RU2797160C1 - Method of treatment of the near-wellbore zone - Google Patents

Abstract

FIELD: oil production.

SUBSTANCE: in the method of treatment of the near-wellbore zone, before treatment is performed, pressure testing of the tubing string of tubing with a downhole pump is performed at least a day before. A back pressure of 8 MPa is created in the tubing string with a pump to determine the tightness and prevent the acid composition from flowing through the pump into the tubing. The pipe space is closed off from above. Then, an injection test is performed, a process fluid is pumped into the annular space, the fluid being formation water with a density of 1.0-1.18 g/cm³ at 20°C containing 0.1-0.2% surfactant ML 81B, in double the volume of the annular space with a flow rate of 0.1-2.0 m³/min or an emulsion with a flow rate of 0.1-0.25 m³/min, being a water-oil emulsion containing commercial oil or oil from a well with a water content of not more than 10%, emulsifier MIA-prom grade B, reservoir mineralized water with density at 20°C 1.16-1.18 g/cm³, or an oil-free emulsion containing the ITPS-013G emulsifier, which is a complex of surfactants based on a hydrocarbon solution of alkanolamine esters of oleic acid, and mineralized water with specific weight of 1.07-1.18 g/cm³. Taking into account the previously performed treatments with low wellhead pressures, depending on the specific injectivity coefficient, the injection volume is selected. When the pressure rises during the injection process, the injection is stopped and the time it takes for the pressure to drop is determined. If the pressure drops to 0 atm in more than 5 minutes, recalculation is carried out to reduce the volumes, solvent consumption and acid composition, and the viscosity of the diverter fluid. If there is no increase in pressure, the entire volume is prepared and pumped without stopping until signs of a stable increase in pressure appear, the results of the injection test are entered into the computer program and the volume and viscosity of the diverter fluid, the rock fracture gradient, permeability, the optimal ratio of the diverter fluid volume to the acid composition volume, and volume of the process fluid are determined. Then changes are made to the design of the project. At least one pumping cycle is performed - sequential injection of a diverter fluid with a viscosity of 600-2000 cps with a flow rate of 0.1-0.25 m³/min, a solvent with a flow rate of 0.1-0.2 m³/min, an acid composition with a flow rate of 0.1-2.0 m³/min with a specific volume of 1-10 m³ per 1 meter of the perforated interval, and the solvent is pumped in a volume of at least 4% of the volume of the diverter fluid, and a water-oil emulsion is used as the diverter fluid containing commercial oil or oil from a well with a water content of not more than 10%, emulsifier MIA-prom grade B, reservoir mineralized water with a density at 20°C 1.16-1.18 g/cm³, or an oil-free emulsion containing the ITPS-013G emulsifier, which is a complex of surfactants based on a hydrocarbon solution of alkanolamine esters of oleic acid, mineralized water with a specific gravity of 1.12-1.18 g/cm³. Squeezing is carried out with process fluid in a volume equal to the volume of the annular space at a flow rate of 0.1-2.0 m³/min. After the response, the well is tied with a trough system, the well is put into operation and worked into the trough system by pumping in a double volume of displacement fluid until a well product with a pH of more than 4 is obtained.

EFFECT: increase in efficiency of treatment of the near-wellbore zone.

2 cl, 7 tbl

Description

The invention relates to methods for intensifying oil production from productive formations using selective acid methods for influencing the near-wellbore zone of a formation composed of carbonate rocks when treating formations with injection through the annular space without the approach of a well workover crew and without tripping operations with deep-well pumping equipment (SPD), including in wells with simultaneous-separate production (OPD), low reservoir pressure and with complicated well designs (presence of emergency bottom hole and the risk of stuck tool in the interval of productive formations, open wellbore, failure of the tool to pass through the production string ).

There is a known method for large-volume selective acid treatment (RF patent No. 2456444, publ. 02/10/2012), including injection of an acid composition slug into the well at a certain flow rate, injection of a non-linearly viscous diverting fluid before and / or after the acid composition slug, the acid composition is pumped with a specific volume of 1.5-3 m ³ per 1 m of the oil-saturated interval.

The known method is not effective enough for carbonate reservoirs, it does not optimize the injection costs of the acid composition and diverter.

A method for selective acid treatment of a heterogeneous carbonate formation is known (patent RU No. 2704668, publ. 10/30/2019), including determining the specific injectivity coefficient of the treatment interval, cyclic sequential injection of a buffer liquid into it, portions of a viscoelastic composition (VCS) and an acid composition in the form of an aqueous solution hydrochloric acid containing substances that improve the filtration characteristics, followed by squeezing with a liquid that preserves the reservoir properties of the reservoir. VUS is prepared from components in the following ratio, wt.%: tallow amidopropyldimethylamine oxide 3.0-4.0; sodium hydroxide 5.0-15.0; sodium chloride 6.0; water is the rest. At the same time, lactide fibers are added to the VUS at a dosage of 10.0-30.0 kg/m ³ . The volumes of portions of the VUS and the dosage of the fiber are determined depending on the value of the coefficient of specific injectivity on the basis of experimental work. Before injection of a portion of WCS with lactide fibers, a buffer liquid is pumped in the form of formation or fresh water with a surfactant in a volume of 0.5-1.0 m ³ , after which a portion of WCS with lactide fibers is forced into the formation through a portion of formation or fresh water with surfactant acid composition in the amount of 0.5-2.0 m ³ per linear meter of treatment interval for vertical wells or 0.05-0.2 m ³ for horizontal wells. The number of sequential injection cycles of formation or fresh water with surfactants, portions of WCS with lactide fibers, formation or fresh water with surfactants and acid composition is 2-3 depending on the radius of distribution of the acid. The volume of the portion of the acid composition is increased by 10-30% with each subsequent cycle, after which the compositions are forced through with a liquid that retains the reservoir properties of the formation, in the volume of the cavity of the tubing plus 3-8 m ³ , followed by closing the well for a time of 6-8 hours reaction of the acidic composition and destruction of the lactide fiber.

The disadvantage of this method is that there are no stages with a solvent - poor contact with the rock of the acidic composition. The use of high-viscosity non-Newtonian fluids imposes restrictions on the filtration characteristics of the injected compositions - the technology is not applicable as a primary matrix acid treatment. The presence of fiber in the composition of the liquid will lead to undesirable clogging and a decrease in filtration, which will reduce the quality of the formed dissolution channels, a short-term effect, and, consequently, a decrease in flow rate. Another disadvantage is the uncontrolled formation of dissolution channels, since the filtration mode of acid compositions is not previously investigated, therefore, the quality of the dissolved filtration channels, their depth and shape are unknown.

There is a known method for treating the bottomhole zone of a well, including an analysis of the compatibility of the acid composition with the formation fluid of the treated well, closing the valve on the oil collection line, pumping the acid composition and displacement fluid, process holding, removing reaction products (patent RU No. 2708647, publ. 10.12.2019 ). Before pumping the acid composition, the process fluid is pumped through the annular space, displacing the well fluid through the tubing string into the flow line associated with the tubing string, water with a corrosion inhibitor is used as the process fluid. Then, the acid composition Rex 1 is pumped into the annulus with the process liquid being forced out into the flow line. Turn off the installation of the deep pump. The tubing string is closed with string and linear valves installed on the wellhead fittings. The Rex 1 acid composition and the displacement fluid are successively pumped into the annulus, the acid composition is forced into the productive formation zone, and the exposure is performed for 8-16 hours. The volume of injection is determined based on the volume of the annular space, which depends on the depth of the well, the specific consumption of the acid composition per linear meter of the productive formation. After exposure, a system is assembled to collect the reaction products in a tank truck. As an acidic composition, an emulsion of the reverse type Rex 1 containing hydrochloric acid, a hydrocarbon solvent and surfactants is used.

The disadvantages of the method that affect the decrease in efficiency are:

- injection of an acid composition in the volume of the annulus, which depends on the depth of the well, the specific consumption of the acid composition per linear meter of the productive formation, without taking into account the permeability and injectivity and the results of the analysis of previous treatments and a computer program for simulating the injection process, without checking the tightness of the equipment, does not allow optimize injection costs, reduce the depth of impact to low-permeability sections of the reservoir and intensify well productivity;

- execution of operations for pumping process fluid with a corrosion inhibitor leads to additional material costs and time;

- without deviation of the injected acid composition, without taking into account the lithological-mineralogical and reservoir characteristics of the reservoir, the coverage area is reduced;

- injection of the Rex 1 acid composition into the annulus with the displacement of the process fluid into the flow line leads to an aggressive effect on the downhole pumping equipment;

- a narrow scope due to the complexity of the application in wells with simultaneous-separate production, low reservoir pressure and complicated well designs.

A known method of large-volume selective acid treatment of the bottomhole formation zone in carbonate reservoirs, including core sampling, determination of the geological and physical characteristics of the formation, features of the void space, conducting filtration studies of the core by pumping chemical reagents through the core samples to determine the type and concentration of the acid composition, types of solvent, diverter and modifying additives, designing the well acid treatment design using a computer program, pumping a solvent, acid composition and diverter fluid into the well with an optimal flow rate and an optimal ratio of the diverter volume to the volume of the acid composition (patent RU No. 2750776, publ. 02.07.2021). In the method, the design of a large-volume selective acid treatment of the bottomhole formation zone is designed using a computer program and acid treatment is carried out by pumping in any sequence with a flow rate of 0.3-2.0 m ³ /min of a solvent, an acid composition with a specific volume of 3-20 m ³ per 1 meter of the perforated interval and the diverter fluid, and the solvent is taken as a mutual solvent or hydrocarbon solvent, as the acid composition - hydrochloric acid inhibited synthetic for oil and gas production of grades a, b, c, d, hydrochloric acid synthetic inhibited modified TATOL / TATOL®-HCl grades HCl-8/12/2500; HCl-8/12/5000; HCl-24/2500; HCl-24/5000 and hydrochloric acid composition TATOL/TATOL - SKS grades HCl-15/2500, HCl-15/5000, HCl-24/2500, HCl-24/5000, and as a diverter - ZKS-M 1- 3 brands Cht ZKS-1M(a) and ZKS-1M(b).

The optimal ratio of the volume of the diverter to the volume of the acid composition is determined based on the skin factor parameter of not more than 0 and the penetration depth of chemical compositions of more than 2.5-7 m and changes in bottomhole pressure.

For well treatment, it is important to control the determination and selection of the type of reagents, their volumes and concentrations based on previous treatments and a computer program for simulating the injection process, taking into account the geological and physical characteristics of the reservoir, features of the void space, core filtration studies and modes of previously performed acid treatment of reservoirs.

The disadvantages of the method are the impossibility of predicting the performance of the process, the viscosity of the composition cannot be varied and is performed in one stage without achieving a deviation of the acid composition.

The closest in technical essence is the method of large-volume selective acid treatment of the bottomhole formation zone in carbonate reservoirs, including determining the type and concentration of the acid composition, the type of solvent, the type of diverter fluid and modifying additives by analyzing the filtration studies of the core - pumping chemicals through previously selected core samples, analysis on the compatibility of the acid composition with the formation fluid of the treated well, designing the design of the acid treatment of the near-wellbore zone using a computer program, taking into account the geological and physical characteristics of the formation, the features of the void space, the results of the preliminary analysis of the filtration studies of the core, the analysis of the compatibility of the acid composition with the formation fluid of the treated well, and modes of previously performed acid treatment of formations, injection of an acid composition, solvent, diverter fluid (patent RU No. 2750171, 06/22/2021). Acid treatment is carried out by pumping in any sequence with a flow rate of 0.3-2.0 m ³ /min of a solvent, an acid composition with a specific volume of 3-20 m ³ per 1 meter of the perforated interval and a diverter fluid, and a mutual solvent is taken as a solvent or a hydrocarbon solvent, as an acid composition - inhibited synthetic hydrochloric acid for oil and gas production grades a, b, c, d, modified hydrochloric synthetic inhibited acid TATOL/TATOL®-HCl grades HCl-8/12/2500; HCl-8/12/5000; HCl-24/2500; HCl-24/5000 and hydrochloric acid composition TATOL/TATOL - SKS grades HCl-15/2500, HCl-15/5000, HCl-24/2500, HCl-24/5000, and as a diverter - ZKS-M 1- 3 brands ZKS-1M(a) and ZKS-1M(b).

The optimal ratio of the volume of the diverter to the volume of the acid composition is determined based on the skin factor parameter of not more than 0 and the penetration depth of chemical compositions of more than 2.5-7 m and changes in bottomhole pressure.

The disadvantages of this method are the decrease in the accuracy of the predicted calculation in terms of volumes, flow rates and pressure during the injection process without taking into account the performance of the injection test and accurate prediction of the injected volumes of reagents, the viscosity of the diverter fluid, which reduces the effectiveness of the acid impact on the rock, high costs associated with the need for a brigade approach workover to the well and performing tripping operations, with a high consumption of chemical reagents injection and with a corrosive effect on GNO, poor quality of temporary blocking of reservoir intervals with a high specific injectivity coefficient, and as a result, a decrease in oil production.

The technical objectives of the proposal are to increase the efficiency of treatment of the near-wellbore zone in production and injection wells by improving the quality of treatment and reducing the time of operations while reducing friction losses during injection of the emulsion, increasing the accuracy of selecting the volume and viscosity of the diverter fluid, increasing the wetting area of the productive formation with solvent and removal efficiency of the bridging film, reduction of oil-free emulsion preparation time, elimination of the risk of acid composition breakthrough and obtaining inter-layer and annular circulation, temporary blocking of reservoir intervals with a high specific injectivity coefficient, increasing the efficiency of acid impact on the carbonate reservoir by improving reservoir properties and increasing depth , the area of the channels of dissolution, as well as increasing the flow rate by increasing the area of fluid inflow to the near-wellbore zone, reducing the cost of performing selective acid treatment, eliminating the aggressive impact on downhole pumping equipment. The method also makes it possible to expand the arsenal of technological possibilities for treating the near-wellbore zone of a carbonate formation with an increase in the efficiency of obtaining a predicted result.

Technical problems are solved by the method of treating the near-wellbore zone, including determining the type and concentration of the acid composition, the type of solvent, the type of diverter fluid and modifying additives by analyzing the filtration studies of the core - pumping chemicals through previously selected core samples, analyzing the compatibility of the acid composition with the reservoir fluid of the treated well, designing the design of the acid treatment of the near-wellbore zone using a computer program, taking into account the geological and physical characteristics of the reservoir, the features of the void space, the results of the preliminary analysis of the core filtration studies, the analysis of the compatibility of the acid composition with the reservoir fluid of the treated well and the modes of the previously performed acid treatment of the reservoirs, injection of the acid composition , solvent, diverter fluid.

What is new is that before treatment of the near-wellbore zone at the well, at least a day before, the tubing string with a well-driven pump is pressure tested, a back pressure of 8 MPa is created in the tubing string by the pump to determine the tightness and prevent the acid composition from flowing through the pump into the tubing , close the pipe space from above, then perform an injection test - pump into the annulus a process fluid - formation water with a density at 20 ° C of 1.0-1.18 g/cm ³ containing 0.1-0.2% surfactant surfactants ML 81B, in a 2-fold volume of the annular space with a flow rate of 0.1-2.0 m ³ /min or an emulsion with a flow rate of 0.1-0.25 m ³ /min, which is used as a water-oil emulsion containing marketable oil or oil from a well with a water content of not more than 10%, emulsifier MIA-prom brand B, formation mineralized water with a density at 20 ° C of 1.16-1.18 g/cm ³ , or an oil-free emulsion containing emulsifier ITPS- 013G, which is a complex of surfactants based on a hydrocarbon solution of alkanolamine esters of oleic acid, and mineralized water with a specific gravity of 1.07-1.18 g / cm ³ , taking into account previously performed treatments with low wellhead pressures at a specific coefficient injectivity from 0.5 to 1.0 m ³ /(MPa⋅h), the injection volume is 2-3 m ³ , with a specific injectivity coefficient from 1.1 to 1.5 m ³ /(MPa⋅h), the injection volume is 4 -5 m ³ , with a specific injectivity coefficient from 1.6 to 2.0 m ³ /(MPa⋅h), the injection volume is 6-8 m ³ , with a specific injectivity coefficient from 2.1 to 3.0 m ³ /( MPa⋅h) the injection volume is 8.1-10 m ³ , with a specific injectivity coefficient from 3.1 to 4.0 m ³ /(MPa⋅h) the injection volume is 10-14 m ³ , with a specific injectivity coefficient from 4 ,1 to 6.0 m ³ /(MPa⋅h) the injection volume is 14-18 m ³ , with a specific injectivity coefficient of more than 6.0 m ³ /(MPa⋅h), the injection volume is more than 20 m ³ , with an increase in pressure during the injection process, the injection is stopped and the time it takes for the pressure to drop is determined, if the pressure drops to 0 atm in more than 5 minutes, the volumes, the solvent consumption and the acid composition and the viscosity of the diverter fluid are recalculated in the direction of decreasing, in the absence of pressure increase, and the entire volume is pumped non-stop until signs of a stable pressure increase appear, the results of the injection test are entered into a computer program and the volume and viscosity of the diverter fluid, the rock fracture gradient, permeability, the optimal ratio of the diverter fluid volume to the volume of the acid composition and the volume of the process fluid are determined, then they make changes to the design of the project in terms of the allowed optimal pressure on the productive formations, but not more than the allowed one on the production casing, optimal costs and injection volumes, the number of injection cycles, then at least one injection cycle is performed - sequential injection of a diverter fluid with a viscosity of 600- 2000 cps with a flow rate of 0.1-0.25 m ³ /min, a solvent with a flow rate of 0.1-0.2 m ³ /min, an acid composition with a flow rate of 0.1-2.0 m ³ /min with a specific volume of 1 -10 m ³ per 1 meter of the perforated interval, and the solvent is pumped in a volume of at least 4% of the volume of the diverter fluid, and a water-oil emulsion containing commercial oil or oil from a well with a water content of not more than 10% is used as the diverter fluid, emulsifier MIA-prom grade B, reservoir mineralized water with a density at 20°C of 1.16-1.18 g/ ^cm solution of alkanolamine esters of oleic acid, mineralized water with a specific gravity of 1.12-1.18 g / cm ³ , the process liquid is squeezed in a volume equal to the volume of the annular space with a flow rate of 0.1-2.0 m ³ /min, after the response of the well they are tied with a gutter system, the well is put into operation and mastered into the gutter system by a pump in a double volume of displacement fluid until a well product with a pH of more than 4 is obtained.

Also new is that the injection cycles of the diverter fluid, solvent, acid composition are repeated until full coverage of the formation is obtained.

To perform a pressure test, use:

- formation water with a density at 20°C of 1.0-1.18 g/cm ³ is used as a process fluid, 0.1-0.2% ML 81B is used as a surfactant;

- used as an emulsion:

water-oil emulsion (WOE) containing commercial oil GOST R-51858-2002 or oil from a well with a water content of not more than 10%, emulsifier MIA-prom grade V (TU 4852-01127913102-2001), reservoir mineralized water with a density at 20° With 1.16-1.18 g / cm ³ with the addition);

or an oil-free emulsion (BNE) containing the ITPS-013G emulsifier (TU 20.59.42-043-27913102), which is a complex of surfactants based on a hydrocarbon solution of alkanolamine esters of oleic acid, mineralized water with a specific gravity of 1.07- 1.18 g/ ^cm3 . In appearance, the emulsifier is a colorless to brown liquid with an opalescence tolerance, the pour point of the reagent is not higher than minus 50°C, the density at 20°C is not less than 0.80 g/cm ³ (RU patent No. 2705675).

To perform acid treatment use:

- a water-oil emulsion or BNE is used as a diverting fluid:

a water-oil emulsion containing commercial oil GOST R-51858-2002 or oil from a well with a water content of not more than 10%, emulsifier MIA-prom grade V (TU 4852-01127913102-2001), formation mineralized water with a density at 20 ° C 1, 16-1.18 g/cm ³ with the addition of MIA-prom grade B (TU 4852-01127913102-2001);

or BNE containing emulsifier ITPS-013G (TU 20.59.42-043-27913102), which is a complex of surfactants based on a hydrocarbon solution of alkanolamine esters of oleic acid, mineralized water with a specific gravity of 1.12-1.18 g /cm ³ . In appearance, the emulsifier is a liquid from colorless to brown with a tolerance of opalescence, the pour point of the reagent is not higher than minus 50°C, the density at 20°C is not less than 0.80 g/cm ³ (patent RU No. 2705675);

- as a solvent, a petroleum paraffin solvent (RPN), a hydrocarbon solvent based on light fractions of paraffinic hydrocarbons, obtained in the process of preparing oil by thermal methods, is used, representing a light brown liquid, with a density of 640-700 g / cm ³ , initial boiling point 20 ° C, vapor pressure at 20°C 395 mmHg, viscosity 0.51 cps, autoignition temperature 255°C, for example TU 0251-062-00151638-2015 and TU 0251-062-00151638-2006;

- used as an acid composition:

inhibited synthetic hydrochloric acid (grades a, b, c, d) according to TU 2458-001-78685855-2016 for oil and gas production, containing additives that improve filtration characteristics;

or PAKS, which is an aqueous solution of 20-24% inhibited hydrochloric acid with the addition of surfactants (0.5-2%), isopropyl alcohol (3-5%), acetic acid (3-5%), demulsifier (2- 4%). The composition has improved physical, chemical and technological properties, and parameters for the dissolution of carbonate rock and cement, for dynamic viscosity, inhibition of the deposition of iron-containing deposits and emulsion formation according to TU 20.59.42-006-13004554-2018;

or the composition of hydrochloric acid ITPS RS brand A according to TU 2458-193-83459339-2009;

or hydrochloric acid inhibited 15-24% concentration with the addition of an ennobling surfactant, for example ML 81B with a concentration of 1%. The composition has surface-active properties for the treatment of terrigenous rocks containing carbonate cement according to TU 2458-526-05763441-2010.

To perform squeezing, an improved process fluid with surfactant with a density at 20°C of 1.0-1.18 g/cm ³ is used, if necessary, with a weighting of the specific gravity, taking into account the temperature regime and reservoir pressure. As a surfactant, ML-81B is used, which is an aqueous solution of a mixture of anionic, non-genic surfactants and ethylene glycol according to TU 2481-007-48482528-99.

The essence of the method is as follows.

The method of treatment of the near-wellbore zone includes determining the type and concentration of the acidic composition, the type of solvent, diverter fluid and modifying additives by pumping chemical reagents through previously selected core samples and conducting core studies. Data is collected and processed based on the results of previously performed core sampling, core filtration studies, determination of the geological and physical characteristics of the reservoir, features of the void space, modes of previously performed acid treatments of the well. An analysis is carried out for the compatibility of the acid composition with the formation fluid of the treated well. The design of the near-wellbore zone acid treatment is designed using a computer program, taking into account the obtained analysis results, taking into account the geological and physical characteristics of the reservoir, the features of the void space, core filtration studies and the modes of the previously performed acid treatment of the reservoirs. The optimal consumption of reagents, the number of rims of the diverting fluid, solvent, acid composition and modifying additives, the sequence of rims, specific volume and assessment of the type of acid composition and type of diverting fluid selected from previous studies are determined. The result of designing the acid treatment of the near-wellbore zone is the calculation of the dynamically changing skin factor, the depth of penetration of chemical compositions, changes in bottomhole pressure during the treatment of the near-wellbore zone. The design of the acid treatment of the near-wellbore zone is carried out, for example, using the STIMPRO ^TM software product.

Before treatment of the near-wellbore zone in the well, pressure testing of the tubing string with a pump at a pressure of P - 4 MPa by a downhole drive is performed at least a day before. If the equipment is tight, the technique is approached to the well. A back pressure of 8 MPa is created in the tubing by a pumping unit to prevent overflow when pumping the acid composition through the pump into the tubing and the oil gathering system. Close the pipe space from above.

An injection test is performed by pumping through the annular space in a 2-fold volume of the annulus of a process fluid with a surfactant at a flow rate of 0.1-2.0 m ³ /min or an emulsion at a flow rate of 0.1-0.25 m ³ /min (flow rate up to 0.25, at a flow rate higher, there is a risk of a whipstock breakthrough in the formations into watered areas or behind-the-casing circulation), taking into account previously performed treatments with low wellhead pressures, depending on the specific injectivity coefficient with the process fluid (table 1).

Table 1

Specific coefficient
injectivity, m ³ / (MPa⋅h) Volume
emulsions, m ³ 0.5 to 1.0 2-3 1.1 to 1.5 4-5 1.51 to 2.0 6-8 2.1 to 3.0 8.1-10 3.1 to 4.0 10-14 4.1 to 6.0 14-18 6.1 or more over 20

The obtained test results are entered into a computer program and the volume and viscosity of the diverter fluid, the rock fracture gradient, permeability are determined, then changes are made to the project in terms of the allowed optimal pressure on the productive formations, but not more than the allowed pressure on the production string, optimal flow rates and injection volumes, number of download cycles. According to the results of the injection test, the preparation of the diverter fluid in the required volume on the well is determined, the optimal ratio of the volume of the diverter fluid to the volume of the acid composition and the volume of the process fluid for squeezing is determined.

Next, a diverter fluid with a viscosity of 600-2000 cps is sequentially pumped at a flow rate of 0.1-0.25 m ³ /min, a solvent at a flow rate of 0.1-0.2 m ³ /min, an acid composition at a flow rate of 0.1- 2.0 m ³ /min with a specific volume of 1-10 m ³ per 1 meter of the perforated interval, which corresponds to one injection cycle, based on pre-selected volumes of reagents, the number of injection cycles depending on the permeability or injectivity obtained as a result of the test injection performed and computer processing. Squeezing is carried out with process fluid in a volume equal to the volume of the annular space at a flow rate of 0.1-2.0 m ³ /min.

After the reaction, the well is tied with a trough system, the well is put into operation and mastered into the trough system by a pump in a double volume of displacement fluid until production with a pH of more than 4 is obtained.

The injection cycle of the diverter fluid, solvent, acid composition is repeated until a full coverage of the formation is obtained, the process fluid is forced through in a volume equal to the volume of the annular space at a flow rate of 0.1-2.0 m ³ /min, taking into account the additionally selected volume according to the corrected design . To wash out the screen created by the diverter fluid in the previously depleted zones of the productive formation and after treating the uncovered zones with an acidic composition, before the acid composition is forced by the process fluid, a solvent is pumped in a volume of at least 4% of the total amount of the diverter fluid. In the process of performing work on the well, it is possible to vary the viscosity of the diverter fluid according to the results of the injection test directly on the object.

The proposal provides for an increase in the efficiency of treatment of the near-wellbore zone by improving the quality and reducing the time of operations while reducing friction losses during injection of the emulsion, increasing the accuracy of selecting the volume and viscosity of the diverter fluid, the ratio of the volume of the diverter fluid to the volume of the acid composition and the volume of the process fluid for squeezing , increasing the wetting area of the productive formation with the solvent and the efficiency of removing the bridging film, reducing the time for preparing an oil-free emulsion, eliminating the risk of acid composition breakthrough and obtaining inter-layer and behind-the-casing circulation, temporary blocking of formation intervals with a high specific injectivity coefficient, increasing the efficiency of acid impact on the carbonate formation due to improving reservoir properties and increasing the depth and area of dissolution channels, as well as increasing the flow rate by increasing the area of fluid inflow to the near-wellbore zone, reducing the duration of well recovery, and reducing the cost of selective acid treatment. Also, the method eliminates the aggressive impact on the downhole pumping equipment and the approach of the well workover crew, and expands the technological capabilities of the method for treating the near-wellbore zone.

The method of processing the near-wellbore zone is carried out in the following sequence.

The selection of wells for performing selective acid treatments of the near-wellbore zone along the annular space is carried out in the drilled areas according to the previously performed results of the core study, laboratory filtration studies with the determination of the geological and physical characteristics of the reservoir, features of the void space, and in the bulk based on the data of previously performed acid treatments ( on pressure, flow rate and volume of pumped fluids). Based on the collected data in a specialized licensed computer program, the treatment design of the near-wellbore zone is designed and the volumes and flow rates of liquids are calculated during injections and allowable pressures. The selection of acid compositions is carried out on the basis of previous studies of the interaction of the diverter fluid, solvent, acid composition with the rocks of productive carbonate formations in certain fields.

An analysis is carried out in the field laboratory for the compatibility of the acid composition with the previously selected formation fluid of the treated well in a mixture of: 25%, 50%, 75% and in a mixture of 50% with the addition of 3-valent iron, then a sieve is performed

analysis for the passage of a mixture of acidic composition with reservoir fluid through a 100 MESH sieve. With negative results - no separation between the acid composition and reservoir fluid, and failure of the sieve analysis (formation of a sludge complex)

an iron stabilizer is added and an increase in a multiple ratio with respect to the acid composition in the mixture is performed. The volumes, type and concentration of the acid composition, types of solvent, diverter fluid are determined by pumping the chemicals used through the previously selected core samples. The design of the acid treatment of the near-wellbore zone is designed using a computer program, taking into account the geological and physical characteristics of the formation, the features of the void space, filtration studies of the core and the modes of the previously performed acid treatment of the formations (see tables 2, 4). Before injection through the annular space, the tubing string is pressure tested with a pump of 8 MPa unit, back pressure is created in the tubing string to determine the tightness and prevent the acid composition from flowing into the tubing. Close the pipe space from above. Then, an injection test is performed, at the same time, process fluid with surfactant is pumped into the annular space in 2-fold volume of the annulus at a flow rate of 0.1-2.0 m ³ /min or an emulsion with a flow rate of 0.1-0.25 m ³ / min, taking into account earlier treatments with low wellhead pressures, with a specific injectivity coefficient from 0.5 to 1.0 m ³ /(MPa⋅h), the injection volume is 2-3 m ³ , with a specific injectivity coefficient from 1.1 to 1.5 m ³ /(MPa⋅h) the injection volume is 4-5 m ^{3 ,} the specific injectivity coefficient is from 1.6 to 2.0 m ³ /(MPa⋅h) with an injectivity coefficient from 2.1 to 3.0 m ³ /(MPa⋅h), the injection volume is 8.1-10 m ³ , with a specific injectivity coefficient from 3.1 to 4.0 m ³ /MPa⋅h, the injection volume is 10-14 m ³ , with a specific injectivity coefficient from 4.1 to 6.0 m ³ /MPa⋅h, the injection volume is 14-18 m ³ , with a specific injectivity coefficient of more than 6.0 m ³ /(MPa⋅h) volume injection is more than 20 m ³ . With an increase in pressure during the injection process, the injection is stopped and it is determined how long the pressure will drop, if the pressure drops to 0 atm in more than 5 minutes, it is necessary to recalculate the prepared emulsion in the downward direction - volumes, solvent consumption and acid composition and viscosity of the diverter fluid . If there is no increase in pressure, prepare and pump the entire volume of the emulsion without stopping until signs of a stable increase in pressure appear.

The obtained test results are entered: pressure, flow rate, specific gravity of the fluid used in a specialized licensed program and determine the rock fracture gradient, permeability. The volume, pressure and injection flow rate of the process itself are recalculated based on the injection test data. Determine the required volume of diverter fluid (see Table 3, 5). The optimal ratio of the volume of the diverter liquid to the volume of the acid composition and the volume of the process liquid per squeezing is determined based on the injection test performed. At high injectivity, a high-viscosity emulsion is injected (may vary in viscosity) until the maximum pressure on the reservoirs and the production string is reached, then changes are made to the project in terms of the allowed maximum pressure, maximum flow rates and injection volumes.

The diverter fluid is prepared before injection at the well.

Sequential pumping of a diverter liquid with a viscosity of 600-2000 cps at a flow rate of 0.1-0.25 m ³ /min, a solvent at a flow rate of 0.1-0.2 m ³ /min, which ensures wetting of the treated productive formation, improves the quality of washing the carbonate reservoir rocks before pumping the acid composition and washing off the clogging film, the acid composition at a flow rate of 0.1-2.0 m ³ /min with a specific volume of 1-10 m ³ per 1 meter of the perforated interval,

When used as an emulsion diverter, injection of an acid composition with a volume of 1-10 ^m annular circulation. When using an oil-free emulsion as a diverter, before leaving the base, an emulsifier is added to the tank trucks, on the way to the well, mineralized water with a specific gravity of 1.12-1.18 g/cm ³ in a volume fraction of 91 is added from the process fluid preparation unit in a certain proportion -93% of the emulsifier (average 0.9-0.7 m ³ emulsifier, 9.1-9.3 m ³ process fluid per 10 m ³ prepared emulsion). Due to this, on the way to the well during the delivery of the reagents, the actual mixing and preparation takes place, which reduces the time for the preparation of an oil-free emulsion and the process of treating the near-wellbore zone. At the well, mixing is additionally performed until a homogeneous mass with the required viscosity is obtained. To obtain an emulsion with a viscosity of 600 to 1500 centipoise, a 9% emulsifier and mineralized water with a specific gravity of 1.12-1.18 g/cm ³ in a volume fraction of 91% are used, the preparation time is from 1 to 2 hours. If it is necessary to prepare an emulsion with a viscosity of 1500 cP and above, mineralized water is used with a specific gravity of 1.12-1.18 g/cm ³ in a volume fraction of 93% emulsifier 7% dynamic viscosity varies with the duration of mixing and can reach more than 2000 cP.

When using a water-oil emulsion, the tank truck is filled with marketable oil or oil from a well with a water percentage of not more than 10% in the product, after arriving at the well, emulsifier MIA-prom grade V (TU 4852-01127913102-2001) is added and mixed, then formation mineralized water with specific weighing 1.16-1.18 g / cm ^3. Depending on the requirements for the viscosity of the emulsion according to the results of the injection test, the recipe for preparation: emulsifier 4%, process fluid 60%, oil 36%, the resulting viscosity is 600-1500 cP. with a viscosity of 1500-2000 cP and higher: emulsifier 2.7%, mineralized water 1.16-1.18 g / cm ³ - 85.3%, oil - 12% Viscosity varies with mixing time.

When preparing a diverter fluid, a Grase M3600 viscometer and analogues are used to determine the dynamic viscosity.

At the well, two units (SIN-32 or SIN-35) or a unit with 2 pumps are used when performing work. One unit (pump) constantly mixes the reagents until an emulsion of the required viscosity is obtained. The second pump unit simultaneously pumps the emulsion into the well. At a flow rate of 0.1-0.25 m ³ /min of the emulsion, the required volume of the emulsion is simultaneously prepared for the next stage, which makes it possible to treat the well without interruption and increase the volume of the emulsion if necessary.

After the response, the well is tied up with a trough system (tank), the well is put into operation and mastered into the trough system by a pump in a double volume of displacement fluid with sampling until production with a pH of more than 4 is obtained.

The injection cycle of the diverter fluid, solvent, acid composition is repeated until a full coverage of the formation is obtained, the process fluid is forced through in a volume equal to the volume of the annulus at a flow rate of 0.1-2.0 m ³ /min, taking into account the additionally selected volume. In order to destroy the screen created by the diverter fluid in the previously depleted zones of the productive formation and after treating the uncovered zones with an acid composition, a solvent is pumped in a volume of at least 4% of the total amount of the emulsion with a process fluid before the acid composition is forced through with a process fluid. At the same time, the planned indicators are achieved in terms of the depth of penetration of chemical reagents and the skin factor.

The method of treatment of the near-wellbore zone of the formation ensures the performance of acid treatment in the annular space without the approach of a well workover team and the performance of tripping operations with GNO, including in wells with simultaneous-separate production and low reservoir pressure, eliminates the aggressive impact on the downhole pumping equipment through the use of highly effective additives.

EFFECT: invention provides the possibility of predicting the performance of treatment of the near-wellbore zone, performing the selection of volumes and reagents based on the results of previous treatments and a computer program for simulating the injection process. The efficiency of treatment of the near-wellbore zone increases (see tables 6, 7) by improving the quality and reducing the time of operations while reducing friction losses when pumping the diverter fluid, increasing the accuracy of selecting the volume and viscosity of the diverter fluid, increasing the wetting area of the reservoir with solvent and the efficiency of removing the clogging film, reducing the time of preparation of the diverter fluid, eliminating the risk of breakthrough acid compositions and aggressive impact on downhole pumping equipment and obtaining inter-layer and behind-the-casing circulation, temporary blocking of reservoir intervals with a high specific injectivity coefficient, increasing the efficiency of acid impact on the carbonate reservoir for by improving the reservoir properties and increasing the penetration depth, the area of dissolution channels, as well as increasing the flow rate after treatment by increasing the area of fluid inflow to the near-wellbore zone, reducing the cost of selective acid treatment. The method also makes it possible to expand the arsenal of technological possibilities for processing the near-wellbore zone of a carbonate formation.

table 2

Processing plan (design)

Plan: Process Fluid Test at 0.25 ^m3 /min

(determine the volume and viscosity of the diverter fluid, rock fracture gradient, permeability)

The volume of the deflector - 7 m ³

The volume of the acid composition is 10.5 m ³

On-load tap-changer volume - 3 m ³

stage number Reagent name Stage type Initial consumption, m ³ / min Final consumption, m ³ / min Reagent volume,
m ³ Stage time, min 1 Process water with surfactants Injection test 0.30 0.30 9.0 36.0 2 Stop download 60.0 3 BNE(VNE) deflector viscosity 1000cP Deviation 0.20 0.10 7.0 31.10 4 OLTC solvent flushing 0.10 0.10 3.0 20.0 5 Acid composition basic acid 0.10 0.10 1.50 15.0 6 Acid composition basic acid 0.10 0.80 9.0 20.0 7 Industrial water with surfactants Selling 0.23 0.20 7.0 35.0 8 Total volume of injected reagents and injection time 36.5 197.10

Table 3

Processing plan (redesign) based on the results of the injection test on the process fluid (see table 2).

Plan: Fact test on process fluid at 0.7 ^m3 /min

The volume of the diverter - 30 m ³

The volume of the acid composition is 10.5 m ³

On-load tap-changer volume - 6 m ³

stage number Reagent name Stage type Initial consumption, m ³ / min Final consumption, m ³ / min Reagent volume,
m ³ Stage time, min 1 BNE diverter (VNE) with a viscosity of 1500 cP Deviation 0.25 0.10 30.0 171.0 2 OLTC solvent flushing 0.10 0.05 3.0 40.0 3 Acid composition basic acid 0.05 0.45 4.50 18.0 4 BNE diverter (VNE) with a viscosity of 1500 cP Deviation 0.2 0.05 20.0 160.0 5 OLTC solvent flushing 0.05 0.05 3.0 60.0 6 Acid composition basic acid 0.05 0.30 6.0 34.3 7 Industrial water with surfactants Selling 0.30 0.35 6.0 21.50 8 Total volume of injected reagents and injection time 72.5 505.2

Table 4

Processing plan (design)

Plan: Test for BNE (BNE) viscosity 1000 cP with a flow rate of 0.1 m ³ /min

The volume of the diverter - 25 m ³

The volume of the acid composition - 15 m ³

On-load tap-changer volume - 2 m ³

stage number Reagent name Stage type Initial consumption, m ³ / min Final consumption, m ³ / min Reagent volume, m ³ Stage time, min 1 BNE diverter (VNE) viscosity 1000 cP Injection test 0.1 0.1 15.0 95.0 2 Stop download 60.0 3 BNE diverter (VNE) viscosity 1520 cP Deviation 0.10 0.05 10.0 100.0 4 OLTC solvent flushing 0.05 0.05 2.0 30.0 5 Acid composition basic acid 0.05 0.20 1.50 15.0 6 Acid composition basic acid 0.20 0.20 13.5 30.0 7 Industrial water with surfactants Selling 0.20 0.20 7.0 40.0 8 Total volume of injected reagents (m ³ ) and injection time (min) 51.0 400.0

Table 5

Treatment plan (redesign) based on the results of the injection test on the diverter (see table 5).

Plan: BNE Test (BNE) at 0.2 ^m3 /min

The volume of the diverter - 50 m ³

The volume of the acid composition - 15 m ³

On-load tap-changer volume - 6 m ³

stage number Reagent name Stage type Initial consumption, m ³ / min Final consumption, m ³ / min Reagent volume,
m ³ Stage time, min 1 BNE diverter (VNE) viscosity 2000 cP Deviation 0.20 0.10 50.0 250.0 2 OLTC solvent flushing 0.10 0.05 6.0 60.0 3 Acid composition basic acid 0.05 0.20 15.0 60.0 4 Industrial water with surfactants Selling 0.20 0.20 7.0 7.5 Total volume of injected reagents (m ³ ) and injection time (min) 78.0 410.0

Table 6

Number of stages Skin factor Average penetration depth Oil production rate, tons Plan (design) Fact (redesign) Plan (design) Fact (redesign) Plan,
m Fact,
m Plan, t/day Fact, t/day 7 7 -2.64 -2.79 6.71 9.59 1.25 1.35

Table 7

Number of stages Skin factor Average penetration depth oil flow rate,
tn Plan (design) Fact (redesign) Plan (design) Fact (redesign) Plan,
m Fact,
m Plan, t/day Fact, t/day 7 4 -2.78 -2.78 7.54 9.28 1.34 1.34

Claims (2)

1. A method for treating a near-wellbore zone, including determining the type and concentration of the acid composition, the type of solvent, the type of diverter fluid and modifying additives by analyzing the filtration studies of the core - pumping chemicals through previously selected core samples, analyzing the compatibility of the acid composition with the formation fluid of the treated well, designing design of acid treatment of the near-wellbore zone using a computer program, taking into account the geological and physical characteristics of the reservoir, the features of the void space, the results of the preliminary analysis of the core filtration studies, the analysis of the compatibility of the acid composition with the reservoir fluid of the treated well and the modes of the previously performed acid treatment of the reservoirs, the injection of the acid composition, solvent, diverter fluid, characterized in that before treatment of the near-wellbore zone in the well, at least a day before, the tubing string with a borehole drive pump is pressure tested, a back pressure of 8 MPa is created in the tubing string with a pump to determine the tightness and eliminate the flow of acid composition through the pump in the tubing, the pipe space is closed from above, then an injection test is performed - a process fluid is pumped into the annular space - formation water with a density at 20 ° C of 1.0-1.18 g/cm ³ containing 0.1-0, 2% surfactant surfactant ML 81B, in a 2-fold volume of the annular space with a flow rate of 0.1-2.0 m ³ /min or an emulsion with a flow rate of 0.1-0.25 m ³ /min, which use an oil-in-water emulsion containing commercial oil or oil from a well with a water content of not more than 10%, an emulsifier MIA-prom grade B, formation mineralized water with a density at 20 ° C of 1.16-1.18 g/cm ³ , or an oil-free emulsion containing emulsifier ITPS-013G, which is a complex of surfactants based on a hydrocarbon solution of alkanolamine esters of oleic acid, and mineralized water with a specific gravity of 1.07-1.18 g / cm ³ , taking into account previously performed treatments with low wellhead pressures at a specific injectivity coefficient from 0.5 to 1.0 m ³ /(MPa⋅h) the injection volume is 2-3 m ³ , with a specific injectivity coefficient from 1.1 to 1.5 m ³ /(MPa⋅h ) the injection volume is 4-5 m ³ , with a specific injectivity coefficient from 1.6 to 2.0 m ³ /(MPa⋅h) the injection volume is 6-8 m ³ , with a specific injectivity coefficient from 2.1 to 3, 0 m ³ /(MPa⋅h), the injection volume is 8.1-10 m ³ , with a specific injectivity coefficient from 3.1 to 4.0 m ³ /(MPa⋅h), the injection volume is 10-14 m ³ , with specific injectivity from 4.1 to 6.0 m ³ /(MPa⋅h), the injection volume is 14-18 m ³ , with a specific injectivity coefficient of more than 6.0 m ³ /(MPa⋅h), the injection volume is more than 20 m ³ , with an increase in pressure during the injection process, the injection is stopped and the time it takes for the pressure to drop is determined; if the pressure drops to 0 atm in more than 5 minutes, the volumes, solvent consumption and acid composition and viscosity of the diverter fluid are recalculated in the direction of decreasing, in the absence of pressure increase, prepare and pump the entire volume without stopping until signs of a stable pressure increase appear, enter the results of the injection test into a computer program and determine the volume and viscosity of the diverter fluid, the rock fracture gradient, permeability, the optimal ratio of the diverter fluid volume to the volume of the acid composition and the volume of the process fluid, then changes are made to the design of the project in terms of the permitted optimal pressure on the productive formations, but not more than the permitted pressure on the production string, optimal costs and injection volumes, the number of injection cycles, then at least one injection cycle is performed - sequential injection of liquid - diverter with a viscosity of 600-2000 cps with a flow rate of 0.1-0.25 m ³ /min, a solvent with a flow rate of 0.1-0.2 m ³ /min, an acid composition with a flow rate of 0.1-2.0 m ³ /min with a specific volume of 1-10 m ³ per 1 meter of the perforated interval, and the solvent is pumped in a volume of at least 4% of the volume of the diverter fluid, and a water-oil emulsion containing commercial oil or oil from a well with a water content of not more than 10%, emulsifier MIA-prom grade B, reservoir mineralized water with a density at 20°C of 1.16-1.18 g/cm ³ or an oil-free emulsion containing emulsifier ITPS-013G, which is a complex of surfactants based on a hydrocarbon solution of alkanolamine esters of oleic acid, mineralized water with a specific gravity of 1.12-1.18 g / cm ³ , the process liquid is squeezed in a volume equal to the volume of the annular space with a flow rate of 0.1-2.0 m ³ /min , after the response, the well is tied with a trough system, the well is put into operation and mastered into the trough system by a pump in a double volume of displacement fluid until a well product with a pH of more than 4 is obtained. 2. The method according to p. 1, characterized in that the injection cycles of the diverter fluid, solvent, acid composition are repeated until a full coverage of the formation is obtained.