recorded and the core ends were photographed. The pressure dynamics during the testing of the composition is shown in Fig. 6. Photos of the core ends before and after pumping SCSv - 2.5 wt.% EASB are shown in Fig.7.

From the data shown in Figure 6, it can be seen that during filtration tests at 120 ° C, an increase in pressure is observed, which indicates the formation of a gel in the core.

Thus, the possibility of using the claimed acid composition in high-temperature wells was shown.

Thus, from the above, we can conclude that the applicant has achieved the claimed technical result by eliminating the shortcomings of the prototype by introducing a non-ionic synthetic polymer of polyethyleneimine into the composition, due to which:

– almost 6 times higher viscosity at high temperatures – see Fig. 2;

– alignment of the injectivity profile of injection or production wells in heterogeneous permeability formations has been achieved – see Fig.6;

– creation of new fluid-conducting channels across the entire perforated thickness of the formation has been achieved – see Fig. 7, Tab. 2 in Fig. 9;

– increased self-deflecting properties – see Fig. 7, Tab.2 in Fig.9.

Claims (2)

An acidic composition for treating the bottomhole zone of a high-temperature carbonate reservoir containing at least one inorganic or organic acid from the range: hydrochloric, hydrofluoric, acetic, formic, sulfamic, chloroacetic; a zwitterionic surfactant and water, characterized in that it contains erucylamidopropylsulfobetaine as a zwitterionic surfactant and additionally contains a non-ionic synthetic polymer polyethyleneimine in the following ratio, wt.%: inorganic or organic acid 9.0 - 24.0 erucylamidopropylsulfobetaine 1.0 - 10.0 polyethyleneimine 0.01 - 0.09 water rest

Images