RU2482152C1 - Borehole process fluid with low damaging properties and controlled absorption in thermobaric formation conditions - Google Patents

Abstract

FIELD: chemistry.

SUBSTANCE: invention relates to oil-and-gas industry and particularly to preparation of a borehole process fluid which can be used for well drilling, killing or flush-out. The borehole process fluid with controlled absorption in thermobaric formation conditions contains the following per 1 m³, kg: xanthan 7.5-15, polyanionic cellulose 2.5-5, solid sodium chloride up to 483, saturated sodium chloride solution - the balance.

EFFECT: resistance to thermal decomposition, providing efficient control of absorption during work over of production wells, providing high coefficient of recovery of oil relative permeability and preserving reservoir properties of the bottom-hole zone.

4 tbl, 3 dwg

Description

The invention relates to the oil and gas industry, in particular to the creation of a downhole technological fluid with controlled absorption in thermobaric conditions of an oil, oil and gas or gas reservoir, which can be used for drilling, killing or flushing wells.

Fluids to reduce absorption must meet certain requirements regarding their optimal filtration and viscosity characteristics in the surface and thermobaric conditions of the formation, the possibility of injection into the well and placement at a predetermined interval, preservation of the reservoir properties of the bottomhole formation zone, and the availability of composite components. Their component composition should provide the ability to regulate structural-mechanical, rheological and some other properties.

The main way to reduce absorption during the repair of wells is the use of blocking liquids [V.N. Gusakov, S.E. Zdolnik, A.G. Telin, I.M. Zgoba. The problems of killing wells in the Priobskoye field and ways to solve them. // “Scientific and Technical Bulletin of Rosneft Oil Company, 2006, No. 1, pp. 1-5].

To control absorption during the creation of process fluids, the use of the following techniques is described:

- increase the effective viscosity of the process fluid through the use of thickeners [for example, RF patent No. 2301247];

- increasing the effective viscosity of the process fluid by generating emulsions [for example, RF patent No. 2296791],

- increase the effective viscosity of the process fluid by generating dispersed systems in which the dispersed phase is gas [for example, RF patent No. 2322472];

- reducing the permeability of the absorption zone by using shunt particles — microcalcite as a solid phase in the process fluid to form a filter cake [SPE 58734. M.R. Luyster, W.E. Foxenberg, (M-I LLC), S.A. Ali Chevron Petroleum Technology Company. Development of a Novel Fluid-Loss Control Pill for Placement Inside Gravel-Pack Screens].

The main disadvantage of emulsions generated on vegetable or petroleum oils [RF patent No. 2319539], oil [RF patent No. 2306414], kerosene or diesel fuel [RF patent No. 2297436], hydrocarbon solvents [RF patent No. 2296791] using oil-soluble surfactants (emulsifiers ) of different nature is the rapid (1-2 days) destruction of emulsions at low (40-80 ° C) temperatures, the inability to provide control of absorption under thermobaric conditions of the reservoir for a period of more than 48 hours, necessary for underground repair of Azhinov with absorption control.

As water-soluble polymers for thickening water and aqueous solutions, it is known to use:

- guar gum (hydroxypropyl guar, hydroxypropyl carboxymethyl guar, carboxymethyl guar) [RF patent No. 2330942], the main disadvantage of which is its good solubility in fresh water (density of about 1000 kg / m ³ ), the inability to thicken higher-density saline solutions of halite and calcium salts (chloride (bromide, nitrate), low sedimentation stability of suspensions of solid particles in water thickened with guar gum, a significant decrease in the effective viscosity of water thickened with guar gum with increasing temperature, leading to its loss of viscosity, rapid destruction of suspensions and absorption of fluid, which makes it impossible to use these fluids for underground well repairs at elevated temperatures or reservoir pressures above hydrostatic or the need to control absorption for more than 48 hours;

- carboxymethyl cellulose [RF patent No. 2301247] in the following ratio of ingredients, wt.%: carboxymethyl cellulose 0.5-2.0, calcium chloride 7-12, ammonium phosphate disubstituted 19-21, Morpen 0.05-1.00, water the rest , the main disadvantage of which is the thickening ability with respect to fresh water (density about 1000 kg / m ³ ) and halite solutions (limiting the density to 1180 kg / m ³ ), the inability to thicken higher-density saline solutions of calcium salts (chloride, bromide, nitrate) low sedimentation stability of tv suspension particles in water and saline solutions thickened with carboxymethyl cellulose, the rapid destruction of suspensions (low sedimentation stability) and the absorption of blocking fluid;

- polyacrylamide [RF patent No. 2215868] or crosslinked polyacrylamide, for example, radiation [RF patent No. 2285786] or chemical crosslinkers [RF patent No. 2190753], the main disadvantage of which is the solubility of polyacrylamide only in fresh water (density of about 1000 kg / m ³ ) and halite solutions (limiting the density to 1180 kg / m ³ ), the inability to thicken higher-density saline solutions of calcium salts (chloride, bromide, nitrate), low sedimentation stability of suspensions of solid particles in water and saline halite, gelled polyac rilamide, a significant decrease in the effective viscosity of water and aqueous solutions thickened with polyacrylamide with increasing temperature, leading to a loss of viscosity at elevated temperatures, the absorption of blocking fluid, which is unacceptable for safe underground well repair;

- succinoglycan [SPE 26724. Hon Chung Lau. Laboratory Development and Field Testing of Succinoglycan as a Fluid-Loss-Control Fluid (Shell Development Co)].

Succinoglycan biopolymer has a unique combination of properties, including ease of use; cleanliness; thixotropic rheological properties; temperature-independent viscosity below the transition temperature loss viscosity T _m .

The main limitation on the use of succinoglycan is its incompatibility with formulations based on calcium salts (chloride, bromide) and zinc. These mineralized solutions significantly reduce the temperature loss of succinoglycan viscosity (T _m ). For example, T _m in solutions of calcium bromide with a density of 12 lb / gall and 12.9 lb / gall is 65 ° C and 55 ° C, respectively, which makes it impossible to use it to control absorption in blocking fluids in wells with reservoir temperatures above 55 ° C.

To increase T _m and the density of succinoglycan solutions, mineralized solutions based on potassium and sodium formates can be used. At sufficiently high concentrations, these salts can increase the T _{m of} succinoglycan to 93 ° C. However, these salts are inaccessible due to the price and lack of their production in the Russian Federation.

Also for thickening water and aqueous solutions, it is known to use:

- derivatives of synthetic fatty acids: sodium naphthenate (15-18%), synthetic fatty acids of fraction C ₁₆ and above, bottoms of the production of synthetic fatty acids of fraction C ₂₀ and above, tall oil fatty acids, Neftekhim-3, tariff [application No. 2001108932, 2003], the main disadvantage of which is the salting out (separation from solutions) of thickeners from salt solutions with increasing salt content and / or with increasing temperature, a significant decrease in the effective viscosity of water and aqueous thickened solutions with increasing salinity Ia or temperature, leading to a loss in viscosity at elevated temperatures and loss absorption blocking fluid control, which is unacceptable when conducting workover wells uptake control;

- hydroxyethyl cellulose, the main disadvantage of which is the loss of viscosity at temperatures above 79 ° C; even pure preparations require gel filtration to remove insoluble particles; does not form a filter cake. Described by [SPE 80946. Brian Evans (BJ Services). Fluid Loss Control - Improvement for HTHP Wells] there are many cases of high residual resistance, the reason is the transfer of corrosion fragments (particles) and sludge from the well into the formation, it is considered a "damaging" reagent. The main disadvantage of hydroxyethyl cellulose is the limitation on thermal stability, loss of viscosity at elevated temperatures, which does not provide (as will be shown below) the sedimentation stability of suspensions of solid particles for a period of more than 48 hours, which is necessary for underground repair of a well with absorption control;

- crosslinked hydroxyethyl cellulose (SCE) with an alkalizing acidity regulator and a zirconium crosslinker. The cross-linked HEC is stable up to 90 ° C in solutions with a density of up to 1080 kg / m ³ and is not able to thicken solutions of a higher density with the same thermal stability [SPE 39438, F.F. Chang, M. Bauman and M. Palar, S.A. Ali, J. Crom, Schlumberger Dowell, Chevron USA, Texaco Inc. Development of new formulations for controlling absorption based on crosslinked hydroxyethyl cellulose for use in formations with a high positive differential pressure, high permeability and / or high temperature]. The main disadvantage of crosslinked SCE is the density limitations, the difficulty of providing specific conditions for polymer crosslinking in the alkaline region (pH above 10.5), where an expensive crosslinker based on zirconium salts is operable, and low viscosity of SCE solutions that does not provide sedimentation stability of suspensions for more than 48 hours needed for underground well repair with absorption control;

- xanthan gum [RF patent No. 2212527]: an aqueous solution of carnallite ore with a solution density of 1.23-1.25 t / m ³ is used as a quenching liquid, and xanthan gum in an amount of 0.1-1.0 wt. %, the main disadvantage of which (as will be shown below) is the loss of viscosity at elevated temperatures and low sedimentation stability of suspensions of solid (shunt) particles;

- xanthan in a mixture with modified starch [RF patent No. 2322472] and aluminum powder additives for generating an aphron (disperse system in which the dispersed phase is gas, in this example hydrogen) in the following ratio of components, wt.%: microbial xanthan biopolymer 0 5-2.0; modified starch 0.2-2.5; Surfactant 0.01-0.2; sodium carbonate 0.1-1.0; aluminum powder - 0.005-0.08; water - the rest; the main disadvantage is the loss of viscosity at elevated temperatures and low sedimentation stability of suspensions of solid particles that do not provide sedimentation stability of suspensions for a period of more than 48 hours, necessary for underground repair of a well with absorption control;

- suspensions of xanthan powder and / or other derivatives in a dosage of 10-70% (hydroxyethyl cellulose, carboxymethyl cellulose, guar gum, starch, guar derivatives, polyacrylamide) in a mixture with a suspension additive (0.1-0.9%) (hydroxypropyl cellulose, ethyl cellulose, polyvinylpyrrolidone, polyacrylic acid and copolymers of polyvinylpyrrolidone and acrylic acid) with non-aqueous solvents 30-90% [RF patent No. 2287549], the main disadvantage of which is the impossibility of increasing the density of the mixture by dissolving water-soluble salts and associated with these restriction of use only in wells with low reservoir pressure (below hydrostatic), high price and inaccessibility of non-aqueous solvents selected from the group consisting of glycols, polyglycols, simple glycol ethers, glycol ethers and mixed simple and complex glycol ethers, diethylene glycol, triethylene glycol, polypropylene glycol, diethylene glycol ethyl ether and diethylene glycol butyl ether;

- non-polymer zwitterionic viscoelastic surfactants. Quite close to the claimed composition is a composition developed by Schlumberger [RF patent No. 2307144], using a thickener of water-salt solutions (with a density of at least 11.5 pounds per gallon, i.e. 1378 kg / m ³ ) in an amount of 2-30%, in which non-polymer zwitterionic viscoelastic surfactants are proposed - erucilamidopropyl betaine or oleylamidopropyl betaine with the general formula:

where R ₁ , R ₂ , R ₃ , R ₄ and R ₅ are carbon atoms or chains of carbon atoms, saturated or unsaturated, with one or multiple unsaturation, straight chains, branched chains or cyclic, including aromatic and alicyclic groups, and R ₁ contains 16-26 carbon atoms, R ₂ contains 2-10 carbon atoms, R ₃ , R ₄ and R ₅ contain 1-6 carbon atoms.

The authors [RF patent No. 2307144] showed that these liquids, unique in rheological properties, in solutions of high density calcium and sodium salts can not decrease in a certain temperature range, and in some salt solutions even increase the effective viscosity of solutions with increasing temperature. At temperatures of about 100 ° C, they provide solutions with an effective viscosity of 0.4 Pa · sec to 28 Pa · sec (at a shear rate of 1 s ^-1 ), which ensures stability of shunt solids suspensions and control of absorption in thermobaric conditions of high reservoir wells temperature due to increased viscosity. The main disadvantages of this invention are:

- high density of saline solutions ("at least 1318 kg / m ³ " - claim 1 of the claims) and the inability to work with fresh water and saline density solutions of less than 1318 kg / m ³ ;

- the need to use expensive and inaccessible zwitterionic surfactants - derivatives of erucilamidopropyl betaine or oleylamidopropyl betaine, manufactured under the control of the Schlumberger Company outside the Russian Federation.

The prototype of the claimed composition is a technological well fluid [RF patent No. 2380391, publ. January 27, 2010], which contains xanthan gum - from 3 kg / m ³ to 20 kg / m ³ ; polyanionic cellulose - from 3 kg / m ³ to 20 kg / m ³ ; calcium chloride in an amount of up to 37 wt.% or calcium nitrate in an amount of up to 74 wt.%.

The main disadvantage of the prototype fluid, as will be shown by filtration experiments on oil-saturated core material, is that this composition provides very low recovery coefficients of phase permeability for oil, which degrades the filtration-capacitive properties of the bottom-hole zone of wells, significantly lengthens the time for bringing wells to pre-production flow and pre-water cut of produced fluid.

The problem to be solved and the expected technical results are to create a borehole process fluid that is resistant to thermal degradation, allowing:

- on the one hand, as well as a prototype, to provide effective control of absorption during the underground repair of production wells,

- on the other hand, to ensure a high value of the coefficient of recovery of phase permeability in oil and to maintain the reservoir properties of the bottom-hole zone of wells.

The technological consequence of increasing the recovery coefficient of phase permeability in oil will be:

- reducing the time for production wells to reach the pre-production rate for oil and liquid;

- reduction of the time for producing wells to reach the preset value of the water cut of the produced fluid.

Traditionally, the increase in the recovery coefficient of phase permeability for oil in downhole process fluids is provided in two ways:

- the addition of water repellents - cationic surfactants (CPAS). The specified method provides an increase in the recovery coefficient of phase permeability for oil (experimental results are described below), but does not allow to achieve an increased density (above 1.05 g / cm ³ ) due to the lack of a sufficient amount of salts and the effect of salting out of surfactants with increasing salt content and temperature ;

- the addition of potassium salts (for example, potassium chloride) in an amount of about 5 wt.%. The specified method provides an increase in the recovery coefficient of phase permeability for oil, but does not allow to achieve a density higher than the density of a saturated solution of potassium chloride 1.16 g / cm ³ (which is necessary for wells with high reservoir pressure) and does not allow to control the absorption of such a solution due to its low viscosity and lack of shunt particles.

The task is to create a well fluid with the best set of technological properties, namely with a density of up to 1.4 g / cm ³ , a high recovery coefficient of oil permeability, the ability to control absorption in wells without hydraulic fracturing (hydraulic fracturing), with proppant hydraulic fracturing and with fractured collector.

The problem is solved in that the technological well fluid with controlled absorption in the thermobaric conditions of the formation, containing water-salt solution, xanthan gum and polyanionic cellulose, is characterized in that it contains a saturated solution of sodium chloride and additionally solid sodium chloride at the following ratio of components in 1 m ³ technological well fluid, kg:

xanthan 7.5-15 polyanionic cellulose 2,5-5 solid sodium chloride up to 483 saturated sodium chloride solution - the rest.

Sodium chloride in an amount of up to 310 kg / m ³ to obtain a saturated solution of sodium chloride provides an increase in the density of the liquid to 1190 kg / m ³ .

Sodium chloride in an amount of up to 483 kg / m ³ as a solid phase (shunt particles) serves to control the absorption and to increase the density of the liquid to 1400 kg / m ³ .

The solution of sodium chloride in the inventive process fluid is taken saturated to prevent the dissolution of solid sodium chloride, introduced as a solid, shunt absorption, particles.

Regarding the prototype, thus, calcium salts (calcium chloride or calcium nitrate) are excluded from the inventive technological well fluid and solid sodium chloride is introduced. Experimental verification showed that the inventive technological well fluid allows you to:

- multiple (in comparison with the prototype and other known solutions) to increase the recovery coefficient of oil permeability of oil-saturated core,

- gain high density - not less than 1400 kg / m ³ ,

- to maintain the sedimentation stability of solid shunt particles at temperatures up to 125 ° C and to control the absorption in thermobaric conditions of formations with reservoir temperature up to 125 ° C.

The results of an experimental verification of the properties of a technological well fluid are described below.

Filtration experiments to determine the values of the coefficient of recovery of phase permeability for oil, conducted on oil-saturated cores with different permeabilities of the Vankor oil field, are summarized in table 1. As you can see, the highest values of the coefficient of recovery of phase permeability for oil on oil-saturated cores of Yakovlevskaya (Yak 3-7) and Nizhne-Kheta suite (Hx 3-4) - 41% and 45%, respectively - showed the claimed technological well fluid prepared on a saturated solution of sodium chloride (comp Av A, table 1).

The density of the borehole fluid can be adjusted by adding a solid phase - solid sodium chloride to a thickened saturated solution of sodium chloride with a density of 1190 kg / m ³ . Moreover, depending on the required density, the flow rate of solid sodium chloride (solid phase) and the flow rate of sodium chloride solution are selected in accordance with the table values in table 2.

table 2 Solid sodium chloride flow rate and final wellbore density Fluid density kg / m ³ 1190 1200 1250 1300 1350 1400 Solution flow rate dm ³ / m ³ 1000 979.6 929.2 878.3 827.9 776.8 Solid phase flow rate kg / m ³ 0 44.1 153.3 263.5 372.6 483.2

The optimum ratio of the mass flow rates of xanthan and polyanionic cellulose was established based on the ability of solutions with different polymer contents to retain sodium chloride crystals (solid phase) at elevated temperatures and to provide sedimentation stability of the process fluid at high formation temperatures.

It should be noted that suspensions of shunt particles are used to create a filter cake and temporarily reduce the permeability of absorption zones. Therefore, the stability of suspensions in a technological well fluid, which provides control of absorption at normal and elevated temperatures, is one of the necessary conditions for its effectiveness and low damaging ability of the bottomhole zone of the well.

Figure 1 shows the sedimentation rate of solid sodium chloride in polymer solutions at 90 ° C. The best properties for creating a stable technological well fluid are provided by a combination of polymers of xanthan (KS) and polyanionic cellulose (PAC) with a mass flow rate of 7.5 kg / m ³ and 2.5 kg / m ^3, respectively. Moreover, with an equal total flow rate of the mixture of two polymers (10 kg / m ³ ), the best sedimentation stability of solid sodium chloride is provided by a mixture of polymers in a mass ratio of KS: PAC equal to 3: 1 (7.5 kg / m ³ : 2.5 kg / m ^3, respectively).

The minimum required dosage of polymers (xanthan and polyanionic cellulose) for thickening the solution is determined from the condition of sedimentation stability of the solid phase - solid sodium chloride. The sedimentation stability of a wellbore fluid with solid sodium chloride was estimated by the decrease in fluid density over time due to sedimentation of solid particles of sodium chloride. The well fluid was studied, prepared from a saturated solution of sodium chloride with a density of 1190 kg / m ³ , thickened with a mixture of polysaccharides of xanthan and polyanionic cellulose (in a 3: 1 ratio) with various flows indicated in Table 3. Next, solid sodium chloride was added in an amount of 350 kg / m ³ . The density of the obtained well fluid was 1342 kg / m ³ .

Table 3 Dosage of polymers in a saturated solution of sodium chloride and sedimentation stability of the solid phase Test Consumption of xanthan and polyanionic cellulose, kg / m ³ 1.875: 0.625 3.75: 1.25 5.25: 1.75 7.5: 2.5 15: 5 Sedimentation stability of the solid phase not stable not stable not stable is stable is stable The viscosity of the solution, MPa * sec (100 sec ^-1 , + 25 ° C) 11.2 23.7 48,2 110 1080

Thus, it was found that to ensure sedimentation stability of a borehole fluid with a solid phase, the total dosage of polymers of xanthan and polyanionic cellulose should be at least 10 kg / m ³ . Increasing the total polymer dosage above 20 kg / m ^{3 is} impractical due to the excessively high viscosity (above 1000 MPa * s) and the impossibility of pumping such a liquid through the pipes of the injection line and downhole valves.

Figure 2 shows the results of measurements of the time of expiration of 200 cm ³ well fluid through the funnel VBR-2 with different total polymer content. It was found that when the polymer content is above 20 kg / m ^{3, the} fluid loses fluidity (the ability to spontaneously flow) due to excess viscosity.

Thus, the total content of polymers (xanthan and polyanionic cellulose) is advisable to limit the range from 10 kg / m ³ to 20 kg / m ³ .

To assess the thermal stability limit, a well fluid prepared from a saturated solution of sodium chloride with a density of 1190 kg / m ³ , thickened with polymers of xanthan and polyanionic cellulose with a dosage of 9 kg / m ³ and 3 kg / m ^3, respectively, containing 350 kg / m ^{3 of} solid chloride sodium (halite) was placed in a stainless steel piston column. To ensure the safety of the experiment and monitoring the internal pressure, an external pressure gauge was connected to the column. A column with a blocking composition was placed in an oven and maintained at temperatures of 100, 120, 125, 130, and 140 ° C. The pressure in the column due to thermal expansion of the composition reached 18 MPa (180 atm). With an increase in pressure above 18 MPa, to eliminate column rupture, part of the solution volume was discharged using an overflow valve. After temperature control at a given temperature for 5 hours, the column was disassembled, and the blocking composition was studied to preserve the solid phase in the volume of the solution. The influence of temperature on sedimentation stability and solid phase conservation was assessed visually by the presence of precipitated solid phase sediment in the piston column cavity and by the results of measuring rheological properties.

It was visually established that a well fluid based on a thickened solution of sodium chloride and containing sodium chloride as a solid phase is sedimentation stable at temperatures up to 130 ° C inclusive. With increasing temperature to 140 ° C, a solid phase precipitation was observed in the piston column cavity (suspension failure).

Figure 3 shows the rheological properties of the inventive borehole fluid after thermal exposure. Figure 3 shows that the effective viscosity at 103 sec ^-1 and the initial shear gradient indicate that the phenomenon of thermal degradation begins at temperatures above 125 ° C.

Thus, the inventive technological well fluid prepared from a saturated solution of sodium chloride with a density of 1190 kg / m ³ , thickened with xanthan gum (with a flow rate of 7.5 kg / m ³ to 15 kg / m ³ ) and polyanionic cellulose (with a flow rate of 2, 5 kg / m ³ to 5 kg / m ³ ) and containing solid sodium chloride as shunting particles, has sedimentation and thermal stability to a temperature of at least 125 ° C.

The ability of the technological well fluid to control the absorption is confirmed during pilot tests at the Prirazlomnoye and North Salym fields, the results of which are summarized in table 4.

Technological well fluid for experimental field tests had the composition:

xanthan - 9 kg / m ³

polyanionic cellulose - 3 kg / m ³

solid sodium chloride - 373 kg / m ³

saturated sodium chloride solution - the rest.

Table 4 Test results of a technological well fluid during well repair Well Field An object Temperature ° C The density of the liquid, kg / m ³ Absorption, m ³ K _prod , m ³ / (day × atm) To _prod after, m ³ / (day × atm) ΔK _prod ,% one North Salym 1350 0 0.82 1.18 44 2 PRZ BS _4-5 92-96 1350 0 0.14 0.15 7 3 PRZ BS _4-5 92-96 1350 0 0.32 0.30 19 four PRZ BS _4-5 92-96 1350 0 0.15 0.17 13 5 PRZ BS _4-5 92-96 1350 0 0.05 0.05 0 6 PRZ BS _4-5 92-96 1350 0 0,07 0,07 0 7 PRZ BS _4-5 92-96 1350 0 0.22 0.29 32 To _prod - well productivity coefficient ΔK _prod - change in well productivity coefficient PRZ - Prirazlomnoye field

During the underground repairs of seven wells, the absorption of killing fluid was not recorded.

Thus, it was possible to create a technological well fluid - a solution of a mixture of xanthan and polyanionic cellulose in a sodium chloride solution containing solid sodium chloride as shunt particles, which meets all the requirements for controlling absorption in high-temperature (up to 125 ° C) wells with high reservoir pressure (density solutions to 1.4 g / cm ^3, i.e., for the formation pressure to 1.4 times the hydrostatic) and provides the highest permeability recovery rate of oil in neftenas schennnyh cores.

The inventive technological well fluid based on a solution of sodium chloride, thickened with xanthan gum and polyanionic cellulose, with sodium chloride as a solid phase has a number of necessary properties, namely:

- high density up to 1400 kg / m ³ ;

- high sedimentation and thermal stability at elevated (up to 125 ° C) temperature;

- the ability to control absorption due to the presence of a solid phase;

- high recovery coefficient of oil permeability of oil-saturated cores,

which each of these components individually does not possess.

There is no information in the special literature regarding the creation of a technological well fluid to reduce the absorption of drilling fluids, well flushing fluids, killing solutions used in underground well repair, from water-soluble polymers including xanthan and polyanionic cellulose, which have a standard set of technological characteristics (viscosity, ability stabilization of the suspension of shunt particles at high temperatures, thermal stability up to 125 ° C) required to control absorption I am in thermobaric conditions of the formation and at the same time possessing pronounced "sparing" properties in relation to the filtration-capacitive properties of the oil, oil and gas or gas-bearing formation. Therefore, the claimed solution, according to the authors, meets the criterion of "inventive step".

Claims (1)

Technological well fluid with controlled absorption in thermobaric conditions of the formation, containing water-salt solution, xanthan gum and polyanionic cellulose, characterized in that it contains saturated sodium chloride solution and additionally solid sodium chloride as a water-salt solution in the following ratio of components of 1 m ³ technological well fluid, kg:
xanthan 7.5-15 polyanionic cellulose 2,5-5 solid sodium chloride up to 483 saturated sodium chloride solution rest

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