RU2801030C2 - Method for developing deposits of hard-to-recover hydrocarbons - Google Patents

Abstract

FIELD: oil and gas industry.

SUBSTANCE: invention can be used to improve the efficiency of extraction of hard-to-recover hydrocarbon reserves (TRIZ), in particular, from oil-kerogen-containing formations of the Bazhenov and Domanik formations, as well as for the extraction of natural bitumen, heavy and high-viscosity oils and gas hydrates. A method is claimed for the development of deposits of hard-to-recover hydrocarbons, in which a cluster of horizontal wells is used, the horizontal sections of which are located in the zone of the productive formation, the supply of working agents into the productive formation whereas the target product are selected from it through a casing string, which equips the vertical section of each well. At the first stage of the method, a one-stage hydraulic fracturing of the productive formation and its impregnation with a solvent are carried out on the horizontal section of each well. At the second stage, cyclic pumping of the working agent is carried out in the form of water with a temperature of 374°C to 593°C at a pressure of 22.1 MPa to 70 MPa, and then the same water with its saturation with nanosized particles of metal oxides and hydrogen, for several repeated cycles, during which a well retort is formed in the near-wellbore volume of each well and its volume is increased with each the next cycle until the well retorts merge into a combined retort. At the third stage of the method, at least one well is use for injection, and the rest wells are used for production, and through at least one injection well, the working agent is pumped in the form of a WIADAP liquid and nanohydrothermal fracturing is performed, and then into the combined the retort is pumped with a working agent in the form of water, with a temperature of 40 to 120°C at a pressure of up to 100 MPa, by means of which the target product is displaced from the combined in-situ retort to the daylight surface through production wells in the form of an oil-water emulsion.

EFFECT: increased productivity of the selection of hydrocarbons during field development in combination with a high oil recovery factor (ORF).

2 cl, 8 dwg

Description

The invention relates to the oil and gas industry and can be used to improve the efficiency of extraction of hard-to-recover hydrocarbon reserves (TRIZ), in particular, from oil-kerogen-containing formations of the Bazhenov and Domanik formations, as well as for the extraction of natural bitumen, heavy and high-viscosity oils and gas hydrates.

It has been established that the largest strategically significant hydrocarbon reserves of Russia are concentrated in the Bazhenov and Domanik formations. Works on their development were started by Russian oil companies several years ago and consisted mainly in the adaptation of North American shale mining technologies and did not bring positive economic results.

Experts know that North American "shale" production technologies are perfected (1) technologies for drilling long-barreled horizontal wells with a length of their horizontal section, often more than 3000 meters, followed by (2) multi-stage hydraulic fracturing (MSHF) in such wells - up to 50 stages on a horizontal section.

The relative success of their application, for example, in the United States on the Bakken/Three Forks, Eagle Ford, Permian oil shale formations or in Argentina on the Vaca Muerta oil shale play, is due to the fact that at a relatively low content of _Corg (organic carbon: S ₁ (oil dense rocks) + S ₂ (kerogen)) in their oil-kerogen-containing formations (on average, up to 4 percent), their thickness (layer thickness) reaches significant values - from 80 to 200 meters or more.

This made it possible to form a significant drainable volume from one well after multi-stage hydraulic fracturing, equal, on average, to 40 million m ³ . With a 4% _Corg content, such a reservoir volume drained from one horizontal well contains approximately 3.5 million tons of _Corg , of which approximately 880 thousand tons (25%) is mobile light oil of tight rocks (NPP) ( Tight Oil) (S ₁ ), which is also called "tight oil" and, often, not quite correctly, "shale oil".

With an average oil recovery factor (ORF) of North American shale technologies equal to 8%, the projected cumulative production (Estimated Ultimate Recovery (EUR)) from one well of the NPP is 70.4 thousand tons, or from 500 to 600 thousand barrels (550 thousand tons). barrels, on average, for calculation).

With an oil price of US$70/bbl and an NPP production cost of, for example, Bakken/Three Forks in North Dakota of US$57.8/bbl [1], projected revenue per well is US$6.7 million . These calculations are based on the facts of US “shale” oil production and are confirmed by practice, when the North American “shale economy” revives when the price of oil rises above $60 per barrel. [2].

The Bazhenov formation differs from the North American oil shale plays in that its layers are rich in organic carbon ( _Corg - up to 23%), they are more plastic, but their average thickness is about 20 meters. Moreover, in its reservoirs, NPP is approximately 18 times less than kerogen [3].

Thus, at Bazhen it is possible to form a drained formation volume from one well, approximately 10 times less than on North American oil-bearing shale plays, and the oil recovery factor on the Bazhenov formation, according to experts, after multi-stage hydraulic fracturing, on average, does not exceed 6% .

As a result of simple calculations, it is clear that with a sufficiently high 10% _Corg content, the formation volume drained from one Bazhenov well (4 million m ³ ) contains approximately 1320 thousand tons of _Corg , of which 132 thousand tons (10%) are NPP (S ₁ ). With oil recovery factor = 6%, approximately 8 thousand tons of OOP are recovered on the day surface of the well, which, in general, corresponds to the practice of oil production in the Bazhenov formation.

According to experts' estimates, in order for the production of OOP from the Bazhenov formation to become profitable, the cumulative production of OOP for the entire period of operation of the well should exceed 30 thousand tons. According to most experts, this is possible only in isolated cases when developing "sweet spots" (according to S ₁ ).

Thus, the insufficient thickness/thickness of the Bazhenov formations, combined with their high heterogeneity and plasticity (in the words of academician Ivan I. Nesterov: "in the absence of a "skeleton" of the formation"), is the main reason for the unprofitability of Bazhenov mining projects predicted by experts in if they are aimed at extracting only NPP from its layers.

All of the above applies equally to the Domanik Formation.

It follows from the above that the cost-effective development of the Bazhenov (and Domanik) suite, due to its qualitative difference from the North American oil-bearing shale plays, is possible only with the involvement in the active development of an additional hydrocarbon resource - immobile kerogen (S _2b ) and immobile and slow-moving bituminous oil (S _2a ), which implies the use of technologies based on the impact on the reservoir with high-temperature working agents of influence (RAW).

Such technologies, the use of which may be quite successful in the Bazhenov and Domanik formations, should at least additionally involve kerogen and bituminous oil in the active development, ensure an increase in the permeability of the productive formations of the suites, as well as their reenergization - an increase in the internal energy of the formation, its in-situ pressure provided that the degree of molecular blocking of the fluid-conducting channels is reduced and hydrocarbons are withdrawn through the formation zones with increased permeability in the well flowing mode, provided that the formation compaction is prevented - the pressure in it drops below the hydrostatic pressure.

The technologies based on the thermochemical impact on the productive formation by working agents injected from the daylight surface into the productive formation are currently considered the most promising.

For example, there is a known method for the development of deposits of high-viscosity and heavy oils, including the construction of a well, the sequential injection of a working agent into the well - a heat carrier, in the form of a certain volume of a thermally stable direct-type emulsion-dispersed system with surface-active properties, followed by the extraction of oil from the well , and after injection of the calculated amount of coolant, the well is kept closed for a certain time to impregnate the near-wellbore zone of the productive formation, and the RDN reagent system is used as a working agent, which is formed at an RDN concentration of 2.5-10.0 wt. % in fresh or formation water. (see RF patent No. 2163292, class E21B 43/24, 2001).

As a result of the analysis of this method, it should be noted that it is based on the use of a coolant having a low temperature as a working agent injected into the reservoir (the studies were carried out in laboratory conditions at a temperature of +100°C and a pressure of 2 atm.), which is not allows to carry out an active impact on kerogen and heavy oil in order to modify them into lighter hydrocarbon fractions. The near-wellbore zone of the productive formation formed as a result of such thermal impact with a slightly elevated temperature (retort) relative to the formation temperature is small in volume and does not allow the extraction of an acceptable (from the point of view of profitability) amount of hydrocarbons to the surface. Thus, the implementation of the known method does not provide an acceptable ORF.

A known method of cyclic development of high-viscosity oil and bitumen deposits, including drilling of wells arranged in rows with inclined-horizontal parallel in the horizontal plane trunks, with wellheads in a checkerboard pattern, two-stage cyclic injection of a working agent - a heat carrier in the form of steam and oil production by wells, while , at the first stage of the cycle, the coolant is pumped into the odd wells of the row and oil is produced from the even wells of the row, after which the wells are stopped for the period of impregnation of the reservoir, and at the second stage of the cycle the coolant is pumped into the even wells of the row and oil is produced from the odd wells of the row, after which they stop wells for the reservoir impregnation period, repeat the cycle several times, increasing or leaving the time of coolant injection and oil production unchanged from cycle to cycle (see RF patent No. 2418945, class E21B 43/24, 2011).

As a result of the analysis of the known method, it should be noted that a large number of wells allows you to increase the area from which oil is produced. The use of a heated coolant in the form of steam makes it possible, due to heating, to reduce the viscosity of oil in the near-wellbore zone of the productive formation and to slightly increase the oil recovery factor, which is also facilitated by the introduction of the impregnation process, as well as the development of repeated cycles.

However, the temperature of the heat carrier used for the implementation of the method - steam, which is 280-350 ° C, provides only a slight heating of oil products, for example, heavy oil, which is delivered to the day surface in a heated (less viscous) state, cools quickly, becomes more viscous again and for transportation, it is necessary to dilute it by adding a solvent.

The pressure at which the coolant is injected into a low-permeability rock containing heavy oil does not allow it to penetrate a considerable distance from the wellbore and form near-wellbore retorts, significant in volume,

The temperature of the coolant used is also insufficient for intense heating of the parent rock and the implementation of the reaction of molecular modification of kerogen and bituminous oil into synthetic oil in it. The foregoing does not make it possible to ensure, when using the method, sufficient productivity of the selection of the target product, as well as an acceptable oil recovery factor.

A known method for the extraction of hydrocarbons from oil-kerogen-containing formations, including the preparation of working agents of influence (RAS), their sequential injection through a column of heat-insulated tubing into the near-wellbore zone of a productive formation for a phased thermochemical impact on it, followed by the selection of hydrocarbons at each stage and their delivery through the column tubing to the day surface, and the first stage of thermochemical impact on the productive formation is the stage of formation of a near-wellbore zone with increased permeability and increased volume due to injection into the near-wellbore zone of RAW in the form of water having a temperature above 593°C at a pressure of 23 to 50 MPa, after which, at the second stage, a cyclic thermochemical effect of RAS is carried out on the productive formation to generate hydrocarbons, using water as a RAW, with a temperature above 593 ° C and a pressure of 23 to 50 MPa, saturated with Fenton's reagent, as well as RAW in the form of water, temperature from 380 to 593°C at a pressure of 23 to 50 MPa, followed by the selection of hydrocarbons at the third stage and their delivery to the day surface (see RF patent No. 2704684, cl. E21B 43/247, 2019) is the closest analogue.

As a result of the analysis of this method, it should be noted that it is very difficult to implement, since it involves the use of a large number of different RAS, which are pumped in a strictly defined sequence through the tubing string into the productive formation, and the process of thermochemical impact of each RAS used on the productive formation takes a significant time, which dramatically reduces the productivity of the method.

It is also very significant that when using a cyclic thermochemical impact on a productive formation, a specific insignificant amount of RAS is injected into it through a specific small area of the productive formation exposure, as a result of which the specific coefficient of the formation heating rate has a very low value (the specific formation heating rate coefficient is equal to: volume warming up of the productive formation per day at a given enthalpy RAW and heat capacity of the productive formation (heat capacity of rock and organic carbon (С _org ) (mass %))/volume of near-wellbore retort of the productive formation).

The specific rate of heating of the productive formation demonstrates the dependence of the heating rate of the productive formation (per day) on the volume of the in-situ retort, which should be formed as a result of thermochemical impact on the productive formation, and is necessary to compare the integrated efficiency of various scenarios of thermochemical impact on the productive formation of hydrocarbon deposits.

Experts in the field of oil production understand that the recovery factor of high-tech oil (HOT) during cyclic thermochemical impact on a productive formation decreases as the formation zone, which is subjected to thermochemical impact, moves away from the wellbore. So, for example, at a distance of 5 meters from the wellbore, the calculated recovery factor according to the WTH during cyclic thermochemical impact on the productive formation can reach 90 percent or more, and at a distance, for example, 30 meters from the wellbore, the calculated recovery factor according to the WTH during cyclic thermochemical impact on the productive formation the formation is reduced to 10-15%.

Also, for example, when using (1) a horizontal well with a horizontal wellbore 1200 meters long and (2) a supercritical water (SCW) generator with a maximum thermal power of 50 MW (180 million kJ / h) and capable of producing 64800 kg / h SCR (T=480°C at P=400 bar ^; enthalpy 2777 kJ/kg) ^per hour per hour the reservoir is injected with approximately 86 kg of the above RAW (SCR). With such a volume of injection of RAS into the productive formation for the development of an in-situ retort with a volume equal to 4.2 million ^m reservoir, it will take 2553 days or 6.99 years. If, for example, multi-stage hydraulic fracturing was performed in a productive formation from a horizontal section of a horizontal well (18-stage hydraulic fracturing, performed by Gazprom Neft PJSC in a productive formation of the Bazhenov formation in October 2019. Proppant injection per stage - 150 tons; proppant bulk density - 1 ,5 tons / m ³ ; the thickness of the two-sided crack is 1 mm.), as a result of which 18 ΜΕΓΑ cracks were formed in the reservoir, in total, having an area of \u200b\u200bthe internal surfaces of the cracks equal to approximately 3.6 million m ² , then in this case, the specific , per 1 m ² of the inner surface of ΜΕΓΑ fractures, only 0.02 kg of SCR was pumped per hour. This is a very low figure.

Thus, for the solution - the closest analogue, a very low specific rate of heating of the productive formation is characteristic.

The above circumstances significantly reduce the effectiveness of the use of thermochemical technologies in the development of oil-bearing shale formations, such as the Bazhenov formation and / or Domanik formation, both in terms of productivity and oil recovery factor.

The technical result of the present invention is to develop a method characterized by a high productivity of hydrocarbon extraction during field development in combination with a high oil recovery factor due to the optimal combination of the stages of the method, as well as the conditions for implementing each of them.

The terms used below in the description of the claimed invention mean the following.

Horizontal well

To implement the method, horizontal wells with a vertical section and an associated horizontal section located in the reservoir are used. The length of the horizontal section of each well should be sufficient for single-stage hydraulic fracturing (SHF) and is typically between 10 and 100 meters.

Single-stage hydraulic fracturing (SHF)

In the claimed invention, fracturing is carried out on a horizontal section of horizontal wells using a wide range of agents, preferably hydrocarbon solvents, such as methanol or liquefied hydrocarbon gases (LPG) as a working medium [6].

The hydraulic fracturing is carried out to increase the area (up to 10000 m ² ) of the exposed surface of the rock in the near-wellbore zone of the productive formation, which is necessary for the injection of a significant amount of RAS into the productive formation (from 50 to 1000 tons per hour), which allows for the delivery of 20 to 200 kg RAV per 1 m ² of the area of the productive formation exposed after carrying out.

The LPG-based working medium can be a mixture of propane and butane in the liquid state. Such a working environment is significantly different, for example, from the water media traditionally used for hydraulic fracturing. The LPG-based working medium contains an inorganic gas phase such as CO ₂ , N ₂ and mixtures thereof. The density of hydrocarbon gases is 2 times less than that of water, which causes a reduced pressure of the hydrostatic column of liquid in the well during hydraulic fracturing, thus, the development will be easier; the viscosity of propane/butane is 6 times lower than that of water, therefore, a lower pressure drop is required to move the liquid along the rock fracture during development; the surface tension of the medium used is 6 times lower than that of water, which implies a reduced capillary pressure when moving through a porous medium, i.e. when advancing through the formation rock, the fluid will experience a lesser braking effect upon contact with the rock and formation fluid.

It is very significant that 1 m ³ of liquid hydrocarbon gas can be converted into 272 m ³ of ordinary gas, that is, during well development, the liquid will aerate itself, i.e. it is self-gassing” [7].

Thus, anhydrous hydraulic fracturing is more effective than water-based hydraulic fracturing, and they have already found application in the Bazhenov formation. But the large-scale use of waterless hydraulic fracturing is hindered by the high cost of the working medium, since during the implementation of hydraulic fracturing, a significant part of the working medium remains in the productive formation in an unrecoverable state. In the claimed invention, after the hydraulic fracturing, the used working medium is taken from the productive formation to the day surface and can be reused, and therefore, the economic factor will not be an obstacle to the implementation of anhydrous hydraulic fracturing as part of the large-scale use of the claimed invention, in particular, on the Bazhenov and/or Domanik suites.

Ultra-supercritical water generator. The claimed invention uses an ultra-supercritical water generator, known from RF Patent No. 2726702 dated September 26, 2019. , second and third heating sections. The first heating section is located in the upper part of the housing and is equipped with an inlet manifold that can be connected to the feed water supply line. The second heating section is located in the lower part of the housing directly above the coolant generation device, its inlet is connected to the outlet of the first section, and its outlet is connected to the inlet of the third heating section located in the cavity of the housing between the first and second sections. In this case, the generator is equipped with a second heat-generating module, including a heat-carrier generation device located in the lower part of the housing of this module, a superheating section, a sealed container mounted in the housing above the heat-carrier generation device, in which a closed circulation channel is formed, filled with a heat-generating agent. At the same time, the generator is additionally equipped with a heat-generating agent circulation mechanism located in the circulation channel, in which the superheating section is also located, its input is connected to the output of the third section of the first heat-generating module, and the output can be connected to the working agent consumer. The technical result is to increase the efficiency and productivity of the generator, as well as to reduce its weight and size characteristics by providing more efficient heating of the superheating section.

Compensator for thermobaric changes in the length of the casing string

Such a compensator is understood as a device that allows the casing string to repeatedly cyclically change its length (lengthen and shorten) in the well, provided that the separation of the well volume below the compensator from the volume of the well, above the compensator, is maintained.

VTH

VTH is understood as an oil mixture (Oil Blend), compositionally consisting of:

- molecularly modified and partially upgraded mobile NPP obtained as a result of thermochemical treatment of the reservoir, as well as initially located in the reservoir;

- desorbed molecularly modified and partially improved NPP, which before thermochemical treatment was in an adsorbed state on the inner surface of the rounded and slotted pores of the formation (adsorbed NPP, up to 25% of the total NPP located in the formation). The less permeable the productive formation is, the more specifically it contains the adsorbed, retained by the surface of the fluid-conducting channels of the NPP;

- molecularly modified and partially upgraded liquid and mobile oil products of bituminous oil conversion (thermobitumen + heavy/medium oils);

- Synthetic Oil generated inside the productive formation from kerogen.

High viscosity, heavy, medium and light oils. The claimed method can be used for the extraction of natural bitumen (bituminous oils: density at 20°C and 0.1 MPa, g/cm ³ : more than 0.895), high viscosity, heavy (>100 cps (centipoise), medium (density at C and 0.1 MPa, g/ ^cm3 : 0.851-0.870) and light oils (density at 20°C and 0.1 MPa, g/ ^cm3 : 0.831-0.850).

Typically, thermal enhanced oil recovery methods are used to produce high-viscosity, heavy and bituminous oils. However, back in the 60-80s of the last century, 43 multi-year (duration up to 7-10 years) pilot projects were carried out in the world on the use of steam flooding in fields, for example, medium (24 API; "Shell Oil Company" field Brea Field, Orange County, California.) and, for example, light oil (34 API; Texaco Inc., Shiells Canyon Field, Ventura County, California.) [10], [11]. Of the 43 pilot projects, 30 pilot projects were analyzed; it was found that as a result of the use of steam flooding, the oil recovery factor (ORF) was increased by 19% compared to conventional methods of developing these fields of light and medium oil.

Gas hydrates

Gas hydrates (clathrates) are solid crystalline compounds of low-molecular gases such as methane, ethane, propane, butane, etc., with water. Outwardly, they resemble snow or loose ice. They are stable at low temperatures and high pressure; If these conditions are violated, gas hydrates easily decompose into water and gas. Methane is the most common hydrate-forming natural gas. The content of methane in hydrates is very high: more than 160 cubic meters can be obtained from one cubic meter (under standard conditions). m of methane, and hydrocarbon gases up to 220 cubic meters. m. In terms of energy content (calorific value), gas hydrates are comparable to bituminous oil and oil sands.

The thermal technologies proposed today for the production of gas hydrates are ineffective, since they require the injection of a significant amount of coolant into the reservoir. So, for example, for the "melting" of one kilogram of gas hydrates, 500 kJ of heat is required, and one kilogram of wet steam contains, for example, at a pressure of 13 MPa and a temperature of 50 ° C, only 220 kJ (pilot project at the Mallik field, Canada). That is, taking into account heat losses, it will take approximately 3 kg of wet steam to “melt” 1 kg of gas hydrates. From an economic point of view, this prospect is unattractive.

The economic picture changes dramatically in the case of using one of the main working agents of influence (RAS) in the form of superheated steam with a high degree of superheating for the extraction of gas hydrates. So, for example, one kilogram of RAW of the claimed invention, which at a pressure of 13 MPa and a temperature of 500 ° C contains 3337 kJ, can “melt” at least 6.5 kg of gas hydrates, and the efficiency of the technology is increased by 15 times.

To generate one kg of the above RAW, 0.1 m ³ of natural gas is used, and at the same time, as a result of hydrothermal / thermochemical effects, we get: (6.5 * 0.2) 1.3 m ³ of gas. The energy ratio is 1:13. This ratio is typical for medium-density oil production.

Nanoscale particles of metal oxides and hydrogen

To implement the claimed invention, RAV No. 3 is used in the form of supercritical water saturated with hydrogen and nanosized particles of metal oxides, mainly aluminum oxide (Al ₂ O ₃ ), iron oxide (FeO, Fe ₂ O ₃ , Fe ₃ O ₄ ) and / or zinc oxide (ZnO), which are simultaneously (1) catalysts for partial in-situ improvement of the quality of liquid hydrocarbons, (2) a nanoproppant that fixes nanosized fluid-conducting channels and, thus, slows down the process of compaction of the productive formation during the selection of the target product from it - WTH, as well as (3) a bridging agent, which, when injected into the productive formation, reduces the permeability of the most permeable units of the productive formation and, thus, levels the front of the agent that displaces the WTH from the productive formation to the daylight surface. The latter function is especially significant in the development of the Bazhenov formation, since in most cases its productive formation consists of 5 units with different concentrations of _Corg and, accordingly, different permeability. Therefore, when injected into a productive formation, RAW first penetrates most intensively into the most permeable units of the productive formation. (It has been established that, as a rule, the 2nd unit has the highest permeability; for example, (Palyanovskaya area of the Krasnoleninskoye field), 4.649 mD (second unit) compared to the least permeable 4th unit (0.756 mD)). But, if RAW contains nanosized particles of metal oxides, then they quickly clog the most permeable packs and, thus, the RAW front in the productive formation is leveled, that is, the RAW is injected in almost equal proportions into each of the 5 packs of the Bazhenov reservoir. retinues.

RAW No. 3 is also saturated with hydrogen, which is one of the products of the exothermic oxidation reaction of microsized metal particles in the ultra-supercritical water flow in the inorganic compounds oxidation reactor installed between the ultra-supercritical water generator and the surface piping of the well cluster at the field site connecting the oxidation reactor inorganic compounds with high-temperature wellhead Christmas trees. Due to the presence of hydrogen in RAW No. 3, the process of in-situ improvement of the quality of liquid hydrocarbons proceeds more actively in the reservoir, namely the hydrocracking process, as a result of which new, more valuable low-molecular hydrocarbons are formed inside the reservoir.

Solvents

The claimed invention uses organic solvents, mainly from the groups: (1) aromatic solvents (benzene, toluene, solvent, etc.); (2) chlorine-substituted hydrocarbons (chloroform (trichloromethane), carbon tetrachloride, etc.); (3) hydroaromatic solvents (tetralin, decalin, etc.).

Selection of the target product in the well flowing mode and compaction of the productive formation.

It is very essential for the implementation of the claimed method that the selection of the target product as part of a water-oil emulsion, the removal of dissolution products consisting of a solvent, dissolved resins and asphaltenes, liquid mobile hydrocarbons, hydrocarbon and other gases (liquid mixture) from an oil-kerogen-containing formation is carried out in the flowing mode wells under pressure, the value of which is always higher than the hydrostatic pressure. This approach does not allow compaction of the productive formation. Kerogen-bearing reservoirs, as a rule, are devoid of a “skeleton”, their porosity and permeability are maintained only due to the fact that in the pore space of such a reservoir there are in-situ fluids, the intergranular bursting pressure of which always exceeds the level of hydrostatic pressure. Therefore, if the bursting pressure of in-situ fluids in a reservoir falls below the level of hydrostatic pressure, then the process of compaction of such a reservoir begins, or, in other words, the process of "collapse" of both subhorizontal and subvertical fluid-conducting channels, which leads to a decrease in the porosity and permeability of the reservoir .

When withdrawing any liquid mobile mixture from such a productive formation, one of the components of which are liquid and gaseous hydrocarbons, it is important to observe the above condition and not allow the in-situ pressure to drop below the hydrostatic pressure level and always maintain it at a level that is 2-3 MPa exceeds the level of hydrostatic pressure.

Maintaining a productive formation in a state of decompression and dilatancy processes (DILATANSIA. (from Latin dilate - expand), change in the volume of material during shear deformation) within the productive formation itself due to the introduction of enthalpy (heat content / heat) into the productive formation is very important to achieve the specified technical result.

CIN according to VTN (or according to _Corg ). In the claimed group of inventions, the calculation of oil recovery factor according to WTN or organic carbon is carried out, for example, according to the Bazhenov formation as follows:

For example, the content of _Corg in the reservoir of the Bazhenov formation is 15% or 330 kg of HC/m ³ (HC - hydrocarbons).

Based on the data of the publication [9], according to which the content of S ₁ in the productive strata of the Bazhenov formation, on average, is 10% of the content of S ₂ , we obtain that at _Сorg = 15% in ¹ m suites content S ₂ =297 kg HC/m ³ and S ₁ =33 kg HC/m ³ .

Calculation S ₁

Recovery factor No. 1 for S ₁ =45% (extraction of mobile oil from tight rocks). In this case, the oil recovery factor is determined experimentally (for example, by laboratory studies of core material).

Tight oil extracted to the surface (33 * 0.45): 14.85 kg from one m ³ of the Bazhenov formation.

Calculation S ₂

Residual oil generation potential, for example, Type II kerogen - 0.6.

297 kg HC / m ³ * 0.6 \u003d 207.9 kg HC / m ³

The value of converted hydrocarbons in the reservoir during its 100% heating to a temperature of 400°C = 0.7 (conservatively). 207.9 * 0.7 \u003d 145.53 kg HC / m ³

Recovery factor No. 1 for S ₂ =45% (recovery of synthetic oil generated in the reservoir from kerogen). Recoverable synthetic oil:

145.53 kg HC / m ³ * 0.45 \u003d 65.48 kg HC / m ³

Calculation of oil recovery factor according to VTH or according to C _org.

ORF No. 1 for S ₁ + ORF No. 1 for S ₂ \u003d ORF for VTN or C _org.

Retrievable VTN:

14.85 kg / m ³ + 65.48 kg HC / m ³ \u003d 80.33 kg HC / m ³

CIN according to VTN or according to C _org. \u003d 24.34% (80.33 kg / m ³ / 330 kg / m ³ ).

Intraformation retort

In the present invention, an in-situ retort should be understood as some near-wellbore volume of a productive formation in which the process of in-situ retorting is carried out as a result of thermochemical impact on the formation. An in-situ retort is a geohydrothermochemical reactor artificially formed in an oil-kerogen-containing reservoir, existing in a nano-sized mineral matrix filled mainly with organic substances, which, in fact, are low-permeability reservoirs of oil and oil-bearing shale plays. The temperature inside the in-situ retort is higher than the natural temperature of the productive formation surrounding it. The pressure inside the in situ retort is generally higher than the natural pressure surrounding the reservoir.

Artificial formation of an in-situ retort as a result of thermochemical (or hydrothermal) exposure is possible because the permeability of the productive formation of oil-bearing shale plays, including the Bazhenov formation, is very low and there are no large pores and cracks in it. Moreover, as the temperature of the in situ retort rises above 150° C., a "shell" forming the retort is formed around it, the permeability of which is lower than the permeability of the reservoir in its natural state. When carrying out thermochemical impact on the near-wellbore zone of the productive formation, a cyclic increase in the volume of the in-situ retort occurs. This is due to the cyclicity of the thermochemical treatment of the productive formation, as well as the cyclical selection of molecularly modified and partially upgraded hydrocarbons from it. During the implementation of the above processes, the geometric outlines and volume of the in-situ retort are constantly changing while maintaining the general growth trend. The volume of the in-situ retort increases in the process of cyclic thermochemical impact on the reservoir and decreases in the process of cyclic extraction of molecularly modified and partially upgraded hydrocarbons from the reservoir, but the decrease in the volume of the in-situ retort always remains less than the value of the previous increase in its volume, which, in general, and provides a cyclic process of growth of the in-situ retort, explains the cyclical nature of the increase in its volume and changes in its geometric shape while maintaining the general trend of its growth until the merger of all near-wellbore retorts into a single (combined) high-temperature in-situ retort having an average temperature of 400°C, volume which, depending on the porosity and permeability properties (FPP) of the productive formation, can be from 0.1 to 2 million cubic meters. At the same time, depending on the content of kerogen in the reservoir, a significant amount of enthalpy is introduced into the reservoir to heat up to 400°C. So, with an average content of kerogen in the reservoir equal to 10 wt. %, for heating 1 m ³ of the productive formation to 400°C, an enthalpy equal to 1239417.155 kJ/m ³ of the productive formation is required to be introduced into the productive formation, and at 20 wt. % content of kerogen in the reservoir, - 1071950.811 kJ/m ³ of the reservoir. Thus, the formed high-temperature in-situ retort is a store of thermal "artificial" geothermal energy. In the claimed invention, after the end of the cyclic thermochemical impact on the productive formation, “cold” water is injected into it to displace the WTH from the productive formation, from the volume of the combined high-temperature in-situ retort (essential feature of the claimed invention).

Increasing reservoir permeability in the retort

An increase or decrease in the permeability of a reservoir in a retort almost always occurs at the nanoscale. In the course of thermochemical impact on a productive formation, an increase in its permeability is achieved due to:

- growth of intergranular permeability as a result of uneven heating of rock grains and the resulting thermal stresses;

- growth of intergranular permeability due to the dissolution of carbonates and aluminosilicates by acids that are generated in the process of "dry" pyrolysis or hydropyrolysis of kerogen in supercritical water and/or pseudo-supercritical fluid in the presence of carbon dioxide (carbonic acid);

- growth of intergranular permeability due to the dissolution of salts by ultra-supercritical and/or supercritical water;

- growth of organic and fractured permeability, mainly at micro and meso levels due to pyrolization / hydropyrolysis of kerogen and the implementation of auto-fluid fracturing of the productive formation as a result of thermal expansion within reservoir hydrocarbons and the generation of synthetic hydrocarbons and other gases, including from bituminous oil and oil of low permeability rocks (an increase in the temperature of the reservoir by 1°C leads to an increase in pressure inside the closed pore by approximately 4 bar);

- increase in the permeability of the reservoir due to the dissolution of hydrocarbon solvents layers of bitumen, consisting mainly of resins and asphaltenes;

- increase in permeability due to the implementation in the reservoir of nanohydrothermal fracturing of the reservoir.

Subcritical water (DK-water), supercritical water (SC-water), ultra-supercritical water (USK-water), multicomponent pseudo-supercritical fluid (MPS-fluid).

In engineering, the critical state of a substance is understood as such a state in which the distinction (and boundary) between its liquid and vapor/gaseous phases disappears. This state occurs at critical temperature and critical pressure, which corresponds to the so-called critical density (p) of the substance. The concept of critical parameters is used for pure substances, for example, for water, individual gases and individual hydrocarbons. For their mixtures, the concepts of critical parameters, critical and supercritical state are replaced by the concepts of pseudo-critical parameters, pseudo-critical and pseudo-supercritical state or pseudo-ultra-supercritical state. In the claimed invention, both pure substances, for example, water, and complex mixtures of various substances in the ultra-supercritical, supercritical, pseudo-ultra-supercritical and pseudo-supercritical states are used as a working agent.

A typical range of supercritical parameters is pressure from 24.5 to 28.5 MPa at temperatures from 374°C to 580°C. The American Electric Power Research Institute (ERPI) calls ultra-supercritical steam cycles where the steam is heated to over 593°C.

In this application, the term subcritical water (subcritical water) should be understood as water having a temperature (T) up to 374°C and a pressure (P) up to 22.1 MPa.

The term supercritical water (water in a supercritical state) should be understood as water with a temperature of 374°C to 593°C at a pressure of 22.1 MPa to 70 MPa.

Water having a pressure above 28.5 MPa and a temperature above 593°C is ultra-supercritical water or ultra-supercritical water, and a mixture of fluids having a pressure above 22.1 MPa and a temperature above 374°C is a multicomponent fluid in pseudo -supercritical state or multicomponent pseudo-supercritical fluid.

Superheated steam with a high degree of superheat; extraction of natural bitumen, high-viscosity and heavy oils. In this application, the term superheated steam with a high degree of superheat should be understood as water having a temperature of up to 700°C and a pressure in the range from 1 to 22 MPa. With a minimum pressure of 1 MPa and a temperature of 700°C, superheated steam with a high degree of superheat has the following characteristics: density 2.232 kg/m ³ , enthalpy 3924 kJ/kg. At a maximum pressure value of 22 MPa and a temperature of 700°C, superheated steam with a high degree of superheat has the following characteristics: density 52.37 kg/m ³ , enthalpy 3795 kJ/kg. In the case of using RAW based on superheated steam with a high degree of superheating at a depth of up to 2200 meters or in the form of SCR (in pure form or with various additional ingredients: hydrocarbon solvents, alcohols, oxidizers, hydrogen and catalysts) at a depth of more than 2200 meters for the extraction of natural bitumen, high-viscosity or heavy oils, they are irreversibly molecularly modified in the most productive reservoir; become "lighter" and their density and viscosity are irreversibly reduced. Partial upgrading of high-viscosity, heavy and bituminous oils, for example, in supercritical water, has many advantages due to the fact that SCR has the properties of a non-polar medium, which can extract lighter hydrocarbons and disperse heavier ones that are insoluble in it, leading to the suppression of coke formation (up to Τ = 480°C) and an increase in the yield of liquid hydrocarbons only due to this effect. The use of catalysts and hydrogen increases the efficiency of the process of partial upgrading of natural bitumen, high-viscosity and heavy oils in SCR.

Regarding the use of RAW in the form of superheated steam, the following can be noted:

- the higher the degree of overheating of superheated steam, the higher the degree of efficiency in the production of high-viscosity, heavy and bituminous oils;

- the greater the volume of superheated steam is injected into the reservoir, the higher the degree of efficiency in the production of high-viscosity, heavy and bituminous oils;

- the higher the rate of injection of superheated steam into the reservoir and its movement in it, the higher the degree of efficiency in the production of high-viscosity, heavy and bituminous oils.

The mechanism for increasing the efficiency of production of natural bitumen, high-viscosity and heavy oils is associated with the implementation of the following main effects in a productive reservoir:

Viscosity and density reduction: the higher the degree of superheated steam superheat, the greater the irreversible reduction in viscosity and density of high-viscosity, heavy and bituminous oils occurs.

Distillation effect: The extent of the distillation effect increases as the degree of superheated steam increases and the amount of steam injected into the reservoir increases. So, for example, when overheated by 4 ° C, the degree of distillation was 11.158%, when overheated by 10 ° C - 10.903%, and when using saturated steam - 10.423%. The degree of overheating of superheated steam used in IGTT, for example, at a depth of 1500 meters (P = 15 MPa at T _sat . = 342.155 ° C) can reach 135 ° C (T _sat. - saturation temperature).

Thermal expansion of: hydrocarbons, which results in an increase in the energy of the reservoir, allows them to be taken from the reservoir for some time in the well flowing mode.

Hydrothermal cracking: As a result of the use of superheated steam with a high degree of superheat, desulfurization, denitrogenesis and hydrogenation of high-viscosity, heavy and bituminous oils are carried out. Hydrothermal cracking significantly reduces the viscosity of hydrocarbons, and also reduces the content of sulfur, oxygen and nitrogen in them, which improves the mobility of hydrocarbons in the pore medium.

Hydrothermal mechanical fragmentation of molecules: the thermal energy of SCR is converted into the energy of the movement of a superheated steam flow with a high degree of superheat (the kinetic energy of the steam flow), which is then converted into mechanical work in the fluid-conducting channels upon contact with hydrocarbon molecules and rock grains and, thus, inside the reservoir a NANO/THERMOMECHANO/CHEMICAL REACTOR is formed. At high temperatures, C-C (carbon-carbon) bonds weaken and, under the influence of the kinetic energy of the steam flow, in particular, large hydrocarbon molecules begin to experience deformation stresses and break down into smaller hydrocarbon molecules. The longer the hydrocarbon chain, the less energy is required to break it.

Reduction of clogging: high-speed movement of superheated steam with a high degree of superheating, or water-oil emulsion as it is withdrawn from the reservoir, effectively removes the clogging agent (for example, drilling fluid particles) from the near-wellbore volume of the reservoir, which increases its permeability.

More generally, the following classification of mechanisms for increasing the efficiency of production of high-viscosity, heavy and bituminous oils using superheated steam with a high degree of superheating of IGTT is also possible:

The mechanism of physical heating: the essence of this "mechanism" is the injection into the reservoir of RAS, which has the highest possible temperature, in the form of SCR or superheated steam with a high degree of superheat. As a result of the maximum possible heating of hydrocarbons, their viscosity is extremely and irreversibly reduced, and the heating of the rock itself (thermal conductivity) makes it possible to reduce the viscosity of hydrocarbons that move along the fluid-conducting channels located in the heated rock. This makes it possible to extract hydrocarbons with reduced viscosity, the total volume of which is several times greater than the volume of the pore space of the heated reservoir. The higher the heating temperature of the reservoir rock, the greater the amount of hydrocarbons will be extracted to the surface of the well. That is, the higher the temperature used by RAW, the more significant is the contribution of the rock thermal conductivity mechanism to oil recovery/oil displacement.

Mechanism of chemical reactions: hydrocarbons and rock enter into chemical reactions with water injected into the reservoir in the form of SCR, or superheated steam with a high degree of superheat. In this case, individual components of the rock are often catalysts for such chemical reactions. As a result of hydrothermal pyrolysis, hydrocarbons are irreversibly molecularly modified - oil becomes lighter, clay minerals are destroyed, and reservoir permeability increases. Thus, the introduction of heat into the reservoir and the implementation of chemical reactions in it with the participation of water are the two mechanisms that are the basis for increasing the efficiency of oil displacement.

Hydrodynamic Mechanism: Fluid mobility in a reservoir is largely determined by the relative permeability of the fluid or mixture thereof. So, for example, with a conventional thermal treatment based on the injection of predominantly wet steam into the reservoir at a depth of 1500 meters, the density of SATURATED steam is 613 kg/m ³ . At the same depth, the density of superheated steam with the highest degree of superheat at T=480°C is 50.2 kg/m ³ . Almost 12 times less! And this allows the injected fluid in the form of superheated steam with a high degree of superheat to penetrate further into the reservoir compared to, for example, saturated steam. The radius of the retort (heated rock), depending on the reservoir properties of the productive formation, can be increased by 10-15 meters; for comparison, the radius of conventional thermal impact under the most favorable reservoir conditions does not exceed 30 meters. Moreover, it should be taken into account that when using superheated steam with a high degree of superheating, the temperature of the retort will be much higher, which allows not only to increase the oil recovery factor, but also to improve the quality of the extracted hydrocarbons (increase their market value), which will make it possible to refuse in the future, for example, from thinning them with lighter oil for transport to refineries. Also, the heavy components of high-viscosity or heavy oil will mainly remain in the reservoir, which results in a decrease in the accumulation of oil sludge at the refinery. Enthalpy plays a significant role in the implementation of this mechanism. Thus, the enthalpy (heat content) of saturated steam at P = 15 MPa is 1592.4 kJ/kg, and that of superheated steam with the highest degree of superheat (P = 15 MPa at T = 480°C) is 3251.8 kJ/kg. It is the synergistic combination of these two factors (low density and high heat content) that is the basis for increasing the volume of the retort and reducing the number of wells and, accordingly, increasing the recovery factor, the degree of oil displacement and reducing the cost of hydrocarbon production. Note: the volume of a relatively low-temperature retort under conventional thermal treatment and a radius = 20 meters with a seam thickness = 15 meters is 18840 m ³ , and the volume of a high-temperature retort under the proposed exposure (radius 35 meters) is 57697 m ³ ; the increase in the volume of the retort is 38857 m ³ .

Basic working agents of the claimed method. In the claimed method, the basic working agents (BRA) should be understood as a coolant in the form of water in its various states, which are generated directly by the Ultra-supercritical water generator, namely: BRA-1 - subcritical water or subcritical water (DKW); BRA-2 - supercritical water or supercritical water (SCW); BRA-3 - water in the ultra-supercritical state or ultra-supercritical water (USCR) and BRA-4 - water in the form of superheated steam with a high degree of superheating (SHSW).

Diffusion

In the productive reservoir of the Bazhenov formation, due to the low permeability of its reservoirs, the movement of fluids through the fluid-conducting channels occurs mainly in the form of diffusion, and there is practically no flow of fluids in the form of filtration under the action of a pressure drop (Darcy's law). In the process of thermochemical impact on the productive formation and the impact with the use of solvents, both injected into the productive formation from the day surface of the well, and generated in the productive formation (C ₁ -C ₁₀ ) in the process of thermochemical action on it, on the one hand, the process of fluid diffusion due to a decrease in the concentration of fluids and an increase in their volume (under thermal exposure), and on the other hand, the formation of new micro-sized (thickness of 500 nm or more) main fluid-conducting channels, in which fluids move already according to the Darcy law in the form of filtration, and, into which fluids diffuse from micro (thickness up to 5 nm), meso (thickness from 5 to 50 nm) and macronano-sized (thickness from 50 to 100 nm) fluid-conducting channels. Light hydrocarbons have a greater diffusion capacity than heavy hydrocarbons, and "cold" water inhibits the diffusion of hydrocarbons through nanoscale fluid-conducting channels.

Organic acids and permeability.

During the thermochemical impact on the reservoir and, in particular, in the process of conversion ("dry" pyrolysis / hydropyrolysis) of kerogen, organic acids are formed from it (up to 2% of the total mass of kerogen; wt.%), which dissolve carbonates and aluminosilicates, which provides an increase in the intergranular permeability of the reservoir.

Carbon dioxide (CO ₂ ).

In the process of thermochemical impact on the reservoir, as a result of "dry" pyrolysis and hydropyrolysis, mainly of kerogen, a significant amount of carbon dioxide is generated, which is in the supercritical state (SC-CO ₂ ) in reservoir conditions.

So, for example, back in 1992, M. Lewan [4], studying the phenomenon of the importance of water as the reason for the higher efficiency of kerogen hydropyrolysis compared to “dry” pyrolysis, noted that as a result of subcritical (350°C) hydropyrolysis of Type II kerogen from the Woodford Formation (USA) produces a significant amount of CO ₂ . So, as a result of hydropyrolysis of 400 g of core pieces containing about 25 g of kerogen (6.25 wt.%), 0.24 mol of CO ₂ (10.5624 g) was generated. Of course, how much CO ₂ can be generated in the Bazhenov reservoir depends on many factors and in each specific case, but, in the most general form, it is possible to assume that, for example, at 10% kerogen content (S ₂ = 10 wt. %), which is not uncommon for the productive formations of the Bazhenov formation, as a result of its in-situ hydropyrolization, up to 80-90 kg of CO ₂ per 1 m ³ of the productive formation can be generated. In-situ generation of such an amount of CO ₂ is the most powerful tool in the process of reenergizing a productive formation (increasing in-situ pressure or internal energy of the formation), without which efficient and cost-effective production of hydrocarbons from the Bazhenov formation is impossible. Moreover, SC-CO ₂ dissolves in liquid hydrocarbons and at the same time they increase in volume up to 1.5 times - they swell, which enhances the reenergization of the productive formation in its in-situ retort. Complete dissolution of SC-CO ₂ in hydrocarbons is easier to achieve than dissolution in liquid hydrocarbons, for example, SC-methane (SC-CH ₄ ). Under equal reservoir conditions, methane has a higher minimum total miscibility pressure (MMP) compared to CO ₂ : at T=110°C, MTP of methane is approximately 36-37 MPa, and CO ₂ is approximately 18-19 MPa. Their density also varies greatly. At an in-situ pressure of 37 MPa and T = 110°C, the density of CO ₂ is 701 kg/m ³ , and that of methane is 165.9 kg/m ³ . This means that, occupying a smaller volume, SC-CO ₂ can be completely mixed with oil of tight formations, with little or no increase in the reservoir temperature, which, in turn, means that the complete dissolution/mixing of SC-CO ₂ can occur in macrofractures at a considerable distance from the bottom of the well, and this increases the fluidity of low-permeability oil in remote zones of the reservoir and allows it to be extracted from the most remote sections of the reservoir through a system of intensified micro, meso and macro nanofluidic channels.

In-situ solvents

In the process of thermochemical impact on the productive formation, hydrocarbon solvents from among the alkanes are generated in it from in-situ hydrocarbons, namely: С ₁ -С ₆ (methane-hexane), which dissolve oil of low-permeability rocks and heavy hydrocarbons (bituminous oil), increasing their drainage capacity (diffusion rate), the degree of mobility and, accordingly, the recoverability from the reservoir. At the same time, the effectiveness of in-situ solvents, as solvents for oil of low-permeability rocks and bituminous oil, increases with an increase in carbon number from C ₁ to C ₆ (from methane to hexane).

WIADAP liquid

To implement the claimed invention, "WIADAP liquid" is used, which is water treated according to WIADAP technology. This technology is based on the treatment of water by a cold plasma glow discharge, which is initiated in a high vacuum in an atmosphere of residual gases at a potential difference on the electrodes in the range of 2000-3500 Volts. As a result of such a discharge, a highly ionized medium is formed in the “water-plasma” boundary layer, high voltage drops are initiated in this medium, due to which changes in the structure of water occur. It is known that water is by its nature heterogeneous and consists of clusters. Water cluster - a set of water molecules interconnected by hydrogen bonds. The smaller the cluster size, the higher the permeability of water. Exposure of water to a plasma discharge during its processing in accordance with the WIADAP technology makes it possible to reduce the size of such clusters to a nano-structure, and such a structure is stable for 6 months. This fact is significant, since the thickness of the nanopores of the productive formation of the Bazhenov formation, on average, varies from 10 to 50 nm. As a result of water treatment using WIADAP technology, free radicals, including oxygen and hydrogen groups, are almost completely removed from it. In addition, such treatment purifies water from free radicals and heavy isotopes (which cannot be achieved by purification using existing water filtration technologies) and gives it a nanocluster structure (less than 2 nanometers), which greatly increases the ability of such treated water to penetrate into various nanostructured volumes, what the reservoir is, and contributes to the dissolution of various deposits, fats and salts located in them. The water treated in this way was called "WIADAP liquid". It is very important that the water treated according to the WIADAP technology effectively flushes and breaks down (leads to biodegradation) fats and oil products, which makes it possible to use it for flushing/cleaning the channels of a productive oil-kerogen-containing formation.

Nanohydrothermal fracturing of a productive formation. In the claimed group of inventions, as a result of cyclic thermochemical action, a combined high-temperature high-pressure retort is formed in the reservoir, the temperature in which can reach 400-500°C. When relatively “cold” water is injected into the reservoir in the form of either water or WIADAP fluid, such cold water quickly heats up and its volume increases many times over. So, for example, at T = 50°C and P = 40 MPa, the density of water (WIADAP liquid) is 1004 kg/m ³ , and at T = 500°C, the density of water is 178 kg/m ³ . An explosive increase in the volume of water or WIADAP fluid (in this case, by 5.64 times) leads to the rupture of the fluid-conducting channels of the productive formation at the nanolevel and on one linear meter of the formation vertically, depending on its porosity and permeability properties (RP), it can occur from 1 to 10 thousand nanohydrothermal fractures, which significantly increases the permeability of the reservoir and its ability to accept RAS in large quantities. In the claimed group of inventions, the implementation of nanohydrothermal fracturing precedes the subsequent flooding of the productive formation with a pseudo-supercritical fluid and increases its efficiency by increasing the permeability of the wellbore zone of the productive formation.

Flooding of a productive formation with pseudo-supercritical fluid.

During the implementation of the third stage of the claimed method, relatively “cold” water is injected into the combined in-situ retort, as a result of which, at first, a nanohydrothermal fracturing of the productive formation is carried out, and in the course of further injection of “cold” water into the productive formation, some of it quickly transforms into WW - water and, mixing with in-situ fluids (VTH, C ₁ -C ₁₀ , hydrocarbon solvents, CO ₂ , etc.), forms a pseudo-supercritical fluid front of VTH displacement towards production wells. This pseudo-supercritical fluid displacement front in the form of a pseudo-supercritical displacement working agent is followed by a transient water front and then a transient mixed fluid displacement front, the density of which increases with distance from the pseudo-supercritical fluid front. At the same time, due to the fact that a high level of in-situ pressure is constantly maintained in the combined in-situ retort (continuous injection of relatively “cold” water into the reservoir), the permeability of the formation of the combined in-situ retort, even when it (the retort) cools down, does not significantly decrease and the displacement of the target of the product is carried out through reservoir zones with increased permeability.

The essence of the claimed invention is illustrated by graphic materials, on which:

- in Fig. 1 is a diagram of a cluster of three horizontal wells with hydraulic fracturing performed in their horizontal sections;

- in Fig. 2 - scheme of the equipped horizontal well in the initial state;

- in Fig. 3 is a diagram of an equipped horizontal well in the process of injection of RAS into a productive formation for thermochemical treatment;

- in Fig. 4 is a diagram of the configuration of the technological complex used to implement the first stage of the method;

- in Fig. 5 is a diagram of the configuration of the technological complex used to implement the second stage of the method;

- in Fig. 6 is a diagram of the configuration of the technological complex used for the implementation of the third stage of the method;

- in Fig. 7 is a diagram of the implementation of the second stage of the method;

- in Fig. 8 is a diagram of the implementation of the third step of the method.

To implement the method, at least one cluster of standard horizontal wells 1 (Fig. 1) is drilled in the amount of, for example, three, each of which has a vertical section 5 and an associated horizontal section 2, which schematically shows the zone of the hydraulic fracturing 3. Horizontal section 2 of each well 1 is located in the zone of the productive formation 4.

In principle, directional wells can also be used to implement the method.

The vertical section 5 of each of the wells 1 (Fig. 2, Fig. 3) of the cluster is equipped with a string of standard casing pipes 6, each of which is made in a known manner, for example, from an inner thick-walled pipe 7 with a heat-insulating coating (TYPE) 8, closed by an outer shell 9 .

As TYPE 8 casing pipes 6 can be used liquid thermal insulation, for example, TERMION-VULKAN or AKTERM-VULKAN. Such liquid thermal insulation retains its properties at temperatures up to 600°C. It is applied to the pipe surface in layers, with a layer thickness of 0.5 mm, with an interlayer drying of 24 hours, until the coating thickness is from 5 to 15 mm. After complete drying, the TYPE pipe can be used for a long time in the temperature range from -50°С to +600°С.

As a material TIP can be used ultrafine basalt fiber having a diameter of 0.5 to 3.5 microns or microporous material "MICROTHERM" made of pyrogenic silicon dioxide and having an initial density of 320 kg/m ³ . The TIP made of these materials is able to maintain its performance at temperatures up to 1150°C.

At the mouth of each well 1, the casing string 6 is fixed by the X-mas tree 10, and at the bottom of the well 1, a pipe 12 without TIP is connected to the casing string 6 through the coupling 11, which is fixed in the compensator 13 for thermobaric changes in the length of the casing pipes. The compensator 13 is fixed to the casing 14 located in the cement stone 15 formed on the rock 16. In principle, the compensator can be installed almost anywhere in the casing string. Several compensators can be installed in the column.

The refusal during the construction and operation of wells from tubing used in the closest analogue for pumping RAS into the reservoir and selecting the target product from it is a significant feature of the claimed method and is due to the need to deliver a significant amount of RAS to the bottom of the well into the reservoir (from 100 to 200 tons per hour), for which, in order to reduce the time of injection of RAW into the reservoir and reduce hydraulic losses, casing pipes with TIP were used, having a relatively large diameter at the bottom of the well - up to 245 mm. This requirement is fully met by casing pipes with TIP, mounted in a string in each well of the cluster.

The claimed method is carried out in three stages using a technological complex.

To implement the first stage of the claimed method, the configuration (Fig. 4) of the technological complex is used, including a container 17 for a hydrocarbon solvent (RAV No. 1), to which a high-pressure pump 18 is connected to pump the solvent 19 into the reservoir 4 through the casing string 6 from the tank 17.

To implement the second stage of the claimed method, the configuration (Fig. 5) of the technological complex is used, including a water treatment unit 20 connected by an outlet to a tank 21 for prepared water, which is supplied from the tank by a high-pressure pump 22 to a ground generator 23 of ultra-supercritical water, the output of which is connected with the first input of the reactor 24 for the oxidation of microsized metal particles (aluminum, iron, zinc or mixtures thereof in any possible proportions), the second input of which is connected to the output of the container 25 for a colloidal aqueous solution of microsized metal particles. A pump 26 is built into the line connecting the reactor 24 and the tank 25 for pumping a colloidal aqueous solution of microsized metal particles into the oxidation reactor 24. To implement the second stage of the method, RAV No. 2 (pos. 27) and RAV No. 3 (pos. 28) are used.

To implement the third stage of the claimed method, the configuration (Fig. 6) of the technological complex is used, including a water treatment unit 20, the output associated with a container 29 for treated water and / or WIADAP liquid, which pump 30 as a component 31 has the ability to pump into the reservoir 4 along casing string 6.

The required, depending on the stage of the implemented method, the configuration of the technological complex is provided in a known way, through the use of shut-off and control valves.

The technological complex is composed of well-known blocks, assemblies, assemblies, as well as control and measuring equipment, which are operated for their intended purpose.

To implement the method, the following RAVs are used.

Working agents of influence. Under the working agents of the impact of the claimed method should be understood working agents that are directly injected into the reservoir.

RAV No. 1. This RAS is a hydrocarbon solvent from the groups: (1) aromatic solvents (benzene, toluene, solvent, etc.); (2) chlorine-substituted hydrocarbons (chloroform (trichloromethane), carbon tetrachloride, etc.); (3) hydroaromatic solvents (tetralin, decalin, etc.).

RAV No. 2. This RAW is water in a supercritical state with the following parameters when injected into a productive formation: Τ = 480°C; Ρ up to 60 MPa; enthalpy - 2415 kJ/kg.

RAV No. 3. This RAW is supercritical water saturated with nanosized particles of metal oxides, mainly aluminum oxide (Al ₂ O ₃ ), iron oxide (FeO, Fe ₂ O ₃ , Fe ₃ O ₄ ) or zinc oxide (ZnO), and hydrogen.

RAV No. 4. This RAB is a subcritical WIADAP fluid.

RAV No. 5. This RAW is prepared (purified) water in a subcritical state, which, when injected into a productive formation, has a temperature of 40 to 120°C at a pressure of up to 100 MPa.

To implement the claimed method, other ARBs based on ARBs can be used, the use of which can increase the efficiency of the claimed method.

The claimed method, using the above technological complex and RAV, is carried out in three stages as follows.

Implementation of the first stage of the claimed method begins with hydraulic fracturing on the horizontal section of each well 1 pad. A fairly wide range of working agents (media), for example, methanol, LPG, mainly propane and butane, can be used to carry out OHRP.

The process of EMG itself is well known to those skilled in the art and need not be described in detail in this application. OGRP is implemented using the configuration of the technological complex shown in Fig. 4.

As a result of hydraulic fracturing, in the productive formation 4 in the zone of horizontal sections 2 of each well, ΜΕΓΑ cracks 3 are formed, the total surface area of each of which is from 1000 to 10000 m ² .

The presence of cracks in the reservoir after hydraulic fracturing ΜΕΓΑ allows obtaining a significant area of the exposed reservoir in the rock of the near-wellbore zone of each well, and, consequently, to ensure the injection of a large amount of RAS into it - from 100 to 1000 tons per hour, which is very important for achieving the specified technical result.

After the completion of the hydraulic fracturing from the productive formation 4 in the flowing mode, from all wells of the 1st cluster, the selection of the target product is started, which includes the working medium used for the hydraulic fracturing and NPP (S ₁ ). The selection is stopped when the in-situ pressure in the productive formation 4 decreases, practically, to the level of hydrostatic pressure, but always above it. This makes it possible to prevent the process of compaction of the reservoir 4, which begins immediately after the in-situ pressure in the reservoir 4 becomes below the level of hydrostatic pressure.

In the Bazhenov (and Domanik) suite, an increase or decrease in the permeability of a productive formation occurs exclusively at the nanoscale. It is at the nanolevel that the fluid-conducting channels increase or decrease and new porosity is formed, as well as the integration of individual, previously closed pores or fluid-conducting channels, into a single fluid-conducting system.

After completion of the selection from the reservoir 4 of the target product, they start pumping from the tank 17 with a high-pressure pump 18 into the reservoir 4 of all horizontal wells 1 RAV No. 1, pos. 19.

RAW No. 1 is used for impregnation of the near-wellbore zone of a productive formation and dissolution of micro- and nano-sized layers of bitumoid of a sheeted productive formation, consisting mainly of resins and asphaltenes, as well as for the formation of subhorizontal and, in part, subvertical main fluid-conducting channels necessary for intensifying injection at the following stages into the productive formation RAV and the selection of the target product from it.

Depending on the reservoir properties of the productive formation 4, injection into it through the casing string 6 RAW No. 1 19 is carried out for 1 hour to 24 hours, after which the injection of RAW No. 1 into the productive formation 4 is completed and the productive formation 4 is impregnated.

In the process of impregnation, as already noted above, the dissolution of micro and nanoscale layers of bitumoid, consisting mainly of resins and asphaltenes, which cement the sheeted productive formation, is carried out. After completion of impregnation, which can last several days, depending on the quality of the bitumen (chemical composition, etc.) and reservoir properties. On average, the impregnation time is 48 hours. After the impregnation is completed, the target product is taken from the productive formation 4 in the well flowing mode - an emulsion consisting of water, liquid / gaseous hydrocarbons, including dissolved resins and asphaltenes, as well as RAV No. 1. The selection of the target product is carried out until the pressure in the reservoir drops to a pressure level that is 2-3 MPa higher than the level of hydrostatic pressure, after which the selection of the target product is stopped and the second stage of the method is started.

As a result of the implementation of the first stage of the method in the rock of the productive formation, at each horizontal section of the well, after the hydraulic fracturing, impregnation and selection of the target product, a near-wellbore zone with increased permeability was formed due to the formation of ΜΕΓΑ cracks and the formation of an extensive network of fluid-conducting channels due to the dissolution of micro- and nano-sized bitumen layers , which makes it possible to ensure that a significant amount of RAS is pumped into the formed zone at the next stages of the method. Removal of the target product after hydraulic fracturing and impregnation makes it possible to produce hydrocarbons already at the first stage, as well as to increase the efficiency of the action of RAS injected into the reservoir at the next stages of the method.

The second stage of the method is carried out in several cycles. Each of the cycles includes injection of RAW #2 and RAW #3 into each well.

For the preparation of RAW No. 2, industrial water is supplied (Fig. 5) to the water treatment unit 20, in which water is purified from contaminants and mechanical impurities using standard mechanical filtration means, it is softened using reverse osmosis and ultrafiltration. Fine mechanical water purification - removal of various undissolved suspensions from water, is carried out by industrial multi-cartridge filters with washing titanium membranes. The fineness of cleaning is up to 0.1 microns. If necessary, iron and manganese components are removed from the water, as well as its degassing.

From the water treatment unit 20, the prepared water enters the storage tank 21, from which a high-pressure pump 22 (up to 80 MPa) is supplied to the ground-based USK-water generator 23. To implement the claimed method, either one ground-based USK-water generator 23 is used, having a capacity of up to 200 tons of USK-water per hour, or several parallel-arranged ground-based USK-water generators with a total capacity of up to 200 tons of USK-water per hour. This is explained by the fact that for an effective thermochemical impact on the productive formation, it is necessary to pump specifically per 1 m ² of the exposed surface of the productive formation, preferably up to 50 kg of USC-water per hour, but not less than 15 kg of USC-water per hour. With a decrease in the value of specific injection per 1 m ² of the exposed surface of the productive formation below 15 kg of SC-water per hour, the heating time of the in-situ retort significantly increases, the volume of which, for example, for the Bazhenov formation, ranges from 150 to 210 thousand m ³ for one well 1, and, on average, 180 thousand m ³ . With an open porosity, on average, for a productive formation of the Bazhenov formation, equal to 6%, the injected working agent in the form of SC-water (for example, at P = 40 MPa and T = 435°C, the density of SC-water = 336 kg / m ³ ) will penetrate into productive formation 4 to a depth of 1 meter (for a fracture having 3000 m ² ) in 33 minutes of injection of RAV No. 2 into productive formation 4.

The ground-based USK-water generator generates USK-water, which has the following limiting thermobaric characteristics: Τ up to 700 ° C and P up to 70 MPa (density (p) - 190.4 kg / m ³ ; enthalpy - 3490 kJ / kg USK-water ).

In the process of delivering USC-water to the bottomhole, which was generated by a ground-based USC-water generator, due to temperature transport losses, the temperature of USC-water decreases, and due to hydraulic losses due to friction, its pressure drops, as a result of which USC-water is transformed into SC- water (RAV No. 2) having Τ up to 480 ° C at Ρ up to 60 MPa (density (p) - 390 kg / m ³ ; enthalpy - 2415 kJ / kg USK-water). RAV No. 2 27 penetrates into the reservoir 4 through ΜΕΓΑ cracks 3 and fluid-conducting channels formed in the reservoir at the first stage.

RAW No. 2 is used to increase permeability and introduce enthalpy/heat content into the reservoir to partially improve the quality of the NPP (S ₁ ) and generate synthetic/technogenic oil from kerogen and bituminous oil/bitumoids (S ₂ ) and, accordingly, the formation of VTN in the reservoir .

Injection of RAV No. 2 is carried out for a long time; from several hours (at the beginning of the second stage) to several days (at the end of the second stage). With each new cycle, the duration of injection of RAW No. 2 into the reservoir increases, as the in-situ retort grows, - an increase in its volume and, accordingly, an increase in the void volume of the fluid-conducting channels of the in-situ retort; therefore, with each new cycle, to fill the RAW No. 2 of the increasing void volume of the fluid-conducting channels of the in-situ retort, an increasing volume of RAW No. 2 is required for its injection into the productive formation, which, in turn, requires more time.

When the second stage is carried out in the reservoir, first in the near-wellbore zone of each well, and then in more remote zones of the reservoir, the process of formation of an in-situ high-temperature retort takes place, in which, in addition to the naturally present NPP, synthetic hydrocarbons are generated due to the following processes: (1 ) "dry" and hydropyrolysis of kerogen, as a result of which liquid hydrocarbons (synthetic oil) and synthetic gas (syngas) are generated from kerogen, consisting mainly of H ₂ , CH ₄ , CO ₂ and CO, as well as organic acids (up to 2 % by weight of kerogen); (2) thermal cracking, catalytic cracking (in the presence of introduced or natural in-situ catalysts/rock) and hydrocracking (in the presence of introduced or generated in-situ H ₂ ) hydrocarbons (including bituminous oil) - partial improvement of their quality; (3) multiple auto-fluid fracturing associated with an increase in the volume of in-situ fluids (as a result of their thermal expansion and an increase in intergranular bursting pressure (P _p ) and a decrease in sealing pressure (P _y )), partial gasification of liquid hydrocarbons, as well as in-situ molecular modification of kerogen and generating synthetic oil and syngas from it (substances generated from kerogen have a volume 30% larger than the volume of kerogen itself). All this leads to an increase in the amount of WTH generated in each retort, as well as to a significant increase in the porosity and permeability of the productive formation 4 and its reenergization (increased in-situ pressure (P _pl )).

After the in-situ pressure reaches a predetermined value during the injection of RAW No. 2, the value of which largely depends on the ability of the ultra-supercritical water generator to generate a high-temperature base working agent of high pressure and reservoir properties, which, using the Bazhenov reservoir as an example, occurs at a depth of 3000 meters is 40-45 MPa, injection of RAV No. 2 into the productive formation 4 is stopped and injection of RAV No. 3 into each well is started.

RAW No. 3 is used for (a) clogging the most permeable reservoir units with subsequent leveling of the RAW injection front in the productive reservoir, (b) partial improvement of the quality of in-situ hydrocarbons due to the implementation of catalytic cracking and hydrocracking processes in the reservoir, and also (c) in as a nanoproppant for expanding fluid-conducting channels at the nanolevel and slowing down the process of compaction of the productive formation during the selection of the WTH from it in the well flowing mode.

For the preparation of RAW No. 3, process water is supplied to the water treatment unit 20. Further, from the water treatment unit 20, the prepared water enters the tank for the prepared water 21, from which the high pressure pump 22 (up to 80 MPa) is supplied to the ground-based USK-water generator 23. Ground-based generator USK-water generates USK-water, which enters the reactor for the oxidation of microsized metal particles (aluminum, iron, zinc, or their mixtures in any possible proportions) 24. Simultaneously, from a container for a colloidal aqueous solution of microsized metal particles 25, pump 26 periodically in a pulsed mode in batches pumps a colloidal aqueous solution of microsized metal particles into the reactor for the oxidation of microsized metal particles 24, in which an exothermic oxidation reaction of microsized metal particles in USC-water is carried out - the synthesis of nanosized particles of metal oxides in USC-water, which is accompanied by hydrogen generation and heat release.

Thus, in the reactor for the oxidation of microsized metal particles USK-water is saturated with both nanosized particles of metal oxides and hydrogen, and is delivered through the casing string 6 to the bottom of each well 1 into the formed retort. In the process of delivery of USC-water saturated with nanosized metal particles and hydrogen to the bottomhole, due to temperature transport losses, its temperature decreases, and due to hydraulic losses due to friction, its pressure drops, as a result of which USC-water saturated with nanosized particles of metal oxides and hydrogen transforms into SC water saturated with nanosized particles of metal oxides, mainly aluminum oxide (А1 ₂ О ₃ ), iron oxide (FeO, Fe ₂ O ₃ , Fe ₃ O ₄ ) or zinc oxide (ZnO) and hydrogen (РАВ No. 3 ), having Τ up to 480 ° C at Ρ up to 60 MPa (density (p) - 390 kg / m ³ ; enthalpy - 2415 kJ / kg USK-water). Next, RAV No. 3 28 is injected into the productive formation 4.

Injection of RAV No. 3 is carried out until the in-situ value on the example of the Bazhenov reservoir, deposited at a depth of 3000 meters, reaches the maximum possible values - 55-60 MPa.

After completion of pumping RAW No. 3, selection from all wells of the cluster through casing strings 6 of the target product in the form of a water-oil emulsion saturated with hydrocarbon and non-hydrocarbon gases is started, which is carried out in the well flowing mode. After each such cycle carried out, the volume of the near-wellbore retort of each well increases.

The cyclic thermochemical impact on the productive formation continues to be carried out using RAV No. 2 and RAV No. 3 until the in-situ retorts 32, 33, 34 of wells 1 merge into one combined high-temperature in-situ retort 35 (Fig. 7), after which they begin to implement the third stage of the claimed way.

To determine the optimal distance between wells and the retort merging time, mathematical models of the process of thermochemical impact on productive formations are used, which are known to specialists and are not the subject of the claimed method.

The duration of cycles of thermochemical treatment and their number depend on the FES of the productive formation, on the stages of catagenesis, the degree of maturity of kerogen and, accordingly, the value of its residual oil generation potential. So, for example, if the degree of maturity of kerogen corresponds to the initial stages of transformation (PK-3 or MK-1), then the maximum amount of liquid and gaseous hydrocarbons from such kerogen can be obtained in 10 hours of thermochemical exposure and the selection of the target product can begin, and if the degree of maturity of kerogen corresponds to the later stages of transformation (MK-2 or MK-3), then the maximum amount of liquid and gaseous hydrocarbons from such kerogen can be obtained in 48 hours of thermochemical exposure and the selection of the target product can begin. In both cases, the oil generation potential of kerogen is realized by 95% as a result of thermochemical action [8].

To implement the third stage of the method, at least one well 1 of the cluster, for example, the central one, if the cluster consists of three wells having a linear relative arrangement, is transferred to the injection mode of operation, and the two outer ones - to the production wells mode.

It should be noted that as a result of the second stage of the method, the porosity of the reservoir increases, and in the case of using RAW No. 4 and 5 during the third stage, the combined in-situ retort is also cooled, however, compactions of the productive reservoir in the area of the combined in-situ retort during the third stage does not occur due to the fact that initially relatively "cold" RAW No. 4 and 5 are pumped into the reservoir under pressure, which is much higher than the hydrostatic pressure (by 20-30 MPa), while forming in the reservoir of the cooling combined in-situ retort, the displacement front of the target product with high bursting pressure. It is also very significant that during the implementation of the third stage of the claimed method, the reservoir is less susceptible to compaction due to the fact that during the implementation of the second stage of the claimed method, kerogen is pyrolized and, accordingly, synthetic hydrocarbons are generated. As a result of laboratory studies, it was found that after pyrolization of kerogen, the value of the elastic modulus of pyrolized cores of the productive formation increases depending on the degree of concentration of kerogen and clay in the rock, but, on average, from 1.5 to 2.5 times (for example, before pyrolization, the modulus of elasticity was equal to 6 GPa, and after pyrolysis - 13 GPa). As a result, the strength of the productive formation after pyrolization of the kerogen contained in it increases [5] and, thus, the productive formation after pyrolization of kerogen is less prone to compaction than the same productive formation before pyrolization of kerogen.

To implement the third stage, RAV No. 4 is initially injected through the casing string 6 of the injection well in the form of WIADAP fluid, which is carried out for several hours to form a volume with increased permeability in the near-wellbore zone due to the implementation of nanohydrothermal fracturing.

It should be noted that after completion of the second stage of the process, the temperature of the combined in-situ retort is approximately 480°C, and the temperature injected into the combined retort RAB No. 4 is from 40 to 120°C. When RAW No. 4 enters the productive formation 4, practically instantly heating up to a temperature, for example, 420 ° C (the density of RAW No. 4 at this temperature is 423 kg/m ³ ), it passes from the subcritical state to the supercritical state, explosively increasing in volume , in this case, 2.3 times. Such an explosive increase in the volume of WIADAP fluid leads to the rupture of the fluid-conducting channels of the productive formation at the nanolevel and, depending on its reservoir properties, up to 10,000 nanohydrothermal fractures occur per linear meter of the formation vertically, which significantly increases the permeability of the productive formation. Moreover, RAW No. 4, having a nanoscale structure of its water cluster, has an increased penetrating ability into nanosized fluid-conducting channels of a productive formation, as well as an increased ability to split/dissolve hydrocarbons.

RAV No. 4 during the implementation of the third stage of the claimed method, heating up in the productive formation of the combined in-situ retort, goes into a supercritical state, and then enters into/becomes part of the pseudo-supercritical fluid displacement front of the target product.

After the implementation of nanohydrothermal fracturing of the productive formation using RAW No. 4 in the area of the combined retort 35, through the injection well, RAW No. 5 is pumped - water, which, when it is pumped into the retort 35, has a temperature of 40 to 120 ° C at a pressure that is mainly at 20-30 MPa higher than hydrostatic, but can reach 70 MPa for the Bazhenov reservoir, located at a depth of 3000 meters.

As a result, a fluid is formed in the reservoir 4 in the combined in-situ retort 35 to displace the target product, and the fluid can be conditionally divided by its temperature into three fronts: (a) having a supercritical temperature (above 374°C) - pseudo-supercritical product 36; (b) having a subcritical temperature (below 374°C, but above 200°C) - transient water front 37, which follows the pseudo-supercritical displacement front 36 and (c) having a temperature below 200°C - transient mixed fluid front 38.

All together they form a pseudo-supercritical fluid, which moves frontally from the injection well in direction 39 (Fig.8) to the production wells along the productive formation 4 of the combined in-situ retort 35, which has increased permeability and porosity, inside which the supercritical fluid medium dominates, one of the main components of which is water in the supercritical state. The pseudo-supercritical front of the fluid injected through the injection well ensures the displacement of the target product from the combined retort to the surface through the production wells.

3-4 well clusters can be placed on the site. A well pad is usually equipped with a heat recuperator (not shown in the figure), into which, after extraction to the daylight surface, both during the implementation of the second stage of the claimed method and during the implementation of the third stage of the claimed method, a high-temperature water-oil emulsion is supplied for preliminary heating of water, which then enters the USK ground-based generator - water 23.

At the end of the third stage, the hydrocarbon production process is completed, the maximum possible amount of hydrocarbons has been extracted from the reservoir, both in liquid and gaseous states. ORF can be up to 70%, and without the implementation of the third stage, the value of ORF cannot be higher than 45-50%.

After completion of production, well 1 undergoes liquidation.

New in the claimed invention, in relation to the closest analogue and providing the specified technical result is that:

- before the cyclic thermochemical treatment (the second stage of the method), the productive formation is prepared (the first stage of the method) for the adoption of a relatively large amount of RAS. To do this, hydraulic fracturing is carried out, followed by impregnation of near-wellbore zones of the productive formation to dissolve its bitumen layers. The implementation of the first stage makes it possible to form a powerful system of fluid-conducting channels in the near-wellbore zones of the productive formation for pumping a large volume of RAW, and, consequently, to increase the oil recovery factor, compared to the closest analogue, by approximately 5-8%;

- the use of cyclic thermochemical impact on the productive formation allows for in-situ partial improvement of the quality of mobile hydrocarbons and to generate synthetic oil and gas from bituminous oil and kerogen; form and combine in-situ retorts and select from the productive formation most of the hydrocarbons in the form of WTH and hydrocarbon gases;

- during the second stage, a significant amount of heat is introduced into the reservoir, and as a result of the second stage, a high-temperature retort is formed in the reservoir, which, in fact, is an artificial geothermal thermal energy storage (rock and fluids heated to high temperatures). During the implementation of the third stage, a significant amount of heat (25-30%), from the previously introduced during the implementation of the second stage, will be taken into the productive formation together with the hot HPP and recuperated/utilized on the day surface of the well, which significantly increases the energy efficiency of the proposed method;

- the use of WIADAP fluid (PAW No. 4) allows, before the pseudo-supercritical front begins to displace the target product to the day surface through production wells, to carry out nanohydrothermal fracturing of the productive formation in the largest near-wellbore volume of the productive formation due to the higher penetrating ability of the WIADAP fluid compared to water, which significantly increases the permeability of the retort in its near-wellbore area at the nanolevel, and, therefore, allows to provide (a) the maximum possible volume of RAV No. 5 intake by the formation and, accordingly, (b) the highest possible recovery factor as a result of the implementation of the third stage of the method; - the use of a pseudo-supercritical displacement front to displace the EHP from the reservoir makes it possible to displace the maximum possible amount of EHP from the reservoir and provide an oil recovery factor of up to 70%;

- extraction of RAS from the productive formation to the daylight surface after each stage (cycle) makes it possible to ensure, after appropriate cleaning, their reuse, as well as to create optimal conditions for the action of RAS injected into the productive formation at the following stages;

- the use of casing pipes instead of tubing for the implementation of the method makes it possible to deliver a significant amount of RAW (up to 200 tons per hour) to the productive formation without significant hydraulic friction losses, as well as to effectively select the target product to the surface.

The foregoing allows for accelerated, highly efficient and cost-effective commercial development of productive formations, while providing the highest level of (a) recovery factor for low-mobility and mobile hydrocarbons (for natural bitumen, high-viscosity and heavy oil) (b) recovery factor for gas hydrates and (c) recovery factor for HTH (for the Bazhenov and Domanik suites).

From an economic point of view, the claimed accelerated method for the development of HRD makes it possible to reduce the cost of hydrocarbon production. So, for example, to develop ^an in-situ retort (using the example of the Bazhenov formation), which has a volume of 192 thousand m it takes 76 days to pump 100 tons of RAV into it per hour, and the cost of production of 1 barrel of VTN is 1938 rubles. (21% lower).

Naturally, the claimed method can be used not only for the development of oil-kerogen-containing formations of the Bazhenov and / or Domanik formations, but also for the extraction of natural bitumen, heavy and high-viscosity oils, as well as gas hydrates from productive formations, a wide range of deposits occurring at depths from 100 to 6000 meters.

Information sources

[1] PART II: North America Tight Oil - Economics and Fiscal Competitiveness. Play Economics and Supply Prices. RODGERS. Oil and Gas Consulting. April 4, 2013

[2] ND Monthly Bakken* Oil Production Statistics. * Includes Bakken, Sanish, Three Forks, and Bakken/Three Forks Pools. August, 2020. https://www.dmr.nd.gov/oilgas/stats/historicalbakkenoilstats.pdf

[3] A.M. Brekhuntsov, I.I. Nesterov (2010), OAO RN Yuganskneftegaz.

[4] Water as a source of hydrogen and oxygen in petroleum formation by hydrous pyrolysis. Lewan, M. D. Am. Chem. soc. Div. fuel chem. 37, 1643-1649. 1992.

[5] EFFECT OF THERMAL MATURITY ON NANOMECHANICAL PROPERTIES AND POROSITY IN ORGANIC RICH SHALES (A BAKKEN SHALE CASE STUDY). Saeed Zargari. A thesis submitted to the Faculty and the Board of Trustees of the Colorado School of Mines in partial fulfillment of the requirements for the degree of Doctor of Philosophy (Petroleum Engineering). 2015.

[6] Unconventional Fracturing Fluids: What, Where and Why. D.V. Satya Gupta. Tomball Technology Center. 2010 Baker Hughes Incorporated.

[7] LPG for hydraulic fracturing. Development of unconventional hydrocarbon reserves using hydraulic fracturing technology using liquefied hydrocarbon gases as fracturing fluids. Neftegaz.ru. June 28, 2019 https://magazine.neftegaz.ru/articles/dobycha/456276-sug-dlya-grp-razrabotka-netraditsionnykh-zapasov-uglevodorodov-pri-pomoshchi-tekhnologii-grp-s-prime/

[8] OBTAINING OIL OF DIFFERENT COMPOSITION FROM ORGANIC MATTER OF THE BAZHENOV FORMATION. Kalmykov A.G. Bychkov A.Yu. Kalmykov G.A. "New Ideas in the Geology of Oil and Gas-2017". Moscow State University named after M.V. Lomonosov, May 25-26, 2017

[9] Structure and generation potential of the Bazhenov formation in the territory of the Central part of Western Siberia. V.A. Volkov, E.V. Oleinik, E.E. Oksenoid and A.A. Sidorov. Scientific and Analytical Center for Rational Subsoil Use named after IN AND. Shpilman. Tyumen. Geology and mineral resources of Siberia. №3 (27) 2016

[10] Benchmarking of Steamflood Field Projects in Light/Medium Crude Oils". Alfredo Perez-Perez et al. 2001.

[11] Steamflooding As an Alternative EOR Process for Light Oil Reservoirs. Edward J. Hanzlik 1981.

Claims (2)

1. A method for developing deposits of hard-to-recover hydrocarbons, including well equipment, preparation of working agents of influence and their phased injection into the near-wellbore zone of the productive formation, the method being carried out in three stages, the first of which is the stage of formation of a near-wellbore volume with increased permeability in the productive formation, and the second - cyclic thermochemical impact on the productive formation by working agents in the form of superheated steam with a high degree of superheating, subcritical water, supercritical water and / or ultra-supercritical water, with the selection of the target product at each stage on the daily surface of the well in the well flowing mode, characterized in that that to implement the method, a cluster of horizontal wells is used, the horizontal sections of which are located in the zone of the productive formation, the supply of working agents to the productive formation and the selection of the target product from it is carried out through a casing string with a heat-insulating coating, which equip the vertical section of each well, to implement the first stage in the horizontal section of each well, a one-stage hydraulic fracturing of the productive formation is carried out, followed by the selection of the target product - tight oil and the working medium used for hydraulic fracturing, after which the working agent is pumped into the volume formed in the productive formation with increased permeability of each well in in the form of a hydrocarbon solvent, followed by impregnation of the near-wellbore volume of the productive formation with the solvent and selection of the target product in the form of water, liquid and gaseous hydrocarbons, including dissolved resins and asphaltenes, as well as a hydrocarbon solvent, after which they proceed to the second stage, which is carried out cyclically, for several repeated cycles, during which a near-wellbore retort is formed in the near-wellbore volume of each well and its volume is increased with each next cycle, each of the cycles of the second stage includes pumping the working agent in the form of water into the wells, with a temperature of 374°C to 593°C at a pressure of 22.1 MPa to 70 MPa, and then a working agent in the form of water, temperature from 374°C to 593°C at a pressure of 22.1 MPa to 70 MPa, saturated with nanosized particles of metal oxides and hydrogen, followed by selection from all wells of the target product in the form of a water-oil emulsion saturated with hydrocarbon and non-hydrocarbon gases, and cyclic exposure is carried out until the retorts of the wells merge into a combined retort, after which the third stage of the method is started, for which at least one well is transferred to the injection mode work, and the rest - into the production one, through at least one injection well, the working agent is pumped in the form of a WIADAP liquid, nanohydrothermal fracturing is carried out, after which the working agent is pumped into the combined retort in the form of water, with a temperature of 40 to 120 ° C at a pressure of 1-10 MPa higher than the hydrostatic pressure or the pressure in the retort, by means of which the target product is displaced from the combined in-situ retort to the day surface through the production wells in the form of a water-oil emulsion. 2. The method according to claim 1, characterized in that nanosized particles of aluminum oxide (Al ₂ O ₃ ) or iron oxide (FeO, Fe ₂ O ₃ , Fe ₃ O ₄ ) are used to saturate the working agent with nanosized particles of metal oxides, or zinc oxide (ZnO) synthesized in an ultra-supercritical water generator oxidation reactor.

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