Method of heavy oil extraction from underground field

FIELD: oil and gas industry.

SUBSTANCE: invention relates to the heavy oil extraction from underground field. Method of the heavy oil extraction from underground field includes: nanoemulsion (oil-in-water) injection to one or more injection wells, extraction of the specified heavy oil from one or more operation wells, where the specified nanoemulsion is produced using the method including: production of the uniform mixture (1) water/oil product with interfacial tension 1 mN/m maximum, containing water in quantity from 65% to 99.9% by weight, with a view to total mixture weight (1), and at least two surface-active substance (SAS) having different hydrophilic-lipophilic balance (HLB), selected from not-ionic, anionic, polymer SAS, preferably not0ionic; these SAS are in such quantity that to make the mixture (1) uniform mixture (1) dilution by the dispersion medium containing water with added at least one SAS selected from the specified SASs; this dispersion medium and SAS quantities are such that nanoemulsion is produced (oil-in-water) having HLB exceeding HLB of the mixture (1). Invention is developed in subclaims.

EFFECT: increased extraction efficiency.

34 cl, 1 dwg, 2 ex

 

The present invention relates to a method of extracting heavy oil from underground deposits.

More specifically, the present invention relates to a method of extracting heavy oil from underground deposits using a nano-emulsion type "oil-in-water".

This method is particularly advantageous for increasing the extraction of heavy oil from underground deposits within the technologies of development of deposits of tertiary ways, commonly known as "EOR" (Enhanced Oil Recovery methods enhanced oil recovery).

It is known that the extraction of oil from underground deposits is usually effected by means of oil wells. It is also known that such extraction is usually carried out in three separate phases during which use different extraction technologies, with the objective of maintaining crude oil production at highest levels. These extraction technology known as field development primary, secondary and tertiary methods.

Underground deposits can have the natural energy provided, for example, water and/or gases that may be present in these underground deposits, and this energy can promote the movement of oil towards the surface of the Deposit. As water and gas may, in fact, the pressure is able to move in the presence of these underground deposits of oil towards the surface of one or more production wells (field development is the primary method). However, this natural energy wanes over time, resulting in the development of a primary method usually allows you to extract a small proportion of oil is found in underground deposits (for example, about 15-20% of the total amount of oil present in the original these underground deposits).

The development of the secondary method is usually carried out by water injection (waterflooding) or gas (gas injection), which is pumped into these underground deposits for the purpose of maintaining them in pressure that allows you to move the oil towards the surface. Through the specified development secondary way one can get about 15-30% of the total amount of oil originally present in these underground deposits, relative to the specified development the primary method.

The amount of oil remaining in these underground deposits can be removed by developing the tertiary method, generally known as methods of enhanced oil recovery. Specified the development of a tertiary method can be carried out, for example, by injecting into these underground deposits of fluids that improve the mobility of the residual oil towards the surface of the Deposit. These fluids may be selected from, for example, gases that are miscible or not cm�simoudis with the specified oil (usually carbon dioxide); steam, air or oxygen, polymer solutions ("injected into the reservoir of polymer solutions"), mixtures of surfactants and polymers ("injected into the reservoir of surfactants and polymers), mixtures of bases, surfactants and polymers ("injected into the reservoir alkalis, surfactants and polymers", or "ASP" (alkaline-surfactant-polymer flooding)), mixtures of microorganisms.

It is known that to determine the amount of oil recovered by tertiary development method, are important many factors, such as, for example, interfacial tension between the injected gas and/or liquid and residual oil; the relative mobility of the injected gas and/or liquid; the characteristics of the wettability of the surfaces of the rocks present in these underground deposits.

Numerous studies have shown that the use of surfactants can change as the interfacial tension between the injected water and residual oil, and the properties in terms of wettability of the surfaces of the rocks. In many cases, the addition of polymer in conjunction with surface-active substance, directly or after adding a surfactant, can reduce the mobility of injected water and residual oil, allowing, thus, easier to move oil in n�the Board surface underground deposits and to increase the recovery of residual oil.

American patent US 4743385, for example, describes a method of increasing oil recovery from underground deposits, which includes the injection in these rocks a pair containing an effective amount of a mixture comprising an anionic surfactant selected from C14-20sulfonated alkylthiol, C14-20sulfonated benzene or C14-20the sulfonated alkyl benzene; and hydrotropes substance selected from the group consisting of alkali metal salts of sulfonated xylene, alkali metal salts of sulfonated toluene, alkali metal salts of sulfonated cumene, alkali metal salts of sulfonated benzene, alkali metal salts of isethionate, alkali metal salts of sulfonated Bhutan and alkali metal salts of sulfonated hexane.

American patent US 6022834 describes a method of extracting residual oil from underground deposits, in which the specified residual oil contains naturally present components of organic acids and which includes the injection of a composition of surfactants, including a "brine", alkalis and possibly polymers; wherein said composition has a concentration of higher than or equal to its critical micellar concentration, and wherein said composition is capable of creating very low�e interfacial tension between the residual oil and said composition, allowing the alkali to penetrate through the pores of the rocks that make up the field, and thus to bring them into contact and to carry out the reaction with these compounds, organic acids, naturally present in the field, forming in situ secondary system surface-active substances, including salt with the properties of surfactants, which are combined with said composition of surface-active substances, allowing, thus, to emulsify the trapped residual oil, move it and bring to the surface.

American patent US 7055602 describes a method of processing containing a hydrocarbon formation, comprising: (a) ensuring access of the composition to at least part of the specified containing the hydrocarbon formation; wherein said composition comprises a branched aliphatic anionic surfactant and a branched aliphatic nonionic surfactant; wherein the group of the branched aliphatic anionic surfactant comprises an average number of branches for each of the aliphatic group ranging from about 0.7 to 2.5; and (b) abandonment of specified composition (in contact with the formation), interacting with hydrocarbons, within the specified containing hydrocarbons formation.

Americas�coast US patent application 2008/0115945 describes a method of enhanced oil recovery or extraction of other hydrocarbons, present in underground deposits, using an enzymatic fluid, comprising adding the enzyme fluid to said formation; injecting water, steam or both; the abandonment of the specified enzymatic fluid, water and/or steam for the period of time required for impregnation of the indicated formation; extracting the specified oil or other hydrocarbon by pumping or by other means.

American patent application US 2008/0261835 describes a method of extracting heavy oil, comprising: (a) the injection of a water displacing fluid containing one or more surfactants, one or more injection wells for the formation of heavy oil external pseudomallei having a low viscosity; (b) the extraction of heavy oil from one or more production wells.

American patent application US 2008/0302531 describes a method of extracting oil from underground deposits, in which one or more injection wells is injected displacing fluid medium containing: (a) one or more arylalkylamines; (b) one or more jointly present surfactants; (C) one or more solvents; (a) possibly, one or more bases; and (e) possibly one or more regulatory viscosity Angora�RH; and oil is recovered from one or more production wells.

However, the above methods can have various shortcomings.

It is possible to form the emulsion, for example, between the injected fluid and heavy oil found in underground deposits. Educated emulsions, in particular aqueous phase and heavy oil, are extremely difficult to destroy after extraction of the emulsion to the surface, making difficult the extraction of the specified heavy oil. In many cases, for breaking such emulsions are actually needed, heat treatment and/or agents demulsifiers. In addition, these emulsions can increase the viscosity of injected fluid; this reduces its ability to pump and can lead to the blocking of the emulsion in the underground mine, which makes it difficult, if not impossible, to extract oil. Moreover, in the case of high salinity and/or hardness of the water present in the underground mine, extraction of oil using fluids containing surfactants and/or polymers, may be severely limited due to the instability of these surfactants and/or polymers.

Thus, there is the problem of finding ways to increase the recovery of heavy oil from an underground Deposit, which is able ol�to overcome the above mentioned challenges.

Now, the applicant discovered that it is possible to successfully carry out the extraction of heavy oil from underground deposits with the use of nano-emulsion of the type oil-in-water.

Using the mentioned nano-emulsion of the type oil-in-water were obtained numerous advantages. For example, application of the said nano-emulsion of the type oil-in-water helps to reduce the interfacial tension between water present in said nano-emulsion of the type oil-in-water, and oil, are specified in an underground mine, which promotes Miscibility between the oil present in the specified underground mine and the water present in said nano-emulsion of the type oil-in-water.

In addition, the application of this nano-emulsion type oil-in-water allows you to change the wettability of the surface of the rocks present in the specified underground mine, thus to reduce the capillary forces that hold the oil in the microscopic pores of the rocks present in the specified underground Deposit.

In addition, the application of this nano-emulsion type oil-in-water allows to reduce the mobility of the water present in said nano-emulsion of the type oil-in-water, and oil that is present in the specified underground mine due to the lower viscosity of the oil itself, which allows you to�t easier to move the oil to the surface of the specified underground deposits and increase the yield specified in the extraction of oil.

The capacity of that nano-emulsion of the type oil-in-water to reduce the viscosity of oil present in the specified underground mine, also reduces the energy required to pump the specified nano-emulsion of the type oil-in-water underground at a specified field, and to produce work in the presence of rocks with low permeability.

In addition, by using said nano-emulsion can also work in the presence of water having high salinity and/or hardness.

Thus, the purpose of the present invention relates to a method of extracting heavy oil from underground deposits, which includes:

- the injection of a nano-emulsion of the type oil-in-water in one or more injection wells; extraction of specified heavy oil from one or more production wells, where said nano-emulsion of the type oil-in-water can be obtained in accordance with the method, including:

- preparation of a homogeneous mixture (1) water/oil product, wherein the interfacial tension < 1 mn/m, preferably in the range from 10-2mn/m to 10-4mn/m, comprising water in an amount of from 65 wt%. to 99.9 wt.%, preferably from 70 wt%. to 90 wt.%, in the calculation of the total weight of said mixture (1), wherein at least two surfactants selected from neyo�tion, anionic, polymeric surfactants, preferably nonionic, have a number of different HLB (hydrophilic-lipophilic balance, HLB), and these surfactants are present in such quantities to make this mixture (1) homogeneous;

- dilution of the mixture (1) dispersion medium consisting of water with addition of at least one surfactant selected from nonionic, anionic, polymeric surfactants, preferably nonionic; and the number of the specified dispersion medium and the surfactant is such that you get a nanoemulsion of the type oil-in-water having an HLB number higher than the number specified HLB of the mixture (1).

These one or more injection wells and the one or more production wells may be different. In the alternative, these one or more injection wells may be the same wells as the specified one or more production wells.

For purposes of this description and the subsequent claims, the term "heavy oil" refers to oil that has a high density, preferably below 25° API (American Petroleum Institute, the American petroleum Institute), more preferably in the range from 10° API and 20° API, with tightly specified�th determined in accordance with ASTM D287-92 (2006).

In accordance with a preferred embodiment of this invention indicated heavy oil has a dynamic viscosity, measured at reservoir temperature, according to ASTM D7042-04, not lower than 20 GPa, preferably in the range of 22 GPa to 150 GPa.

For purposes of this description and the subsequent claims, the numerical ranges always include the endpoints, unless otherwise indicated.

According to a preferred embodiment of this invention the said nanoemulsion type oil-in-water may include a dispersed phase (i.e. oil) and dispersion medium (i.e., water with surfactants).

According to a preferred embodiment of this invention in said nano-emulsion of the type oil-in-water dispersed phase (i.e. oil) can be distributed in the dispersion medium (i.e. water and surfactants) in the form of droplets with a diameter in the range from 10 nm to 500 nm, preferably in the range from 15 nm to 200 nm.

Particularly suitable for the purposes of the above method, nano-emulsion of the type oil-in-water can be obtained as described in international patent application WO 2007/112967, the content of which is incorporated into this description by reference. The specified method allows to obtain monodisperse nano-emulsion of the type oil-in-water with high�th stability and having a dispersed phase (i.e. oil), distributed in the dispersion medium (i.e. water and surfactants) in the form of droplets having a high specific surface area (surface/volume) (i.e., a specific surface area of not lower than 6000 m2/l).

According to a preferred embodiment of this invention, these nano-emulsion of the type oil-in-water can have a HLB number equal to 9 or higher, preferably in the range from 10 to 16.

According to a preferred embodiment of this invention in these nano-emulsions of the type oil-in-water dispersed phase (i.e. oil) can be distributed in the dispersion medium (i.e. water) in the form of droplets having a specific surface area (surface/volume) in the range of 6,000 m2/l up to 300,000 m2/l, preferably in the range from 15,000 m2/l to 200,000 m2/L.

In accordance with a preferred embodiment of this invention, these nano-emulsion of the type oil-in-water may include the number of surfactants in the range from 0.1 wt%. up to 20 wt.%, preferably in the range of from 0.25 wt%. to 12 wt.%, and the amount of oil in the range of 0.5 wt%. up to 10% wt., preferably in the range of 1 wt%. to 8 wt.%, in the calculation of the total mass of the specified nano-emulsion of the type oil-in-water.

According to a preferred embodiment of this invention, these surface active agent can choose from nonionic surfactants, such as, for example, alkylpolyglucoside; esters of sorbitol and fatty acids; polymeric surfactants such as, for example, grafted acrylic copolymers having a main chain of the poly (methyl methacrylate-methacrylic acid and side chains of polyethylene glycol; or mixtures thereof.

According to a preferred embodiment of this invention the oil in said nano-emulsion can choose from aromatic hydrocarbons, such as, for example, xylene, mixtures of xylene isomers, toluene, benzene, or mixtures thereof; linear, branched or cyclic hydrocarbons, such as, for example, hexane, heptane, decane, cyclohexane, or mixtures thereof; complex mixtures of hydrocarbons, such as, for example, gas oil, kerosene, control, white spirit or mixtures thereof; or mixtures of these substances.

With regard to water used for this nano-emulsion, it can be any. For economic reasons it is preferable that the specified water was present near the place of preparation of these nano-emulsions of the type oil-in-water.

According to a preferred embodiment of this invention for the preparation of these nano-emulsions can be applied demineralized water, salt water, water with additives, or mixtures thereof. More specifically, it is possible to apply water that is present in the specified underground Deposit.

p> Oil, which is present in the specified underground mine may include other compounds such as, for example, compounds containing oxygen, such as naphthenic acids; compounds containing Halogens; compounds containing metallic elements; compounds containing nitrogen; compounds containing sulfur; or mixtures thereof.

To omelet naphthenic acids normally present in said solid matrix, the nano-emulsion of the type oil-in-water can be added at least one base.

According to an additional embodiment of the present invention to a specific nano-emulsion of the type oil-in-water can be added at least one base, in amounts of from 0.1% wt. up to 10% wt., preferably from 0.2 wt%. up to 5% wt., in the calculation of the total mass of the specified nano-emulsion of the type oil-in-water. Preferably the specified base can be chosen from sodium hydroxide, potassium hydroxide, sodium carbonate, potassium carbonate or mixtures thereof.

To remove the specified heavy oil from one or more production wells indicated a nanoemulsion of the type oil-in-water pumped into the specified one or more injection wells for a certain period of time at a certain temperature, which depends on the type of underground deposits (for example, on the type of rocks present in at�the earth's field), as well as the size of wells and distance from a specified set of one or more injection wells and the specified one or more production wells.

According to a preferred embodiment of this invention the specified nanoemulsion type oil-in-water can be pumped into one or more injection wells for a period of time in the range from 80 days to 200 days, preferably in the range from 90 days to 180 days.

According to a preferred embodiment of this invention the specified nanoemulsion type oil-in-water can be pumped into one or more injection wells at a temperature in the range from 10°C to 100°C, preferably in the range from 20°C to 90°C.

To remove greater amounts of heavy oil, preferably it is possible to carry out secondary recovery, preferably through the injection of water (water flooding).

According to a preferred embodiment of this invention the method may include the injection of water (water flooding) to the one or more injection wells prior to injection of the specified nano-emulsion of the type oil-in-water.

As for water, which can be used in the specified injection (water flooding), it may be of any origin. For economic reasons it is opportune that this water could be taken condition close to the� from the place of injection.

According to a preferred embodiment of the present invention can be applied demineralized water, salt water, water with additives, or mixtures thereof. More specifically, it is possible to use water that is present in the specified underground Deposit.

In order to extract a greater amount of heavy oil, it may be preferable to pump water and/or at least one polymer in the specified one or more injection wells after the injection of the specified nano-emulsion of the type oil-in-water.

According to a preferred embodiment of this invention the method may include, after the injection of the specified nano-emulsion of the type oil-in-water, injection water and/or at least one polymer in a specified one or more injection wells.

As for water, which can be used for the specified injection, it may be of any origin. For economic reasons it is advisable that this water could be taken near the injection wells.

According to a preferred embodiment of the present invention can be applied demineralized water, salt water, water with additives, or mixtures thereof. More specifically, you can use the water that is present in the specified underground Deposit.

According to a preferred embodiment of this invention is indicated�first polymer can be selected, for example, polyacrylamide, sulfonated copolymers of acrylamide, xanthan resin or mixtures thereof.

The specified extraction of heavy oil of the one or more production wells (production wells) are in the process of uploading the specified nano-emulsion of the type oil-in-water specified in one or more injection wells (injection wells).

The heavy oil extracted with the help of this method, which is the object of the present invention, can be directed to further processing, such as, for example, processing by hydrogenation or hydrocracking to obtain a hydrocarbon fraction having great commercial value.

Further, the present invention will be illustrated by means of an illustrative example of an embodiment, with reference to the following Fig.2.

Fig.1 schematically depicts an embodiment of the method, which is the object of the present invention. Underground mine (1) with particles (2) heavy oil treated according to the method of this invention. To this end a nanoemulsion (4) of the type oil-in-water is pumped into an injection well (3).

The specified nanoemulsion (4) is pumped into an injection well (3) for a period of time, preferably in the range from 80 days to 180 days, with the temperature preferably being in the range of�from 10°C to 100°C.

Specified heavy oil (6) is recovered from production wells (5) in the process of uploading the specified nano-emulsion (4) in a specified injection well (3). Specified heavy oil (6) can be sent to the subsequent processing (not shown in Fig.1).

Below are some illustrative and non-limiting examples for a better understanding of this invention and as an example of its implementation.

Example 1

(1) preparation of the precursor nano-emulsion of the type oil-in-water equal to 0,121 g of Atlox 4913 (grafted copolymer polymethyl methacrylate-polyethylene glycol from Uniqema), 0,769 g of Span 80 (monooleate sorbitol from Fluka), 3,620 g Glucopone 600CS UP (alkylpolyglucoside from Fluka, 50% aqueous solution) and 6,150 g of xylene were added to 50 ml of a glass whose contents were stirred magnetically, and the whole mixture was kept under stirring until complete dissolution. After complete dissolution, was added 4,340 g of deionized water and the mixture was held at mild stirring for two hours; received 15 g of the precursor having an HLB number equal 12,80.

The specified predecessor before using left to stabilize for 24 hours at room temperature (25°C).

(2) preparation of nano-emulsion of the type oil-in-water 0,325 g Glucopone 215 CS UP (alkylpolyglucoside from Fluka, 60% aqueous solution) and 2,236 g of deionized water was added to 20 ml of STE�lannie tube and the whole mixture was kept under stirring until complete dissolution. After complete dissolution of the added 2,439 g of the precursor obtained as described above, and the whole mixture was kept under stirring for two hours to obtain nano-emulsion, which has a transparent/translucent appearance, the HLB number 13,80 and the content of xylene equal to 20% of the mass. in the calculation of the total weight of the nano-emulsion.

The specified nanoemulsion was diluted 96,25 ml of deionized water to obtain a nanoemulsion having a total content of surfactants, is equal to 1.25% of the mass. in the calculation of the total weight of the nano-emulsion, and the content of xylene, equal to 2.5% of the mass. in the calculation of the total weight of the nano-emulsion.

The nanoemulsion obtained as described above has the drops of the dispersed phase (xylene) with dimensions in the range from 40 to 60 nm, a polydispersity index below 0.2, and it is stable for more than 6 months.

Example 2

Steel column (1.4 cm × 10 cm) filled to 26.6 g of sand that came from the oil fields Aghar (Egypt), and then washed with brine to obtain a Packed column ("sand gasket"). After washing indicated a Packed column ("sand fill) brine were conducted subsequent measurement: the permeability of the brine, which has been shown to be equal to 0.09 D (Darcy) and porosity, which, as shown, equal to 42% (which corresponds to the pore volume equal to 6.5 ml).

Obtained as described above, a Packed column ("sand gasket") then saturated 5,0 ml of oil imported from the Aghar field (Egypt), a dynamic viscosity, measured at reservoir temperature, i.e., 77°C, according to ASTM D7042-04, is 64 GPa; which corresponded to the initial saturation of oil for 77.3% of the pore volume.

After holding a Packed column ("sand fill), rich in oil, at 77°C for seven days, the column was washed with triple pore volume of brine (water flooding); it was extracted with 3.5 ml of oil (equivalent to 70.3% of the amount of oil that is present in the saturated column). The brine flow was 0.1 ml/min.

After washing with brine, the amount of residual oil in a Packed column ("sand pack") was equal to 29,7% of the pore volume.

Then Packed column ("sand gasket") were washed with 1 (pore volume) nano-emulsion obtained according to Example 1, and then 4 pore volumes of brine, it was extracted with 1.1 ml of oil (equivalent to 73.3% of the oil present in Packed column ("sand gasket) after washing with brine). The consumption of nano-emulsion was 0.1 ml/min.

To remove the residual oil and to get the opportunity to cut the material balance, a Packed column ("sand packing") was washed with 10 pore volumes of tetrahydrofuran, and was extracted with 0.4 ml of oil (which is 100% about� oil present in a Packed column ("sand pack") after washing the nanoemulsion). The flow rate of tetrahydrofuran was 0.2 ml/min.

The quantity of oil extracted after washing was determined by extraction of the fractions of oil/water with tetrahydrofuran, with subsequent spectrophotometric detection at 446 nm.

1. A method of extracting heavy oil from underground deposits, including:
- the injection of a nano-emulsion of the type oil-in-water in one or more injection wells;
- extracts of the specified heavy oil from one or more production wells,
in which the specified nanoemulsion type oil-in-water gain in accordance with a method comprising:
- obtaining a homogeneous mixture (1) water/oil product, wherein surface tension < 1 mn/m, comprising water in an amount of from 65 wt%. to 99.9 wt.%, in the calculation of the total weight of said mixture (1), and at least two surfactants with different values of the hydrophilic-lipophilic balance, HLB, selected from non-ionic, anionic, polymeric surfactants, preferably nonionic, and these surfactants are present in such quantities to make this mixture (1) homogeneous;
- dilution of the mixture (1) a dispersion comprising harassing, to which is added at least one surfactant selected from nonionic, anionic, polymeric surfactants, wherein the quantity of the specified dispersion medium and the specified surface-active substances are those that receive a nanoemulsion of the type oil-in-water having a HLB value higher than the specified HLB of the mixture (1).

2. A method of extracting heavy oil from underground deposits according to claim 1, wherein the specified one or more injection wells and the one or more production wells represent different wells.

3. A method of extracting heavy oil from underground deposits according to claim 1, wherein the specified one or more injection wells and the one or more production wells are the same wells.

4. A method of extracting heavy oil from underground deposits according to claim 1, wherein the specified heavy oil has a dynamic viscosity, measured at reservoir temperature according to ASTM D7042-04, not lower than 20 GPa.

5. A method of extracting heavy oil from underground deposits according to claim 4, in which the specified heavy oil has a dynamic viscosity, measured at reservoir temperature according to ASTM D7042-04, range from 22 GPa to 150 GPa.

6. A method of extracting heavy n�PTI from underground deposits according to claim 1, in which in said nano-emulsion of the type oil-in-water dispersed phase (i.e. oil) distributed in the dispersion medium (i.e. water and surfactants) in the form of droplets with a diameter in the range from 10 nm to 500 nm.

7. A method of extracting heavy oil from underground deposits according to claim 6, wherein in said nano-emulsion of the type oil-in-water dispersed phase (i.e. oil) distributed in the dispersion medium (i.e. water and surfactants) in the form of droplets with a diameter in the range from 15 nm to 200 nm.

8. A method of extracting heavy oil from underground deposits according to claim 1, wherein the said nanoemulsion type oil-in-water has a HLB value of 9 or higher.

9. A method of extracting heavy oil from underground deposits according to claim 8, in which the said nanoemulsion type oil-in-water has a HLB value in the range from 10 to 16.

10. A method of extracting heavy oil from underground deposits according to claim 1, wherein in said nano-emulsion of the type oil-in-water dispersed phase (i.e. oil) distributed in the dispersion medium (i.e. water) in the form of droplets having a specific surface area (surface/volume) in the range of 6,000 m2/l up to 300,000 m2/L.

11. A method of extracting heavy oil from underground deposits according to claim 10, wherein in said nano-emulsion type of oil�-in-water dispersed phase (i.e. oil) distributed in the dispersion medium (i.e. water) in the form of drops, having a specific surface area (surface/volume) in the range of 15000 m2/l to 200,000 m2/L.

12. A method of extracting heavy oil from underground deposits according to claim 1, wherein the said nanoemulsion type oil-in-water includes the amount of surfactants in the range from 0.1 wt%. up to 20 wt.%, in the calculation of the total mass of the specified nano-emulsion of the type oil-in-water.

13. A method of extracting heavy oil from underground deposits according to claim 12 in which the said nanoemulsion type oil-in-water includes the amount of surfactants in the range of from 0.25 wt%. to 12 wt.%, in the calculation of the total mass of the specified nano-emulsion of the type oil-in-water.

14. A method of extracting heavy oil from underground deposits according to claim 1, wherein the said nanoemulsion type oil-in-water includes quantities of oil are in the range of 0.5 wt%. up to 10% wt., in the calculation of the total mass of the specified nano-emulsion of the type oil-in-water.

15. A method of extracting heavy oil from underground deposits according to claim 14 in which the said nanoemulsion type oil-in-water includes quantities of oil are in the range of 1 wt%. to 8 wt.%, in the calculation of the total mass of the specified nano-emulsion of the type oil-in-water.

16. A method of extracting heavy oil from underground deposits according to any one of claims.6-15, in which the specified surface-active ve�society chosen from nonionic surfactants, such as alkylpolyglucoside; esters of sorbitol and fatty acids; polymeric surfactants such as grafted acrylic copolymers having a main chain of the poly (methyl methacrylate-methacrylic acid and side chains of polyethylene glycol; or mixtures thereof.

17. A method of extracting heavy oil from underground deposits according to claim 1, in which the oil in the said nano-emulsion is selected from aromatic hydrocarbons, for example xylene, mixtures of xylene isomers, toluene, benzene or mixtures thereof; linear, branched or cyclic hydrocarbons, for example hexane, heptane, decane, dodecane, cyclohexane or mixtures thereof; complex mixtures of hydrocarbons such as gas oil, kerosene, control, mineral spirits, or mixtures thereof; or mixtures of these substances.

18. A method of extracting heavy oil from underground deposits according to claim 1, wherein the water in the said nano-emulsion is selected from demineralized water, salt water, water with additives, or mixtures thereof.

19. A method of extracting heavy oil from underground deposits according to claim 1, wherein the water in the said nano-emulsion is a water that is present in the specified underground Deposit.

20. A method of extracting heavy oil from underground deposits according to claim 1, wherein to said nano-emulsion of the type oil-in-water added according to møn�Shea least one base in amounts in the range from 0.1 wt%. up to 10% wt., in the calculation of the total mass of the specified nano-emulsion of the type oil-in-water.

21. A method of extracting heavy oil from underground deposits according to claim 20, in which the specified nano-emulsion of the type oil-in-water add at least one base in amounts in the range from 0.2 wt%. up to 5% wt., in the calculation of the total mass of the specified nano-emulsion of the type oil-in-water.

22. A method of extracting heavy oil from underground deposits according to claim 20 or 21, wherein said base is selected from sodium hydroxide, potassium hydroxide, sodium carbonate, potassium carbonate or mixtures thereof.

23. A method of extracting heavy oil from underground deposits according to claim 1, wherein the specified nanoemulsion type oil-in-water is pumped into one or more injection wells for a period in the range from 80 days to 200 days.

24. A method of extracting heavy oil from underground deposits according to claim 23, in which the specified nanoemulsion type oil-in-water is pumped into one or more injection wells for a period ranging from 90 days to 180 days.

25. A method of extracting heavy oil from underground deposits according to claim 1, wherein the specified nanoemulsion type oil-in-water is pumped into one or more injection wells at a temperature in the range from 10°C to 100°C.

26. A method of extracting heavy oil from underground deposits according to claim 25, in which�azanuy a nanoemulsion of the type oil-in-water is pumped into one or more injection wells at a temperature in the range from 20°C to 90°C.

27. A method of extracting heavy oil from underground deposits according to claim 1, wherein said method includes, prior to injection of the specified nano-emulsion of the type oil-in-water, water injection (waterflooding) specified in one or more injection wells.

28. A method of extracting heavy oil from underground deposits according to claim 27, where the specified selected from water, demineralized water, salt water, water with additives, or mixtures thereof.

29. A method of extracting heavy oil from underground deposits according to claim 27, in which the specified water is water that is present in the specified underground Deposit.

30. A method of extracting heavy oil from underground deposits according to claim 1, which comprises, after placing the specified nano-emulsion of the type oil-in-water pumping in the specified one or more water injection wells and/or at least one polymer.

31. A method of extracting heavy oil from underground deposits according to claim 30, where the specified selected from water, demineralized water, salt water, water with additives, or mixtures thereof.

32. A method of extracting heavy oil from underground deposits according to claim 31, in which the specified water is water that is present in the specified underground Deposit.

33. A method of extracting heavy oil from underground deposits by any�the mu one of claims.30-32, wherein said polymer is selected from polyacrylamide, sulfonated copolymers of acrylamide, xanthan resin or mixtures thereof.

34. A method of extracting heavy oil from underground deposits according to claim 1, wherein the specified heavy oil is sent to the subsequent processing, for example for processing with the aim to improve quality through hydrogenation or hydrocracking.



 

Same patents:

FIELD: oil and gas industry.

SUBSTANCE: group of inventions is related to production of heavy hydrocarbons. In the in situ multistage solvent extraction method of heavy oil from oil pools at first liquids and gases are extracted from zones of contact with heavy oil in order to increase interfacial area of unextracted heavy oil subject to contact with solvent. Then solvent is injected in the form of steam to the above zones in order to increase pressure in the pool up to accumulation of sufficient quantity of solvent in the form of liquid to ensure contact with enlarged interfacial surface of heavy oil. Then the pool is isolated for the period sufficient to ensure diffusion of solvent to unextracted oil through the interfacial surface at ageing stage so that the mixture of solvent and oil with low viscosity is obtained. One or more parameters of the pool are measured to determine the degree of unextracted oil liquefaction in the pool by solvent. Oil extraction from the pool is commenced by gravity drainage when viscosity of oil becomes rather low to flow through the pool to the production well.

EFFECT: maximising liquefaction of heavy oil and maximising its extraction as a result.

19 cl, 11 dwg

FIELD: oil and gas industry.

SUBSTANCE: method involves displacement of the first fluid on a hydrocarbon basis, which is present at a non-cased interval of a well shaft, with the second fluid, contact of the second fluid to acid natural formation fluid so that the third fluid is formed, where the second fluid contains aqueous liquid dispersed as a disperse phase in oily liquid, and surface active substance (SAS) based on amine and chosen so that the above contact performs protonation of at least some part of SAS with formation of the third fluid included in an emulsion containing oily liquid reversely dispersed as a disperse phase in aqueous liquid, where at least 40 vol % of any solid substances that do not refer to a proppant and are present in the fluid are water-soluble at pH that is lower than or equal to 6.5, and SAS has the above said structure. An underground well treatment system. The fluid containing a reversible invert emulsion containing an aqueous liquid dispersed as a disperse phase in oily phase and the above SAS.

EFFECT: improving destruction efficiency of a filter cake.

20 cl, 6 dwg, 3 tbl, 2 ex

FIELD: oil and gas industry.

SUBSTANCE: under the method of development of oil deposits with nonuniform permeability comprising successive injection via the injection well of the water suspension containing polymer, mud powder and SAS solution, prior to the suspension injection in the deposit the initial intake of the injection well is determined under pressure in water line ands water mineralisation; in water with salinity level 0.15-40 g/l complex action SASs with pour point not exceeding minus 30°C and kinematical viscosity 35-50 sSt are used, i.e. water-alcohol solution of non-ionic SAS-monoalkyl esters of PEG at the following ratio wt %: specified SAS 0.001-1.0, specified water rest, suspension and SAS solution are injected in volume ratio (1-3):1 depending on initial intake of the injection well - at intake 200-400 m3/day - 1-2:1, 400-500 m3/day - 2-3:1, over 500 m3/d - 3:1, between suspension and SAS solution water with salinity level 0.15-40 g/l or water suspension of polyacrylimide with concentration 0.0001-0.1 wt % is injected. Under another option during this method in water with salinity level 40-300 g/l the complex SAS with pour point minus 40°C max is used, containing complex action SAS with pour point minus 30°C max. and kinematical viscosity 35-50 sSt - water-alcohol solution of non-ionic SAS - monoalkyl esters polyoxyethylene glycol 90 wt % and alkyldimethylbenzylammonium chloride 10 % at following ratio of components in wt %: specified SAS 0.001-1.0, specified water - rest, suspension and SA solution are injected to the deposit in volume ratio (1-3): 1 depending on initial intake of the injection well at water line pressure - at intake 200-400 m3/day - 1-2:1, 400-500 m3/day - 2-3:1, over 500 m3/day - 3:1, and between suspension and solution the water with salinity level 40-300 g/l or water suspension of polyacrylimide with concentration 0.0001 0.1 wt % are injected.

EFFECT: increased oil recovery of the deposit.

2 cl, 4 ex, 4 tbl

FIELD: oil and gas industry.

SUBSTANCE: under method of oil deposit development comprising determination of the injection well intake, oil recovery via the production wells, and injection via at least one injection well of the water dispersion of the water-soluble polymer and alkali metal hydroxide, this dispersion contains in wt %: water-soluble polymer 0.01-0.05, alkali 0.5-1.0, at definite intake values of the injection well the specified dispersion is injected until injection pressure increasing by 20-30%, its flushing in the deposit by the injected water in volume of tubing plus 1.0 m3, alkali composition in volume 10-30% of volume of injection of the specified dispersion is injected until specific intake decreasing by 10-20% and achievement of the injection pressure not exceeding the maximum permitted pressure on production string and production deposits, the specified compositions at specified water salinity under each of three options, and flush by water in volume 10-15 m3.

EFFECT: increased oil recovery of deposits and watercut reduction of production wells, spreading of process abilities.

3 cl, 1 ex, 2 tbl

FIELD: oil and gas industry.

SUBSTANCE: method envisages the usage of aqueous solutions of binary mixtures - inorganic or organic nitrate or hydrate of alkali metals, which are injected through individual channels. The method includes the mounting of equipment in wells at the selected area of a deposit. Each well is equipped with devices to control the temperature, pressure and composition of reaction products in a real time mode. Formation areas in vicinity to the well with a volume of at least 20 m3 are heated preliminarily up to a temperature of at least 100°C by injection of at least 2 t of binary mixture reagents. Cyclic heating of the formation area in vicinity to the well with a volume of at least 100 m3 and weight of 250 t is made up to a temperature of at least 140°C due to a reaction of at least 12 t of the binary mixture reagents. At that the first level of explosion safety is ensured by the alternation of injection of saltpetre solution portions, 1 t each, with portions of industrial water of at least 0.05 t each. The second level of explosive safety in the borehole is ensured by the continuous control and monitoring of the reaction process with the temperature limitation in the well bore below the pre-blasting temperature. This temperature is determined against signs of the reaction self-acceleration at recorded charts of time-temperature and time-pressure curves. In case of these signs the injection of a saltpetre decomposition initiator is stopped to the well. Further injection of the saltpetre solution with the weight of at least 10 t is made to the preheated formation. At that the third level of explosive safety is implemented in the reaction process in the formation, which is catalysed by the heat accumulated during the previous cycles. The third level of explosive safety is ensured by a ratio of the weight of the saltpetre injected to the pores and fractures of the formation to the weight of the rock. The ratio is equal mainly to 1 to 20. Low explosive probability, close to zero, is ensured by a mixture of 95 wt % of rock and 5 wt % of saltpetre. The injection of reagents at all cycles is made at continuous temperature control in the reaction zone and pressure and temperature control in the zone near the packer and in the process of the reagents injection for the purpose of timely cessation of the reaction when the parameters of the reaction exceed limits of permitted modes.

EFFECT: improved efficiency of oil production at worked-out deposits with an increased production safety.

4 cl

FIELD: oil and gas industry.

SUBSTANCE: this invention is related to production of oil-in-water emulsions with low viscosity during operations with oil. The method for reduction of apparent viscosity for hydrocarbon fluids occurring at oil extraction and transportation includes contact of the above hydrocarbon medium with effective quantity of composite containing at least one polymer with at least 25 mole percent of cationic monomers. The invention has been developed in dependent claims.

EFFECT: increase in oil production.

15 cl, 9 ex, 4 tbl, 4 dwg

FIELD: oil and gas industry.

SUBSTANCE: treatment method of underground hydrocarbon-containing formations involves the following: a) provision of a composition including a thickening initiator measuring pH, and a polymer capable of hydration in a certain pH range; b) pumping of a composition with pH value beyond the limits of the above pH range; c) activation of an action of pH thickening initiator for displacement of pH composition to the above range of its values, and d) provision of a possibility of increasing viscosity of the composition and shaping of a plug. According to another version, a processing method of underground hydrocarbon-containing formations involves the following: a) provision of a composition containing a polymer capable of hydration in a certain pH range; b) pumping of the composition with pH value beyond the limits of the above pH range; c) provision of a pH changing thickening initiator; d) activation of the action of the thickening initiator for displacement of pH composition to the above range of its values, and e) provision of a possibility of increasing viscosity of a composition and shaping of a plug. The invention has been developed in dependent claims.

EFFECT: improving efficiency of initiation and control of plug formation.

15 cl, 5 ex, 3 dwg

FIELD: oil-and-gas industry.

SUBSTANCE: invention relates to oil production, particularly, to from underground oil deposits. In compliance with this invention, at least one production well and one injection well can be used. Temperature distribution in the zone between said wells is analysed. In case temperature is distributed between said zones so that minimum temperature makes at least 20°C, maximum temperature does not exceed 320°C, while their difference makes at least 20°C, aqueous gel-forming preparations are injected via injection well that contain one or several chemical components. These preparations after injection in the deposit form gels under the effects of deposit temperature. Said preparations differ in type and/or concentration of chemical components. Chemical components and/or their concentration are selected to make gel-forming temperature and/or geol-forming time of the second and, if required, any other injected portion, differ from portions injected there before.

EFFECT: higher efficiency of oil extraction due to levelling of injectivity.

19 cl, 4 tbl, 7 dwg

FIELD: oil and gas industry.

SUBSTANCE: according to the method the first and second banks are injected through a hydrocarbon- or water-based displacement fluid to the designed area of the well. At that the availability of a residual saturation area is determined in productive formations with loose - loosely cemented porous and/or fractured reservoirs. The availability of an ultimate water saturation area, an undersaturated transition interval with a film water area and an intensive flow of water diffuse layers and a subarea of high oil content is determined. The availability of ultimate oil saturation is determined. The availability or unavailability of shale barriers at boundaries of the ultimate water saturation area and the transition interval is considered. The water saturated area is cut from the ultimate oil saturation area and an oil inflow is ensured to the productive formation from the subarea of high oil content. Injection is made to the design area of a producer and/or injector. At that the displacement fluid in injected in a quantity of 0.1 up to 500% of the first bank volume. The second bank is injected in a quantity of 0.1-250% of the first bank volume. Polymer resin is used as the first bank. Polymer hardener is used as the second bank. Upon injection the well is transferred to the hydrocarbon inflow mode.

EFFECT: increased efficiency of the method.

24 cl, 47 ex, 1 dwg

FIELD: oil and gas industry.

SUBSTANCE: in the development method of a non-homogeneous oil formation that includes injection to the formation of an aqueous solution of polyacrylamide (PAA), chrome acetate and magnesium oxide, the solution contains additionally a glass or basalt reinforcing microfiber pretreated by a 1-5% aqueous solution of AF9-6 or AF9-12 or constructional reinforcing microfiber (CRF) with the following concentration of components in the solution, wt %: PAA 0.3-1.0, chrome acetate 0.03-0.1, magnesium oxide 0.015-0.07, the above fibre 0.1-0.5.

EFFECT: increased efficiency of the method.

1 dwg, 2 tbl, 1 ex

FIELD: oil and gas industry.

SUBSTANCE: composition for reservoir oil recovery increasing including viscosifier and detergent agent; it contains mixture of rape and palm oils as viscosifier, xylol as detergent under the following ratio in wt %: rape oil 90.0 - 95.0, palm oil 3.0 - 8.0, xylol 2.0 - 5.0.

EFFECT: increased oil-driving properties and oil recovery of reservoirs.

3 ex, 4 dwg

FIELD: chemistry.

SUBSTANCE: invention relates to oil and gas extraction industry and can be used in modifying filtration properties of formations, during hydraulic fracturing, fluid flow separation in a well, borehole cleaning and other repair works. The multipurpose gel-forming composition includes 3-4 wt % carboxymethyl cellulose or polyanionic cellulose, 5-14 wt % potassium alum, 0.2-06 wt % sulphanole, 0.2-0.6 wt % propylene glycol, 0.02-0.06 sodium tetraborate and water.

EFFECT: obtaining a non-toxic, low-density gel-forming composition.

6 ex, 1 tbl

FIELD: oil and gas industry.

SUBSTANCE: method involves displacement of the first fluid on a hydrocarbon basis, which is present at a non-cased interval of a well shaft, with the second fluid, contact of the second fluid to acid natural formation fluid so that the third fluid is formed, where the second fluid contains aqueous liquid dispersed as a disperse phase in oily liquid, and surface active substance (SAS) based on amine and chosen so that the above contact performs protonation of at least some part of SAS with formation of the third fluid included in an emulsion containing oily liquid reversely dispersed as a disperse phase in aqueous liquid, where at least 40 vol % of any solid substances that do not refer to a proppant and are present in the fluid are water-soluble at pH that is lower than or equal to 6.5, and SAS has the above said structure. An underground well treatment system. The fluid containing a reversible invert emulsion containing an aqueous liquid dispersed as a disperse phase in oily phase and the above SAS.

EFFECT: improving destruction efficiency of a filter cake.

20 cl, 6 dwg, 3 tbl, 2 ex

FIELD: oil-and-gas industry.

SUBSTANCE: initial furnace charge containing quartz feldspathic sand and/or quartzite and the material - magnesium oxide source, is dried and grinded. Before grinding diatomite is added at the amount of 0.2-10.0 wt % at the content in MgO furnace charge of 9.1-10.9 wt % in terms of the calcinated substance.

EFFECT: decrease of collapsibility of proppant granules at preservation of low density of material.

1 tbl

FIELD: oil-and-gas industry.

SUBSTANCE: composition for increase of oil recovery of formations containing non-ionogenic and anionic surface-active agents - NSAA and ASAA, boric acid and water, it contains as a named SAA the complex SAA Neftenol VVD, or mix of NSAA AF9-12, or NP-40, or NP-50 and ASAA of volgonat or a sulphanole, or NPS-6 in the ratio 2:1 and in addition contains the technical or distilled glycerin at the following ratio of components, wt %: complex SAA or mix of NSAA and ASAA 1.0-4.0, boric acid 1.0-15.0, glycerin 10.0-90.0, water - the rest. According to another version the named composition as SAA the named SAA complex SAA Neftenol VVD, or the mix of NSAA AF9-12, or NP-40, or NP-50 and ASAA of volgonat or a sulphanole, or NPS-6 in the ratio 2:1 and in addition - the technical or distilled glycerin and carbamide at the following ratio of components, wt %: complex SAA or mix of NSAA and ASAA 1.0-4.0, boric acid 1.0-15.0, glycerin 10.0-90.0, carbamide 5.0-10.0, water - the rest.

EFFECT: decrease of freezing temperature, increase of high-viscosity oil displacement efficiency high-viscosity oil, possibility of use of the composition both at high formation temperature or both at thermal influence, and at low formation temperature.

2 cl, 4 dwg, 2 tbl, 8 ex

FIELD: oil-and-gas industry.

SUBSTANCE: acid composition with varying viscosity for the productive formation treatment contains an surface-active agent SAA1 of amide amine oxide with the generalised formula: where R1 - an non-branched or branched chain of saturated or non-saturated aliphatic group with a number of carbon atoms from about 7 to about 30; R2 - an non-branched or branched chain of saturated or non-saturated bivalent alkylengroup with a number of carbon atoms from 2 to 6; R3 and R4 - identical or different value, they represent alkyl or hydroxyalkyl with a number of carbon atoms from 1 to about 4, or R3 and R4, together with the nitrogen atom to which they are linked, they form heterocycle containing up to six terms; R5 - hydrogen, either alkyl, or hydroxyalkyl group with a number of carbon atoms from 1 to 4, and SSA2 - an amine oxide with the generalised formula: where R3 and R4 - identical or different, represent alkyl or hydroxyalkylite with the number of carbon atoms from 1 to about 4, or R3 and R4, together with nitrogen atom to which they are linked, they form the heterocycle containing to six terms; R6 - cocoalkyl-fraction of residues of fatty acids (C10-C16), meanwhile SAA2 use in composition with PAV1 at a mass ratio (in terms of active ingredient for both SAA) as 1: (3.3-20) respectively, at the contents in acid composition of the named ratio from SAA2 and SAA1 1-2 wt % and solution of hydrochloric acid (in terms of HCl) 6-14 wt % to the total weight of the composition.

EFFECT: achieving of minimum initial viscosity of the acid composition at the minimum effect on rheological behaviour of the acid composition at acid depletion.

3 cl, 1 tbl, 1 ex, 4 dwg

FIELD: oil and gas industry.

SUBSTANCE: in a preparation method of compositions for the isolation of behind-the-casing flows in a well that includes mixing of microcement and additives, oil well portland cement with the specific surface of 800 or 900 m2/kg is used as the microcement and a water-soluble acrylamide polymer, copolymer of vinyl amide and n-vinyl lactam, olefin sulphonate and polyethylene glycol at the water-cement ratio of 0.75-1.2 are used as the additives for the preparation of the composition; a microcement grouting fluid is prepared preliminarily with a solution of the above listed additives in water at simultaneous stirring, then the microcement is added to the produced fluid with the following ratio of ingredients, in weight parts: oil well portland cement with the specific surface of 800 or 900 m2/kg - 100, water-soluble acrylamide polymer - 0.01-0.02, copolymer of vinyl amide and n-vinyl lactam - 1.0-2.5, olefin sulphonate - 0.01-1.0, polyethylene glycol - 0.05-0.15, and water 75-120.

EFFECT: improved workability and efficiency in the isolation of behind-the-casing flows in the well due to the increased strength and expanded time range for hardening of the microcement-based composition.

1 tbl

FIELD: oil and gas industry.

SUBSTANCE: composition contains a surface active substance based on a polymer of ethylene oxide - ITPS 806 reagent grade B 0.1-5.0 wt % and a mixture of aliphatic and aromatic hydrocarbons in the form of ITPS 010 reagent grade A is the rest.

EFFECT: invention provides high dissolving, dispersing and washing activity of a composition in relation to asphaltene-resin-paraffin deposits of a different type, and reduction of oil viscosity in a treated zone.

4 tbl, 4 ex

FIELD: oil-and-gas industry.

SUBSTANCE: composition for bottom hole formation zone processing comprises following elements in wt %: hydrochloric acid - 10.0-20.0, anionic surfactant, or non-ionic surfactant, or cationic surfactant, or mix thereof - 0.4-3.0, phosphorus compound AFON 300M - 0.01-15.0, solvent - 5.0-25.0, water making the rest. Proposed process comprises injection of said acid compound and its driving. Said compound is held to remove the reaction products. Note here that said acid compound is forced in pulse mode or in continuous mode in amount of 1-3 m3 per running meter of perforated depth of the bed at pressure allowable for this bed.

EFFECT: higher capacity of injection wells and fluid inflow due to decelerated reaction with bed rock, lower intensity of acid corrosion.

4 cl, 2 tbl, 17 ex

FIELD: oil and gas industry.

SUBSTANCE: according to the first version grouting composite contains oil-well Portland cement, water and additive that includes chlorine-containing setting accelerator, at that the composite contains sodium chloride and lithium carbonate as the additive with the following ratio of components, weight parts: Portland cement 100, sodium chloride 1.2-4.05, lithium carbonate 1.6-5.4, water 50-52, at that sodium chloride and lithium carbonate are taken in mass ratio 3:4 respectively and according to the second version the composite contains as the additive sodium chloride and biopolymer - reagent based on xanthane gum, at that sodium chloride and the above biopolymer are taken in mass ratio 10:1 respectively.

EFFECT: reduced setting time in conditions of low and normal temperature at simultaneous reduction of thickening time and increased flexural and compression strength at break in the same conditions.

3 cl, 2 tbl

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

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

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

1 tbl

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