Method for extracting unconventional oil and complex for the implementation thereof
The thermal method with a supercritical water cloud in interconnected wells enhances unconventional oil extraction by increasing ORF and reducing environmental impact through efficient hydrocarbon dissolution and waste recycling.
Patent Information
- Authority / Receiving Office
- WO · WO
- Patent Type
- Applications
- Current Assignee / Owner
- PASHKIN ANTON SERGEEVICH
- Filing Date
- 2024-12-26
- Publication Date
- 2026-07-02
Smart Images
Figure RU2024000390_02072026_PF_FP_ABST
Abstract
Description
[0001] Thermal method for extracting unconventional oil from deep formations and a technological complex for its implementation
[0002] IRO / R Authors: Pashkin Sergey Vasilrovich Anton^Sergeevich ii^lexandrovich
[0003] IPC (2021): B 43 / 24; E21B 47 / 00
[0004]
[0005] Description of the invention
[0006] The invention relates to the oil industry, specifically to the extraction of unconventional, high-viscosity, and heavy oil from deep reservoirs. The method and device significantly increase the oil recovery factor (ORF) from deep formations and treat large areas of complex oil-bearing deposits while minimizing environmental pollution from industrial waste.
[0007] Currently, carbon-based fossil fuels are the main primary energy resource for humanity and the main feedstock for the petrochemical industry.
[0008] Fossil fuels can exist in a solid state – coal, kerogen, oil shale, etc.; in a liquid state – conventional and unconventional oil; and in a gaseous state – natural gas methane. The differences between the aggregate states of fossil fuels are primarily rooted in the hydrogen-to-carbon ratio (H:C) in their molecules: 0-0.5 in coal, up to approximately 2 in liquid hydrocarbons, and up to 4 in methane gas.
[0009] The most in-demand hydrocarbons in the energy and petrochemical industries are those in liquid and gaseous form—traditional oil and natural gas. They are also the easiest to extract. However, their reserves are rapidly depleting, and according to the International Energy Agency (IEA), liquid hydrocarbon production from conventional reservoirs peaked at 3.4 billion tons in 2015, after which it began to decline.
[0010] The conversion of solid coals into gaseous hydrocarbons (methane and syngas) is most often accomplished through underground coal gasification (UCG). An oxidizer—air or oxygen mixed with water vapor—is injected into the underground formation through a feeder well. The coal reacts chemically with oxygen and water, and incomplete oxidation produces flammable mixtures of CO2, CO, and H2, which are brought to the surface through a production well. Unconventional oils are those for which traditional production methods are ineffective, either because they occur in low-permeability reservoirs or because they are near-solid and have minimal fluidity. Reserves of unconventional oils significantly exceed those of conventional oils, but their production poses a significant technical challenge.
[0011] Increasing reservoir permeability, or increasing oil availability, is currently achieved through horizontal well construction and hydraulic fracturing (HF)—the oil produced through this process is commonly referred to as shale oil. HF involves injecting water, as well as mixtures of water with hydrocarbon fluids, acids, nitrogen, carbon dioxide, and the like, into the reservoir under high, fracturing pressure. To prevent the fractures from closing immediately after the pressure is released, a proppant (quartz sand, glass beads, nut shells, etc.) is injected into them. Fractures after HF can extend for several hundred meters with an average width of up to 5 mm. These fractures act as new conduits for oil, significantly improving well-to-reservoir contact and expanding the area of fluid influx into the well. On average, a single HF treatment can increase the flow rate of oil wells by two to three times.Several hydraulic fracturing operations can be performed in a horizontal well. This is called multi-stage hydraulic fracturing (MSHF). In shale fields, the number of stages reaches into the tens. Currently, MSHF is perhaps the only sufficiently effective and proven method for developing hard-to-recover oil reserves.
[0012] Field development efficiency is assessed using the oil recovery factor (ORF). ORF is defined as the ratio of recoverable reserves to initial geological reserves and is calculated at each stage of field development—during design, during production, and at the end of production.
[0013] The average oil recovery factor for conventional production methods hasn't changed much over the past few decades. This is likely due to the fact that, despite technological advances, oil producers are still dealing with deteriorating reservoir properties.
[0014] According to generalized data, the recovery factor for primary development methods (using reservoir energy potential) is on average no higher than 10%, while for secondary development methods (flooding and gas injection to maintain reservoir energy) it is approximately 35%. In Russia, the recovery factor, as a rule, does not exceed 20%.
[0015] Thus, a large amount of unrecovered oil remains in the formations, which means lost profits.
[0016] The situation changes significantly when modern enhanced oil recovery (EOR) methods are employed. Their use allows for an average increase in oil recovery by another 7-15% and a significant increase in recoverable oil reserves at already discovered fields through improved oil displacement and an increase in the drainage zone without the need to drill additional wells.
[0017] The simplest EOR method is the now-common waterflooding procedure. Unfortunately, however, water does not displace oil uniformly. Due to the different viscosities and surface tensions of water and oil, the uneven structure of reservoir rocks, and the varying pore sizes, water can move faster than oil in certain sections of the formation. As a result, some oil remains trapped in the pores.
[0018] To more effectively displace oil, various aqueous solutions (surfactants, alkalis, etc.) are used as the displacing agent instead of water. This is quite expensive and not always practical. To reduce oil viscosity and increase its mobility, solvents—liquefied natural gases such as butane, propane, and their mixtures—are injected into the formation. Carbon dioxide, which dissolves readily in oil, can also be used as a solvent.
[0019] Increasing the coverage of the drainage zone can also be achieved by flooding with sulfuric acid, which dissolves the minerals of the reservoir rocks, thereby increasing its permeability.
[0020] However, all the above-mentioned methods are expensive and have their own contraindications in specific cases. Therefore, in some cases, thermal stimulation of the formation proves more effective.
[0021] The simplest thermal method is to inject hot water into the formation. This significantly reduces the oil's viscosity and increases its mobility. However, as the water moves through the formation, it cools, meaning the oil will first be displaced by cold water, then by hot water. As a result, the increase in oil recovery will be abrupt. Furthermore, at elevated temperatures, the oil's viscosity becomes sufficient to further saturate the capillaries of the rock, but insufficient to escape them.
[0022] A more effective method here is to replace water with hot steam, which, under similar conditions, has a higher heat content than heated water. An advanced solution is to inject supercritical water into the well (see, for example, patent RU 2671880 C1 dated May 18, 2017, "Method for extracting hydrocarbons from oil-kerogen-containing formations and a technological complex for implementing it," by V.G. Kiryachek, O.V. Kolomiychenko, and others). This water is produced in a surface water generator at a pressure P above 28.5 MPa and a temperature T above 593°C.Before high-temperature thermochemical impact on the productive formation, natural fractures and natural fluid-conducting channels in the bottomhole zone of the productive formation are restored by low-temperature thermochemical-catalytic impact on it with a working agent, followed by fixing the channels with nanoproppant, and after the main high-temperature thermochemical impact on the productive formation, in the process of delivering hydrocarbons to the daylight surface, their additional partial upgrading is carried out by passing them through a flow reactor formed by the space in the product pipeline between the tubing string (TU) and the couplingless pipe coaxially placed in it.
[0023] These options, which involve injecting heated water into the reservoir, require a significant amount of thermal energy, generated by flaring some of the produced oil or associated gases at the surface. Furthermore, using a supercritical water generator at the surface requires the use of expensive, heat- and chemically resistant materials capable of operating in the aggressive environment at elevated pressures and high temperatures found in the supercritical water generator.
[0024] Increasing the recovery factor is facilitated not only by large-scale impact on the productive formation, but also by working with the bottomhole zone - that part of the formation through which oil enters the production well.
[0025] During the oil production process, paraffins and resins settle at the bottomhole and in the near-wellbore zone of wells, and sand plugs stick to them and accumulate in the perforation channels.
[0026] Methods that can increase the permeability of the near-wellbore zone and clear it of debris, i.e., intensify the inflow, currently include vibration treatment of the face, the use of acid or thermal action on the plug, and often a combination of these methods.
[0027] Formation waters are a common feature of oil and gas fields. They are highly enriched in chemical elements of varying compositions and cause a significant number of complications during oil production and processing at the field level. As wells are operated, they gradually become flooded, and once the formation water content in an oil well reaches 90-95%, operation of the well becomes unprofitable.
[0028] Oil fields extend over large areas, reaching several hundreds and thousands of square kilometers, and are located in formations at depths reaching several kilometers.
[0029] An oil reservoir often consists of several permeable oil layers separated by impermeable barriers, which can number up to 20 interlayers. The effective reservoir thickness—the total thickness of the permeable layers—can reach 10 meters or more, while the field-weighted average is typically 2.8 meters. Hydraulic fracturing creates fractures in the reservoir and interlayers to increase permeability, extending up to several hundred meters. Clearly, to cover the largest possible area of a field, a sufficiently large number of wells is required.
[0030] However, currently used EOR methods have reached their limits and do not allow for a significant increase in recovery. To increase recovery and reduce the cost of oil recovery from existing and new wells, the following issues must be effectively addressed:
[0031] - increase the efficiency of oil extraction from capillaries and cracks in the productive formation;
[0032] - increase the volume of the zone of oil extracted from the formation in the presence of interlayers; - reduce the viscosity of the extracted oil and ensure its homogeneity, especially near the downhole well, without expensive reagents;
[0033] - to process kerogen in the formations into recoverable light synthetic oil; - to ensure high permeability of the bottomhole zone;
[0034] - reduce the concentration of minerals in extracted oil and formation water;
[0035] - make the method of oil extraction simple, reliable, and adjustable;
[0036] - improve the quality of hydrocarbons extracted from hard-to-recover reserves (shale and bituminous oil, keratogenic and coal deposits, etc.) through thermochemical reactions with complete or partial removal of sulfur and other elements directly in the formation;
[0037] - improve the environmental situation near operating fields, for example, by reinjecting extracted water into the formation.
[0038] A thermal method for extracting unconventional oil from deep formations using wells hydrodynamically interconnected in a flowing mode is known. It includes pumping an oxygen-containing gas mixture into the formation through injection wells, igniting the oil at the injection well using electric burners or a chemical reaction, forming a combustion front in the oil-bearing formation, reducing the viscosity of the oil by heating it due to thermal conductivity, followed by squeezing the oil to a production well inside the formation using gravitational forces and the pressure of the injected gas (see, for example, TXXia, M.Greaves, ATTurta, C.Ayasse. Chemical Engineering Research and Design. 5, 295-304, 2003; THAI (Toe-to-Heel Air Injection) in situ oil recovery requires minimal use of natural resources / / OIL&GAS NETWORK. 2004, v.5, #2, April; author's certificate SU 920200 dated 31.07.1978).For this process to be successful, it is necessary that the oil in the reservoir be distributed fairly evenly, and that the reservoir itself have high homogeneity, permeability and porosity.
[0039] However, the existing method of extracting unconventional oil has a number of significant drawbacks associated with high requirements for reservoir homogeneity, the possibility of gas breakthrough from the injection well to the production well bypassing the oil-containing section of the reservoir, the impossibility of extracting heavy hydrocarbons such as kerogen, and clogging of the bottomhole zone with debris, which in real conditions significantly affects the oil recovery factor.
[0040] The objective of the present invention is to increase the recovery factor of unconventional oil, including highly viscous and heavy oil, from deep wells. The stated objective is achieved in that in the known method for extracting unconventional oil from deep formations in the flowing mode, which includes pumping oxygen into an oil-containing formation through an injection well from an oxygen station through injection wells of a cluster of hydrodynamically interconnected injection and production wells (IPW) having injection and production pipes, igniting oil at the injection well, forming a combustion front in the oil-bearing formation that reduces the viscosity of the oil, squeezing the oil to the production wells of the IPC cluster, into the injection wells along with oxygen, a displacing agent is pumped by a high-pressure pump, which is water, with the creation in the formation of a pressure of the medium higher than the supercritical pressure for water in the range of P = 25 - 50 MPa,they bring the temperature of the water at the bottomhole above the critical temperature for water T = 400 - 900 C due to heat release during oxidation of oil by oxygen in the formation, thereby creating a mobile expanding cloud of water in a supercritical state (OSCW) near the bottomhole, due to a controlled imbalance of the flow rates of injected water and produced products in the hydrodynamically connected SSS of the cluster, as well as the production of oil from sections of the formation, leading to the cessation of local heat release, they create a movement of the combustion zone and, accordingly, the OSCW along the oil-bearing formation from a depleted well to a fresh well, while the OSCW, during its movement, carries out thermochemical reactions and extracts hydrocarbons into itself when passing sections of the formation between these hydrodynamically connected wells, destroys interlayers, increases the oil extracted into the cloud to the outer boundaries of the formation and directs hydrocarbons into production wells for lifting to the surface,In this case, the extraction of oil from the formation and the movement of the cloud are carried out from the deepest wells, leaving waste rock together with subcritical cooling water in the lower part of the developed oil-containing formation.
[0041] The injection and production pipes of a cluster of hydrodynamically interconnected injection and production wells (IPW) can be arranged in pairs coaxially to form a counter-current “pipe-in-pipe” heat exchanger for the flows of the displacing agent and the produced products.
[0042] At the daylight surface, after the extraction of oil products with water from the SDS production pipe and the separation of oil products, the residual contaminated water can be pumped back into the developed formation through the SDS injection wells, adding here waste from previous drilling operations and oil spills, oil refining waste, household waste, etc., thereby preventing and eliminating environmental pollution with industrial solid and liquid waste in the vicinity of the wells, while solid thermally non-degradable waste remains in the lower part of the developed section of the oil-bearing formation, and liquid waste undergoes additional thermochemical processing in the formation and is returned in a refined form to the daylight surface.
[0043] The presence of water-insoluble gaseous hydrocarbons in the production well produces a gas-lifting effect and reduces energy costs using the principle of communicating vessels for pumping water under high pressure into the injection well.
[0044] A technological complex for extracting unconventional oil from deep formations in a flowing mode, includes a cluster of hydrodynamically interconnected injection and production wells (IPW), an oxygen station for supplying oxygen to the injection wells, a device for igniting oil near the bottom of the injection wells, characterized in that it is additionally equipped with a high-pressure pump for supplying water as a displacing agent into the injection pipes of the IIP of a water-based displacing agent, an oxygen station for supplying oxygen, regulators for supplying water to each injection pipe of the IIP, regulators for the pressure of the produced products "before itself" at the mouth of each production pipe of the IIP, regulators for supplying oxygen to the bottom of each injection well of the IIP, temperature and pressure sensors at various sections of the oil-bearing formation near the bottom of the IIP, sensors for the composition of the produced products at the mouth of each production pipe of the IIP,an oil product separator from water on the daylight surface, an automated process control system (APCS) that controls the flow and pressure regulators at the SDS in accordance with the field development program, based on sensor readings and mathematical models of field development.
[0045] The injection and production pipes of a cluster of hydrodynamically interconnected injection and production wells (IPW) can be arranged in pairs coaxially to form a “pipe-in-pipe” heat exchanger for the flows of the displacing agent and the produced products.
[0046] Figure 1 shows a diagram of the wellhead and bottomhole of an injection and production well (IPW) with coaxial pipes for supplying oxygen and water and for bringing unconventional oil refinery products to the surface in a flowing mode. Here: 1 - IPF, 2 - oil-bearing formation, 3 - interlayers.
[0047] Fig. 2 shows the movement of a cloud of supercritical water through the developed oil-bearing formation between hydrodynamically connected wells of the well cluster. Here: 1 is the level of the daylight surface; 2, 3, 4 are the well cluster; 5 is the developed unconventional oil formation; 6 is the sediment of the oil-bearing formation rocks; 7 is the OSCW; A-B is the developed section of the oil-bearing formation, B-C is the high-temperature section of the oil-bearing formation with OSCW, C-D is the section of the formation with the modified oil being squeezed out from OSCW 2 to OSCW 3.
[0048] Fig. 3 shows a schematic diagram of a process complex for extracting unconventional oil from a well cluster. The process complex comprises: 1 - a buffer tank for water injected under pressure into the formation. The water source is primarily recycled water separated from oil obtained from production wells, and additionally water from natural water sources, including those containing oil and mineral contaminants from field development; 2 - a high-pressure pump that delivers water to injection wells.It is possible to use either one or several pumps for different wells in the well cluster; 3 - water flow regulators for individual injection wells in the well cluster, controlled by the process control system; 4 - flow (or back pressure) regulators for production wells, controlled by the process control system; 5 - oxygen flow regulators, controlled by the process control system; 6 - a cluster of injection and production wells (IPW) having coaxially located injection and production pipes, as well as pipes common with the injection pipes or separate pipes for injecting oxygen into the oil formation; 7 - oxygen station for supplying the process complex with oxygen; 8 - oil-water separator; 9 - automatic process control system (APCS).
[0049] Unconventional oil production proceeds as follows. First, oxygen is injected under high pressure from an oxygen station into the wellbore of one or more SDSs, igniting the oil in the formation. Simultaneously, water is pumped through these SDSs by a high-pressure pump to the bottomhole of the injection pipe, which then returns to the surface through the SDS and then through a pressure regulator back into the oil separator and water buffer tank (Fig. 3). The water, heated in the formation and containing the products, exiting through the SDS production pipes transfers heat to the water entering the wellbore, moving coaxially through the SDS injection pipes, dramatically reducing the energy costs of heating the SDS bottomhole. Reservoir pressure in deep wells is almost always higher than the supercritical pressure for water (Pcr = 22.1 MPa), and when the bottomhole temperature rises above the critical pressure (Tcr = 375°C), a supercritical water vapor (SWV) forms near the bottomhole of the injection pipe.This water has the ability to dissolve gases and petroleum products in virtually unlimited quantities, allowing it to extract hydrocarbons from the surrounding space. The higher the temperature and partial pressure of supercritical water, the greater its extraction capacity. As the temperature rises above 600-700°C, water at these pressures becomes an active participant in thermochemical transformations, one of the main ones being the reaction with carbon found in unconventional oils, particularly kerogens and bitumens, which leads to the formation of hydrogen: C + 2H2O -> CO2 + 2H2. Hydrogen, in turn, is also an active reagent, improving the quality of the extracted oil by reducing its viscosity.
[0050] Next, as the volume of the supercritical water cloud near the SDS (section A-B) in Figure 2 increases, the supercritical water, along with the hydrocarbons dissolved in it, escapes to the surface through the SDS production pipe, virtually completely removing hydrocarbons from this section of the reservoir. The remaining solid hydrocarbons, such as kerogen, continue to react with the oxygen supplied to the reservoir (C + O2 --> CO2 + thermal energy), maintaining high temperatures in the reservoir section. Various solid inclusions in the reservoir, interlayers such as sand, clay, etc., devoid of organic matter and degraded by local pressure gradients during uneven gas release or simply thermal stress, settle in the lower part of the reservoir section, clearing a passage in the reservoir, which, after the hydrocarbons from this section of the reservoir are completely exhausted and combustion ceases, gradually cools and fills with water in its normal state.
[0051] By reducing water withdrawal from the production pipe of the wellhead cluster (2) and, correspondingly, increasing water withdrawal from the production pipe of the wellhead cluster (3), the flow of the SSW (section B - C) from the wellhead cluster (2) to the wellhead cluster (3) is ensured. This flow strips the hydrocarbons, absorbs them, and drives them along the hydrodynamic channel (section C - D or D - E) toward the wellhead cluster (3). At the same time, the hydrocarbon temperature in the channel gradually increases over time, preventing clogging of this channel. In the SSW, the temperature is maintained primarily by the combustion of the most refractory hydrocarbons remaining after the cloud's passage in the region of the trailing edge of this cloud's movement.
[0052] By purposefully moving the OSCW along the mathematical model of the field from one wellhead pressure point to another, which is hydrodynamically connected, it is possible to significantly increase the recovery factor of unconventional oil deposits. Thermochemical reactions in the reservoir, including those involving water, can significantly enhance the extractable hydrocarbons. The presence of supercritical water in the pressure points, which has a high solvent capacity for hydrocarbons, significantly reduces fouling of the bottomhole of production wells.
[0053] In the given example, water plays the primary role as the displacing agent. Its incompressibility, high heat capacity, and heat of vaporization due to heat exchange between counter-moving flows in the pressure-strain zone (PSS) significantly reduce heat losses during production, as will be demonstrated in the examples below. It should be noted that, in principle, air could be injected into the PSS as a displacing and oxidizing agent instead of oxygen. This may offer some benefit if deep reservoir development is conducted from shallower wells. However, from an energy perspective, the disadvantages usually outweigh the benefits.
[0054] The proposed invention enables the efficient development of large fields with the proper placement of cluster wells. Hydraulic fracturing or even multi-stage hydraulic fracturing can be used to establish hydrodynamic connections between wells. This can significantly increase the recovery factor for unconventional oil production.
[0055] Let's examine the energy costs and application features of the proposed invention in more detail using specific examples. Example 1. Unit VAT. Energy balance and well productivity assessments for unconventional oil production using the proposed method.
[0056] To create and maintain a high-temperature cloud of supercritical water (SCW) in an oil-bearing formation, a source of thermal energy is required. This is achieved through a chemical reaction that oxidizes the oil within the formation using oxygen supplied from the surface.
[0057] The energy released as a result of this reaction is W o in a steady-state case, it is used for heat transfer from the OSQV to the surrounding cloud space W s , to support endothermic reactions within the OSCB W r and on convective heat carried away together with the products of thermochemical transformations W cothrough the production pipe (SDS) from the OSKV to the surface. In turn, heat from the bottom of the production pipe (Wco) goes to the SDS, which is also a counter-current pipe-in-pipe heat exchanger, to heat the water injected into the formation (W). C i, , to heat the space surrounding the well W s j and the residual thermal energy carried by water and oil products to the surface, which exceeds the thermal energy injected through the injection well by Wd. To complete the picture, the cost of heating the oxidizer flow—oxygen W02—in the well must also be taken into account.
[0058] Thus, we have the following relationships for energy balance:
[0059] - in OSKV: Wo + Wei = W s + W r + W co + W o2 , (1) - in VAT: Wco = Wei + Wsi + W d (2) or, combining them: W o - W s + W r + W si + Wd + W o2(3) When carrying out quantitative assessments in this example, for the sake of certainty, we will set the characteristic numerical values of the main parameters of the SDS, oil reservoir and OSCB:
[0060] - well: depth H = 2500 meters, internal diameter of the injection pipe - di — 80 mm, internal diameter of the coaxially located production pipe near the bottomhole - d2 = 140 mm;
[0061] - oil reservoir: high-viscosity oil with kerogen, reservoir thickness - h = 10 meters, interlayer thickness - h p = 0.1 * h = 1 meter, average temperature of the rock at a distance of 1 meter from the layer T g = 50 C;
[0062] - OSKB: the characteristic size (diameter) coincides with the thickness of the layer - D = 10 meters, the maximum temperature in the center of the cloud T о = 700 C, partial pressure of water - P = 30 MPa. Its volume will be V = 520 m3 3 , and the lateral surface area S = 310 m 2 Volume of interlayers (10%) V = 52 m 3 .
[0063] Let's note the important features of SCR that allow for a significant increase in recovery compared to traditional production methods. At the specified temperature and pressure, the density of SCR is approximately 300 kg / m3. 3 , which is significantly less than the density of water under normal conditions, which is 1000 kg / m3 3SCR has a high dissolving power for hydrocarbons and gases, but is virtually ineffective at dissolving inorganic substances. SCR essentially behaves like a dense gas with high diffusion coefficients and thermal diffusivity, which are more than three orders of magnitude higher than those of liquids such as water or light oil. Considering the presence of possible inhomogeneities, turbulent flows due to localized gas formation, etc., turbulent diffusion can also play a significant role in the transfer of substances in the SCR, leading to the equalization of dissolved substance concentrations and the temperature field throughout the SCR volume. SCR has high extraction properties, increasing with increasing partial pressure of water, allowing oil to be extracted from cavities and capillaries in the SCR.Another important property of SCR, at a given temperature and pressure, is its direct participation in thermochemical gasification reactions with carbon atoms, which form the basis of oil and kerogens. For example, C + 2H2O -> CO2 + 2H2, producing hydrogen. This, in turn, promotes the upgrading of produced hydrocarbons, reduces oil viscosity, and removes impurities. Interlayers and other minerals, sulfur compounds, and metals within the oil reservoir have a density of approximately 2000 kg / m3, which is significantly higher than the density of SCR. Therefore, they settle to the bottom of the reservoir under the force of gravity, freeing the hydrodynamic channel and facilitating the advancement of the SCR, without clogging the perforations of the production pipe.
[0064] Performance assessment of individual VAT:
[0065] To estimate the performance of an individual SDS in flowing mode, we will assume the specific gravity of oil to be equal to the density of water at the same temperatures and pressures. For simplicity, we will also assume that the amount of water injected by weight will be equal to the amount of water-oil slurry obtained from the production well.
[0066] The performance of a VSD is determined primarily by the capacity of the injection and production pipes and depends on their diameter. With a water velocity in an 80 mm diameter injection pipe at the daylight surface of v = 1 m / s, we obtain the volumetric performance:
[0067] Q p = 0.8 * 0.08 2 m 2 * 1 m / s = 0.005 m 3 / s = 18.0 m 3 / hour = 432 m 3 / day = 0.15 million m 3 / year. That is, this single well, with an oil-to-water concentration of 40%, will produce approximately
[0068] Q o = 0.4 * Q p ~ 170 m 3 / day = 62 thousand tons / year of petroleum products.
[0069] The well's productivity for oil with a water concentration of 90% will be: Q w = (1 - 0.9) * Q p = 43 tons / day = 16 thousand tons / year of petroleum products.
[0070] If we assume that the volume of a cloud with a diameter of D = 10 m before heating contained approximately 0.9 * V = 0.9 * 520 m3 = 468 m3 of oil, then to extract it to 90% of the maximum it would take no more than:
[0071] tgo = 468 m3 / 43 (m3 / day) = 10.9 days.
[0072] Note that to extract oil from OSKB at 60% oil concentration it would require:
[0073] teo ~ 468 m3 / 170 (m3 / day) = 2.7 days.
[0074] Assessment of the significance of processes influencing the energy balance in formula (3):
[0075] - heat losses of the OSKV due to heat transfer to the surrounding rock formation W s :
[0076] Heat loss from the cloud-to-air mixture to the surrounding environment is determined by the thermal conductivity of the surrounding medium. Reference books provide the following thermal conductivities for various solid and liquid materials at temperatures close to normal: water - X = 0.6 W / (m*C); clay, sand - X = 0.8 - 1 W / (m*C); rocky soil - X = 2 W / (m*C). For certainty, we will assume the effective thermal conductivity of the surrounding rocks X = 1 W / (m*C).
[0077] Then in the stationary case of a spherical shape of the OSCB we will have:
[0078] W s = 27t(T0-Tg) * X * D = 6.28 * 650 * 1 * 10 (W) = 41 kW. (4) The OSQV cannot effectively spread beyond the boundaries of the oil-bearing formation, since there are no heat sources there.
[0079] - heat losses through the outer wall of the VAT W s i:
[0080] For a rough estimate, we will take the average value of the wall temperature of the SDS along the height from the face to the mouth T si= 350 C, soil thermal conductivity coefficient X - 1 W / (m*C), soil temperature at a distance R2 - 1 m from the borehole axis T g = 50 C, the average radius of a well 2500 m long Ri = 0.15 m. Then for W si we get:
[0081] Wsi = 2L (Tsi- T g ) * H * X / In (R2 / R1) = 6.28 * 300 * 2500 * 1 / 1.9 (W) = 2.5 MW (5) - convective losses of thermal energy associated with the removal of thermal energy through the production pipe by water with the products of thermochemical transformations:
[0082] Of particular importance in the energy balance during the entire technological process is the consideration of "pipe-in-pipe" heat exchange in coaxial SSS pipes between the injected water flows and the counter-current produced products of thermochemical transformations. Convective losses are estimated based on the temperature difference between the water leaving the production pipe, T ехWith the processed products and the temperature of the water entering the injection pipe, Tsh, at the well's daylight surface. Assuming that the masses of the incoming water and the products exiting the well are equal and their effective heat capacities at the daylight surface are approximately equal, the thermal power losses due to heat removal from the well (if this heat is not subsequently utilized) will be:
[0083] Wco - Wei = Wd ~ Qp * Ср * (Тех - Tin) (6), where С р = 4.2 kJ / (kg*C).
[0084] Accurately calculating the heat transfer between coaxial pipes in a well in this example is a complex and, in this case, thankless task, since the parameters of water and products of thermochemical transformations are highly dependent on temperature, which varies significantly along the flow of these media. As water moves downhole, the hydrostatic pressure also changes. The production pipe may contain gas, leading to gas lifting. The flow pattern in both the injection and production pipes also changes with depth. It is clear that heat transfer between pipes in the pressure-strain zone (PSS) should be significantly more intense than heat transfer from the PSS to the surrounding environment due to their smaller size and flow turbulence. Here, we will obviously have to limit ourselves to estimates based on heat transfer calculation tables for coaxial counterflow heat exchangers, which are widely available online.Analysis of the data in the tables, as applied to the conditions under consideration, shows that at v = 1 m / s the temperature difference (T. ех - Tin) is within 3-5°C, and at v = 2 m / s it will be 7-10°C. Due to the sharp decrease in water viscosity with increasing temperature, i.e., a decrease in hydrodynamic resistance to the flow of water and water-containing products, at given flow rates, pressure losses in both the injection and production pipes of the SSS are insignificant compared to the in-situ pressure. Regarding the accuracy of the estimates, it should be noted that their accuracy does not fundamentally alter the essence of the invention.
[0085] In this invention, water is used not only as a displacing fluid, delivering unconventional oil to the surface, but also as a highly effective solvent for supercritical oil in the reservoir and a chemical reagent for upgrading high-viscosity oil. It should also be noted that water from the production pipe is reinjected into the injection well after oil separation. The extracted oil in the depleted reservoir can be replaced by adding water from external sources to the injection well.
[0086] In the example under consideration, energy losses due to heat transfer to the surface will be:
[0087] Wo = 0.005 m3 / s * 4.2 kJ / (kg*C) * 5 C = 0.1 MW (7), which is significantly less than the heat loss through the walls of the SDS.
[0088] It should be noted that if supercritical water is injected from the surface, thermal energy losses will be at least 700 / 5 - 120 times greater, i.e., over 10 MW. This is likely costly and not feasible, as producing supercritical water at the surface requires specialized, rather expensive materials to resist corrosion and accommodate the simultaneous high pressures and temperatures in such a heater. Localized heating directly in the oil reservoir and thermal energy recovery in a coaxial well significantly simplify the technological solution.
[0089] Thus, the main heat losses in the process of extracting unconventional oil from deep wells are associated with soil heating along the SSS. Note that as the soil near the SSS heats up, i.e., as R2 increases, these losses will decrease.
[0090] - the amount of oxygen required to maintain the temperature in the OSCW:
[0091] In the example under consideration, heat losses are up to 3 MW per SDS, regardless of the water content of the extracted petroleum products. It was noted earlier, and this follows from formula (3), that all heat losses can and should be compensated for by oil combustion during oxygen injection into the oil-bearing formation.
[0092] Let's assume the calorific value of oil in the reservoir to be 30 MJ / kg. The required amount of oxygen for combustion of unconventional oil will be taken as 4:1 by weight.
[0093] That is, it is necessary to burn (subject to supercritical water oxidation SCWO) approximately 3 MW / 30 (MJ / kg) = 0.1 kg of oil / s = 8.7 tons of oil per day, which is much less than the daily amount of oil produced (compare 170 tons of oil per day with a water cut of 60% and 43 tons of oil per day with a water cut of 90%).
[0094] The required amount of oxygen to maintain the OCS will be, accordingly, 8.7 tons of oil * 4 = 35 tons of oxygen per day, regardless of the water content in the recovered oil. The amount of oxygen injected into the well and its heat capacity are significantly less than that of the water injected into the well, so the contribution of the heat capacity of oxygen can be neglected in the energy balance (the W02 term in formula (3)). Similarly, the thermal effects of endothermic reactions W can be neglected. r Due to their small size compared to the heat released during carbon oxidation, the costs of endothermic reactions can be offset by a small additional supply of oxygen.
[0095] The cost of 1 ton of oxygen is approximately $100 per ton. The price of oil is currently approximately $60 per barrel, or $375 per ton.
[0096] With a 40% water cut, 35 tons of oxygen are required to produce 170 tons of oil. The contribution of oxygen to the cost of crude oil in this case is (35 / 170) * (100 / 375) = 5.5%. With a 90% water cut in the produced oil, the cost of providing oxygen will exceed 22%. Therefore, producing oil from a well using this method can be profitable even with a water cut exceeding 90%. The absolute contribution of using oxygen for unconventional oil production will be approximately $21 and $83 per ton of unconventional oil produced using the proposed method, respectively. However, this method is profitable in any case due to a significant increase in oil recovery, given the lack of other technologies for extracting unconventional, hard-to-reach oil from deep wells in most cases.
[0097] The example given shows the great potential for using a cloud of supercritical water as a solvent, an extracting agent, a chemical reagent for reducing viscosity, and a material carrier to the surface of unconventional oil from deep wells.
[0098] - energy costs for water circulation through the SDS and the reservoir:
[0099] Maximum energy expenditure W p for pumping water through the SDS with pressure losses equal to the hydrostatic pressure P = 25 MPa, are:
[0100] W p = Q p * P - 0.005 (m 3 / с) * 25 MPa = 0.125 MW with a pump efficiency close to unity. If we take into account the following factors:
[0101] - As the well depth increases, the hydrostatic pressure of the water increases, and at H = 2500 m it will already reach the required P = 25 MPa. Additional pressure can be created by a high-pressure pump located on the surface;
[0102] - as the temperature in the well increases to supercritical, the density of water drops by approximately 3 times, which leads to a decrease in hydrostatic pressure;
[0103] - the production well contains non-condensable gases, such as carbon dioxide and methane, with low density, which creates a gas lifting effect in the communicating pipes of the SDS, reducing the energy costs for circulating the solvent - water - through the SDS;
[0104] The viscosities of water and petroleum products drop by more than an order of magnitude as the temperature in the oil-bearing formation rises to operating temperatures, leading to a sharp reduction in friction in the pressure-strain state pipes. However, even with standard water viscosity at 20°C and a flow velocity of v = 1 m / s, frictional pressure losses in the pipes will be negligible compared to hydrostatic pressure. Therefore, these energy costs can be even more neglected compared to other costs.
[0105] Example 2. Non-stationary phenomena in field development.
[0106] In the non-stationary case, namely, during the formation and expansion of the OCW, as well as the heating of the liquid mass in the discharge pipe, an additional amount of thermal energy is expended. Let's estimate this energy.
[0107] So, the volume of water in the injection well is:
[0108] Morning = 0.8* 0.08 2 * 2500 m 3 = 12.8 m3
[0109] , which is significantly less than the volume of OSKV.
[0110] That is, the costs of heating water in the VAT should be significantly lower than the costs of heating the SWC cloud.
[0111] The time it takes for water to pass through an injection well to the bottomhole is, taking into account the drop in water density to a level of p = 300 kg / m3:
[0112] tin ~ 2500 m / 2m / s = 1250 s = 0.35 hours.
[0113] This time is significantly less than the time of oil production from a developed OSCW at the considered oil water cuts of t9o or even Ш
[0114] This means that the energy spent on heating the OSKV is returned through recovery in the VAT heat exchanger in the form of water heated in the discharge pipe.
[0115] After igniting the oil in the formation near the bottom of the injection well, the OSCW will increase in volume to the dimensions discussed in Example 1. In this process, a certain amount of thermal energy will be expended.
[0116] If the time of formation of the specified volume of OSKV is taken as the time of emptying this volume through the production pipe, then with the average heat capacity of the oil reservoir C П l = 1 kJ / (kg*C) and Tmax = 700 C, then we obtain the thermal energy consumption to reach a steady-state production mode:
[0117] WCKB = 520,000 kg * 1 kJ / (kg*C) * 700 C / 10.9 days = 0.39 MW at 90% water cut of the produced oil and
[0118] WCKB = 520,000 kg * 1 kJ / (kg*C) * 700 C / 2.7 days = 1.56 MW at 60% water cut of the produced oil.
[0119] These values are comparable to the thermal energy costs of maintaining a stationary OCS and delivering oil products to the surface. Therefore, during the initial, non-stationary stage of oil reservoir development, the amount of oxygen supplied should be increased slightly. Example 3. Oil reservoir area under an OCS, optimal distance between adjacent SDSs in a well pad.
[0120] As can be seen from Example 1, heat losses through the boundaries of the OSCB into the surrounding rock formation W s not the largest compared to heat transfer into the surrounding VAT rock Wsl.
[0121] For the purpose of the assessment, let us assume that W s ~ Wsi= 2.5 MW. Assuming the thermal conductivity of the rock = 1 W / (m*C), the temperature of the OSCB near its boundary T о = 700 C, and the temperature of the rock at a distance of L = 1 meter from the boundary T g = 50 C, we obtain the area of the upper or lower part of the OSCB S 0CK B without taking into account the boundary area of the OSKV with the oil-bearing formation:
[0122] SOCKB = 0.5 * Wsi * L / (X * (To - T g )) - 1920 m 2 .
[0123] That is, with a round cloud, its size could be about 50 meters near a single SDS, and with an oil reservoir thickness of 5-10 meters, its length (for example, to the neighboring SDS) could be up to 200 meters or more.
[0124] Taking into account the gradual heating of the surrounding rock layers and the resulting reduction in heat loss from the OSKV, the optimal distance between adjacent SDSs in a bush can be several hundred meters.
[0125] Example 4. Oil extraction from a cluster of hydrodynamically interconnected wells. Hydrodynamic connectivity between wellheads can be artificially created, for example, through hydraulic fracturing. A cluster of hydrodynamically interconnected wellheads allows for the production of large oil-bearing formations by arranging the flow of OCW from one wellhead to another by changing the ratio of fluid flow rates in individual wellheads.
[0126] As an example, when in the injection pipe VAT - 6(1), the feed will be increased, say, by two times, and in the production pipe VAT - 6(2), the flow rate will, accordingly, also be increased by two times (see example 1), the OSKV will move from VAT - 6(1) to VAT - 6(2), provided that the cloud diameter (in the example under consideration D = 10 m) will not change, at a speed of:
[0127] VOCKB - Qp / 0.8 *D * D = 18 (m 3 / hour) / (0.8 * 100 m 2 ) = 0.22 m / hour = 5.4 m / day.
[0128] In this case, a layer with an area of approximately: will be traversed in a day.
[0129] St ~ VOCKB * D ~ 54 M 2 / day.
[0130] In other words, 10 VAT per month can develop areas of more than 10 thousand m 2 deposits with a thickness of 10 m and produce, depending on the water content in the oil in the examples under consideration, from 10 to 50 thousand tons of unconventional oil per month.
[0131] One of the main issues of field development by the method under consideration is the problem of stability and controllability of the movement of the oxygen-containing gas in the reservoir or the question of the possibility of complete extraction of oil from the entire volume of the oil reservoir. This issue is the main one for the prototype of the present invention (TXXia, M.Greaves, ATTurta, C.Ayasse. Chemical Engineering Research and Design. 5, 295-304, 2003; THAI (Toe-to-Heel Air Injection) in situ oil recovery requires minimal use of natural resources / / OIL&GAS NETWORK. 2004, v.5, #2, April), where the introduced oxygen-containing gas played the role of not only an oxidizer to increase the temperature and reduce the viscosity of the produced oil, but also the role of a pusher of this oil into the production well.Therefore, reservoir heterogeneities, uneven reservoir heating, and geometrical features of the injection and production well locations, when a viscous liquid is pushed out by a significantly less viscous gas, lead to gas breakthroughs toward the production well, significantly reducing oil recovery. Much oil remains in pores, capillaries, and various zones of the reservoir. It also proves extremely difficult to treat clusters of hydrodynamically interconnected wells, i.e., large fields.
[0132] At the same time, in the present invention, the piston, in the form of a SKV, contains a homogeneous, controlled, and slowly moving SKV substance with dissolved petroleum products within it within the oil-bearing formation. The water in the SKV primarily serves as a strong solvent for unconventional oil, extracting it from the pores and capillaries of the surrounding rock, and as a chemical reagent that enhances the quality of the recovered oil. This water has minimal viscosity, and therefore, it is this water with dissolved hydrocarbons that will be the first to reach the production pipe. As the SKV advances toward the production well along existing fractures, the temperature of the walls of these channels will increase, the viscosity of the moving fluid will decrease, and the channel will expand due to the removal of petroleum products. The SKV can remain in a given section of the oil-bearing formation for as long as necessary to maximize oil recovery.Oxygen supplied from the surface will be consumed only where there is oil, and it will lead to the expansion of the OSCW.
[0133] The oxidation of hydrocarbons produces carbon dioxide, which is highly soluble in SCW and also a good oil dissolver, especially when in a supercritical state. In this case, carbon dioxide will facilitate the delivery of hydrocarbons to the surface, and its entry into the production pipeline will not negatively impact the sustainability of the unconventional oil extraction process.
[0134] Water, passing into the SSCW, is not a classic pushing agent, as it becomes a single unit with the oil products. Moving through the oil-bearing formation from one SSC to another, absorbing oil from pores and capillaries, cleaning the formation of oil down to kerogens, leaving behind water cooled to a subcritical state and waste rock, it emerges at the surface, cooling to subcritical temperatures where most oil products are virtually insoluble and can therefore be separated from the carrier (water) at minimal cost. The separated water, along with the remaining oil products, is injected into one of the SSCWs, thereby preventing damage to the environment around the well, and the oil products, separated from the water, are sent to an oil storage facility. To replace the volume of oil removed from the formation, water from external sources can be injected into it.Moreover, the water may be quite dirty, for example, with residues of drilling fluids, oil spills from well development, household waste, and sewage. Potential breakthroughs of the OSCW to adjacent SDSs through hydrodynamic channels will not lead to instability, since the movement of the OSCW can be tightly controlled by flow regulators located on the daylight surface, which regulate fluid flow through the injection and production pipes of individual SDSs, as well as oxygen flow regulators.
[0135] The presence of oxygen at the trailing edge of the SSCW will lead to additional heating of the cloud due to the oxidation of hard-to-recover heavy hydrocarbons (e.g., kerogen, coal, coke, etc.), contributing to both overall heating and an increase in oil recovery. After the cloud moves to the adjacent SSS, even if oil is produced from thin capillaries, heat generation in this section of the reservoir due to oxygen combustion ceases, and cooling of the depleted section occurs either naturally or induced by the addition of water. Since water density increases during cooling, it is advisable to move the SSCW from deeper to shallower wells by regulating the pressure and flow rates of water and oil products at the well's surface, allowing the depressed sections of the reservoir to fill with water and interlayer debris.If a section of the reservoir is devoid of oil products, oxidation reactions with heat release cannot occur there. The reservoir cools, water converts to a normal liquid state, and fills the space vacated by oil. The oxidizer is then moved to an area containing hydrocarbons. Effective oil field development using this technology requires a thorough understanding of the properties of the oil-bearing reservoir, careful monitoring of its condition during development, mathematical modeling and forecasting of field development, and regulation of the oxidizer temperature and the rate of oxidizer propagation to obtain oil products with optimal properties.
[0136] The examples given show that, compared to known ones, the proposed technology has the following advantages:
[0137] - allows for the efficient extraction of unconventional oil from deep formations over large areas of fields;
[0138] - allows for the modification of heavy oils into lighter ones by carrying out cracking, gasification of kerogens and hydrogenation directly in the oil-bearing formation;
[0139] - increase the recovery factor by extracting even highly viscous and heavy oil from the pores and capillaries of the formation with water in a supercritical state and carbon dioxide;
[0140] - to solve environmental problems of oil production by cleaning the area around wells from technological contaminants by injecting liquid and solid contaminants into the pipes of injection wells and leaving these contaminants in the developed formation.
[0141] The increased efficiency of the proposed technology for producing unconventional oil from deep wells by fountaining, in contrast to the known technology of squeezing oil heated by combustion in oxygen into a production pipe with an oxygen-containing agent, consists of dissolving and modifying the oil directly in the oil reservoir in the strongest hydrocarbon solvent, which is water in a supercritical state, organizing the controlled movement of a cloud of supercritical water through the oil-bearing reservoir, delivering such a solvent with oil products to the surface, where the solvent turns into water and loses its dissolving properties, and reinjecting water through an injection pipe into the oil-bearing reservoir, whereby the water is heated to a supercritical state by the solvent with oil products coming to the surface.If there are no oil products left in the well, the oxidation reaction with heat generation cannot occur, the formation cools, water returns to its normal liquid state, and fills the space vacated by the oil. The oxidizing agent moves to the area where hydrocarbons are present.
[0142] The required raw materials are additional water from any source and oxygen. Energy for oxygen production can be obtained from associated gas extracted on-site from a well.
[0143] Fig. 3 shows a diagram of the process complex for extracting unconventional oil from a well cluster in the flowing mode according to the proposed method. The process complex includes a cluster of hydrodynamically interconnected SDS (15), an oxygen station (7) with a compressor for feeding an oxygen-containing mixture into injection wells, one or more high-pressure pumps (2) for feeding water into the SDS injection pipes from a water buffer tank (1), water supply regulators (3) into each SDS injection pipe, pressure regulators of the produced products "before themselves" (4) at the mouth of each SDS production pipe, oxygen supply regulators (5) into the bottomhole of each SDS injection well, temperature and pressure sensors at various sections of the oil-bearing formation near the SDS bottomhole, sensors of the composition of the produced products at the mouth of each SDS production pipe, an oil product separator from water on the daylight surface (8),An automated process control system (APCS) (9) that controls the flow and pressure regulators at the SDS in accordance with the field development program, based on sensor readings and mathematical models of the field. Additional water to replace extracted oil in the reservoir is supplied to the buffer tank from external sources.
[0144] The technological complex allows for scanning of the oil reservoir using a VAT cluster and OSKV for the most complete and efficient extraction of petroleum products to the surface, modification of the composition of the extracted petroleum products in the desired direction, and also solving environmental problems of environmental pollution from accumulated industrial waste such as spilled oil, drilling fluids, harmful chemical additives, municipal waste, etc. by injecting them into the spent VAT cluster.
Claims
Formula 1. A thermal method for extracting unconventional oil from deep formations in a flowing mode, which includes pumping oxygen into an oil-containing formation through an injection well from an oxygen station through injection wells of a cluster of hydrodynamically interconnected injection-production wells (IPW) having injection and production pipes, igniting the oil at the injection well, forming a combustion front in the oil-bearing formation that reduces the viscosity of the oil, squeezing the oil to the production wells of the IPF cluster, characterized in that, along with oxygen, a displacing agent, which is water, is pumped into the injection wells using a high-pressure pump, creating a pressure in the formation above the supercritical pressure for water in the range of P = 25 - 50 MPa, bringing the water temperature at the bottomhole above the critical temperature for water T = 400 - due to heat release during oxidation of oxygen by oil in the formation. 900 C,creating a mobile expanding cloud of supercritical water (SCW) near the bottomhole, due to a controlled imbalance in the flow rates of injected water and produced products in the hydrodynamically connected SSS of the cluster, as well as the production of oil from sections of the reservoir, leading to the cessation of local heat generation, create a movement of the combustion zone and, accordingly, the SCW along the oil-bearing reservoir from the exhausted well to a fresh well, while the SCW, during its movement, carries out thermochemical reactions and extracts hydrocarbons into itself when passing sections of the reservoir between these hydrodynamically connected wells, destroys interlayers, increases the oil extracted into the cloud to the outer boundaries of the reservoir and directs hydrocarbons into production wells for lifting to the surface, while the production of oil from the reservoir and the movement of the cloud are carried out from the deepest wells,leaving waste rock along with subcritical cooling water in the lower part of the developed oil-containing formation.
2. The method according to paragraph 1, characterized in that the injection and production pipes of a cluster of hydrodynamically interconnected injection-production wells (IPW) are arranged in pairs coaxially to form a counter-current “pipe-in-pipe” heat exchanger for the flows of the displacing agent and the extracted products.
3. The method according to paragraphs 1-2, characterized in that, at the daylight surface, after the extraction of oil products with water from the SDS production pipe and the separation of oil products, the residual contaminated water is pumped back into the developed formation through the SDS injection wells, adding here waste from previous drilling operations and oil spills, oil refining waste, household waste, etc., thereby preventing and eliminating pollution of the environment with industrial solid and liquid waste in the vicinity of the wells, wherein solid thermally non-degradable waste remains in the lower part of the developed section of the oil-bearing formation, and liquid waste is subjected to additional thermochemical processing in the formation and is returned in a refined form to the daylight surface.
4. A process complex for extracting unconventional oil from deep formations in a flowing mode, including a cluster of hydrodynamically interconnected injection and production wells (IPW), an oxygen station for supplying oxygen to the injection wells, a device for igniting oil near the bottom of the injection wells, characterized in that it is additionally equipped with a high-pressure pump for supplying water as a displacing agent into the injection pipes of the IIP of a water-based displacing agent, an oxygen station for supplying oxygen, regulators for supplying water to each injection pipe of the IIP, regulators for the pressure of the produced products "before themselves" at the mouth of each production pipe of the IIP, regulators for supplying oxygen to the bottom of each injection well of the IIP, temperature and pressure sensors at various sections of the oil-bearing formation near the bottom of the IIP, sensors for the composition of the produced products at the mouth of each production pipe of the IIP,an oil product separator from water on the daylight surface, an automated process control system (APCS) that controls the flow and pressure regulators at the SDS in accordance with the field development program, based on sensor readings and mathematical models of field development.
5. The technological complex according to paragraph 4, characterized in that the injection and production pipes of a cluster of hydrodynamically interconnected injection and production wells (IPW) are arranged in pairs coaxially to form a “pipe in pipe” heat exchanger for the flows of the displacing agent and the extracted products.