The considered technologies are changes in the direction of filtration flows and cyclic waterflooding; FLC is a non-stationary physical process. Pressures and pressure gradients depend on time. The use of cyclic waterflooding is based on the existence of a hydrodynamic connection between interlayers of different permeability. The extraction of oil from a low-permeability reservoir, the flow of oil in the second half-cycle from OP to EP, does not formally increase the sweep efficiency. However, it allows involving low-permeability differences in the effective thickness of the opened interval in the development
[21][43]. Therefore, the thickness coverage ratio increases. Over time, the amount of oil flowing from OR to WP decreases, and the sweep efficiency also decreases. However, it allows involving low-permeability differences in the effective thickness of the opened interval into the development. Therefore, the thickness coverage ratio increases. Over time, the amount of oil flowing from OR to WP decreases, and the sweep efficiency also decreases. However, it allows involving low-permeability differences in the effective thickness of the opened interval in the development
[26][44].
5. Gas and Water–Gas EOR
5.1. Displacement of Oil from the Reservoir by Carbon Dioxide (CO
2
)
To displace oil from the reservoir, carbon dioxide CO
2 can be used, which mixes with oil at a temperature of 300–310 °K and pressure above 10 MPa. However, resins and asphaltenes contained in the oil are slightly soluble in CO
2 and may precipitate. Critical values are CO
2 P = 7.38 MPa, T = 305 °K. For complete solubility of CO
2, it is necessary to increase the temperature and pressure above critical values, for example, P = 30 MPa, T = 360 °K
[27][46].
Another way to use CO
2 is as follows. Water is pumped into the formation with carbon dioxide dissolved in it (carbonized water). Due to the greater chemical “affinity” of oil and CO
2, upon contact with carbonized oil water, CO
2 molecules diffuse, loosen heavy oil films on the surface of rock grains, and make these films mobile, which leads to an increase in the amount of oil to be recovered
[28][47].
5.2. Displacement of Oil by Hydrocarbon Gases
Currently, much attention is paid to the utilization of associated petroleum gas. One of the ways to use associated gas is to use it as a reagent injected into injection wells in order to increase the oil displacement efficiency
[29][49].
To increase oil recovery, the following gases are used: dry hydrocarbon gas, high-pressure gas, enriched gas and gas–water (water–gas) mixture. When using liquefied hydrocarbon gases and other liquid hydrocarbon solvents as displacing agents, another problem arises in extracting the solvent remaining there, the price of which can significantly exceed the cost of oil
[30][50].
Oil displacement by the reagent can be immiscible or miscible (without the existence of a phase boundary). The miscibility of gas with oil in reservoir conditions is achieved only in the case of light oils (the density of degassed oil is less than 800 kg/m
3). The injection pressure of dry hydrocarbon gas is 25 MPa or more, and the pressure of enriched gas is 15–20 MPa. When mixing (dissolving) gas with oil, the viscosity of oil decreases, the mobility of oil increases, including flow rates (Dupuy’s formula
[31][51]), and, ultimately, oil recovery.
5.3. Water–Gas Cyclic Impact
The technology of cyclic water–gas treatment consists of the fact that gas and water are injected into the reservoir alternately by rims or simultaneously in a mixture into the same or separate injection wells
[32][55].
Physically, the oil displacement mechanism is as follows. Water fills small pores and narrows the pore channels, thereby increasing the sweep efficiency. The gas injected into the reservoir, due to its greater mobility, occupies large pores, and the upper part of the reservoir partially dissolves in oil, increasing its mobility and thereby increasing the displacement efficiency. Thus, gas increases one of the factors of the oil recovery factor, and water increases the other
[33][56].
Joint displacement of oil from heterogeneous reservoirs by water and gas is more effective for ultimate oil recovery than the separate displacement of oil only by water or gas. By choosing the optimal operating mode, reservoir recovery can be increased by 7–15% compared to conventional waterflooding. The main condition for the optimality of the water–gas treatment process is to ensure a uniform distribution of the injected gas over the water-flooded volume of the reservoir, in which there is a simultaneous breakthrough of gas and water into production wells. The duration of injection cycles for each agent is 10–30 days
[34][35][57,58]. By choosing the optimal operating mode, reservoir recovery can be increased by 7–15% compared to conventional waterflooding. The main condition for the optimality of the water–gas treatment process is to ensure a uniform distribution of the injected gas over the water-flooded volume of the reservoir, in which there is a simultaneous breakthrough of gas and water into production wells. The duration of injection cycles for each agent is 10–30 days
[34][57].
6. Thermal Methods of Enhanced Oil Recovery
6.1. Physical Processes Occurring When Oil Is Displaced by Heat Carriers
The initial value of reservoir temperature and its distribution in the reservoir is determined by the geothermal conditions in which the field is located. Typically, reservoir temperature follows a geothermal gradient. During the development of the field, the reservoir temperature may change. Thus, the water injected into the reservoir has a different temperature. Processes associated with the release or absorption of heat occur in the reservoir. The temperature change will occur due to the hydraulic resistance of the filtering fluids due to the Joule–Thomson effect
[36][63].
The distribution of reservoir temperature and its change is called the temperature regime. The change in the temperature regime occurs mainly due to thermal conductivity and convection (warm fluids have a lower density, they are lighter)
[37][38][11,64].
6.2. Displacement of Oil from the Reservoir by Hot Water and Steam
Hot water and steam, otherwise coolants, are produced in high-pressure steam generators (boilers) and pumped into the formation through injection wells of a special design and with special equipment designed to operate at high temperatures
[39][66]. The disadvantage of using surface steam generators is large losses of heat (temperature) in surface communications and in the wellbore. When the coolant moves along the formation, heat losses occur through the roof and bottom of the formation. To reduce heat loss, layers with a thickness of more than 6 m are chosen, and areal grids of wells are used at a distance of up to 100–200 m between injection and production wells. The perforation interval is chosen in the middle part of the formation; the pipes are insulated, and the steam generator is brought as close as possible to the wells
[40][67].
6.3. Thermal Rim Method
According to this technology, instead of continuous injection of the coolant after its penetration into the formation, after a certain time, water is pumped at the formation temperature. A heated region (thermal rim) is created in the reservoir, which moves from the injection well to the production wells under the influence of cold water injection into the reservoir
[41][73].
In this case, when oil is displaced by a thermal rim, three displacement fronts are formed in the reservoir: 1—hydrodynamic-displacement of unheated cold oil by water; 2—thermal front-displacement of heated oil of low viscosity with hot water; 3—hot oil displacement front with cold water. Moreover, the 3rd front of hot oil displacement by cold water will lag behind the previous two. The heat of the hot oil will be transferred to the cold water, i.e., the reverse process of heat transfer will take place in the direction of the injection well. The viscosity of the displaced oil will increase, and the mobility coefficient will decrease. Unrecovered oil reserves will remain in the reservoir
[42][74].
7. Combined Technologies for Enhanced Oil Recovery in Deposits with High-Viscosity Oils
7.1. Thermopolymer Formation Stimulation (TPV)
The TST technology is based on the injection of a PAA solution with a concentration of 0.05–0.1%, heated to a temperature of 90–950 °C, into the reservoir
[43][78]. The viscosity of a heated aqueous solution of polyacrylamide is 1.5–2 mPa∙s. The viscosity of oil in the fracture system decreases, and part of the hot solution, mainly hot water, impregnates the blocks, improves the hydrophilicity of the rock, increases the mobility of the oil, and thereby leads to its displacement.
7.2. Steam-Cycling Treatment of Production Wells
Steam-cycling treatment of production wells refers to the methods of intensification of inflow (MIP). During steam cycling treatments, steam is pumped into a production well for 15–20 days in a volume of 100–300 tons per 1 m of formation thickness
[44][81]. Then the well is closed for 10–15 days to redistribute heat and countercurrent capillary displacement of oil from low-permeability interlayers (LP) into a high-permeability interlayer. Further, the well is operated until the maximum profitable production rate is reached within 2–3 months.
The physical essence of the process is as follows: steam liquefies high-viscosity oil and increases the oil mobility coefficient
[45][82]. Depending on the change in temperature and pressure, the steam first passes into a two-phase state of steam-water, then after condensation, into hot water, which, invading low-permeability layers, reduces the viscosity of the oil located there. After the well is stopped, as well as during cyclic waterflooding, water begins to displace oil from the OR to the WP
[46][83]. At the third stage of the good operation cycle, the pressure in the bottom hole zone drops, and the oil recovery increases due to its greater mobility. Thus, the technology implementation cycle consists of three stages.
7.3. In Situ Combustion
In situ, combustion (IG) is based on the ability of hydrocarbons (in this case, oil) to chemically react with oxygen. As a result of combustion, a large amount of heat is released in the reservoir; the temperature rises, and the physical properties of reservoir fluids and rock change. Unlike other thermal methods of enhanced oil recovery, HSV eliminates technical problems and heat losses that occur when it is generated on the surface and delivered to the reservoir by injecting heat carriers into it
[47][48][13,86]. The call of combustion is carried out at the bottom of the well—the incendiary. An oxidizing agent (usually air) is pumped into the injection well while simultaneously heating the bottom hole formation zone using a downhole electric heater, gas burner, incendiary chemical mixtures, etc.
7.4. Dry In Situ Combustion
In dry in situ combustion, only air is injected to sustain combustion. The main part of the heat generated in the reservoir (80% or more) remains in the area behind the combustion front and is gradually dissipated into the rocks surrounding the reservoir. This heat has a certain positive effect on the process of displacement from adjacent parts of the reservoir not covered by combustion
[49][50][60,92].
It has been established that in the case of maintaining in situ combustion by injecting only a gaseous oxidizer (air) into the formation, heat loss from the rock heated as a result of combustion occurs more slowly due to the low heat capacity of the airflow than when the rock is heated by a moving combustion front. When the combustion front moves, a part of the oil that remains in the reservoir after its displacement by combustion gases, water vapor, water, and evaporated light fractions of oil ahead of the combustion front is consumed as fuel
[51][93].
7.5. Wet In Situ Combustion
The combination of in situ combustion and flooding is called wet in situ combustion. The essence of wet combustion lies in the fact that water injected along with the air in certain quantities, evaporating in the vicinity of the combustion front, transfers the generated heat to the area in front of it, as a result of which extensive heating zones develop in this area, formed by zones of saturated steam and condensed hot water. The process of in situ steam generation is one of the most important distinguishing features of the wet combustion process, which determines the mechanism of oil displacement from reservoirs
[37][52][53][11,96,97].
The values of the ratios of the volumes of water and air injected into the reservoir are within the limits of 1–5 m
3 of water per 1000 m
3 of air (under normal conditions), i.e., the water–air factor should be (1–5)∙10–3 m
3. The specific values of the water–air factor are determined by various geological and field conditions for the implementation of the process. However, with an increase in oil density and viscosity (more precisely, with an increase in coke concentration), the required water–air factor decreases
[54][98].
The combustion front is characterized by the highest temperature—here, it reaches 370 °C and above. As the combustion front moves in the reservoir, several characteristic, distinct temperature zones are formed
[55][100]. In the scorched region behind the combustion front, two temperature zones are distinguished. In the transition zone, the temperature changes from the temperature of the injected working agents (water and air) to the evaporation temperature of the injected water. Directly adjacent to the combustion front is a zone of superheated steam formed as a result of the evaporation of water injected together with air in the rock, heated to a high temperature by the combustion front moving ahead
[56][101].
Heat transfer to the area ahead of the combustion front is carried out during wet combustion mainly by convective transfer by flows of evaporated injected water and combustion products, as well as by heat conduction. As a result, several temperature zones are formed ahead of the combustion front
[57][102]. A zone directly adjacent to the combustion front has superheated steam, within which the temperature drops from the temperature of the combustion front to the temperature of condensation (evaporation) of the steam. The size of this zone is relatively small because heat losses in the rocks surrounding the reservoir led to rapid cooling of the gaseous water vapors filtered here and combustion products, which are characterized by low heat capacity
[58][103]. The main share of the heat transferred to the area ahead of the combustion front is concentrated in the zone of saturated steam—the zone of the steam plateau. There is heat loss to the surrounding rocks, accompanied by steam condensation in the transitional temperature zone. A hot water zone formed as a result of the complete condensation of saturated steam. The temperature in the saturated steam zone depends mainly on the level of reservoir pressure, taking into account the proportion of steam in the gas flow. Usually, within this zone, it varies insignificantly and is approximately 80–90% of the saturated vapor temperature
[59][104]. The temperature in the transition zone varies from the steam condensation temperature to the initial reservoir temperature
[60][105].
7.6. The Method of Thermal Gas Exposure
The method of thermal gas exposure (TGT) refers to thermal methods
[61][120]. It is used in light oil fields with elevated temperatures above 650 °C and high reservoir pressures; similarly to in situ combustion, nitrogen, carbon dioxide, and light oil fractions act as displacing gaseous agents that mix with oil and provide an increase in its mobility. This contributes to an increase in the oil recovery factor, especially when developing deposits with hard-to-recover reserves
[62][121].
8. Other Methods of Enhanced Oil Recovery
8.1. Hydraulic Fracturing (HF)
One of the commonly used methods of enhanced oil recovery is hydraulic fracturing. Hydraulic fracturing technology and well development after hydraulic fracturing are discussed in detail in
[63][64][123,124].
We consider the process of crack formation. It is known from continuum mechanics that in an elastic medium, a crack is formed in the plane of the highest normal stress, that is, in the plane in the direction of the rock stress
[43][78]. Therefore, the crack is vertical. It propagates in the direction of the minimum normal stress, that is, in the direction radial from the well.
The choice of a good operation mode is determined by the results of hydrodynamic studies of wells after hydraulic fracturing. The performance of the ESP unit size should correspond to the good productivity factor determined after hydraulic fracturing
[65][126].
The fracture created in the reservoir is filled with proppant, which does not allow it to close. Thus, a two-capacitive system formation–fracture is created in the reservoir. A fracture filled with proppant is a fictitious reservoir since the diameters of the proppant particles are the same
[66][127].
8.2. Operation of Wells with Horizontal Completion
The development of engineering, technology and new scientific methods in drilling contributed to the construction and operation of horizontal wells
[67][133]. In the literature, an incorrect definition of such wells is used: horizontal wells (HW), implying that only the horizontal part of the well that has penetrated the productive formation is in operation. A large number of works have been devoted to determining the mining capabilities of HS. There are several hydrodynamic models that describe the flow of fluid from the reservoir to the horizontal part of the well, the length of which can reach 600 m or more. As a rule, horizontal wells are used to extract oil from low-permeability differences that are not involved in development
[68][69][70][16,94,134].
8.3. Acoustic Methods
According to the technology of their use, acoustic methods can be divided into MIP and EOR. The former has an impact on the bottom hole zone, improving reservoir properties and well productivity. The latter affects the element, part of the production facility, involving the development of uncovered areas and capillary-retained oil
[71][138]. Recently, the development of technology has allowed various technologies to aim at the development and improvement of acoustic methods of influencing the BFZ.
9. World Experience in Using MIP and EOR
As it was presented, in the modern world, often all geological and technical measures (GTO) at wells can be attributed to EOR
[72][154].
After analyzing a number of publications
[73][74][75][155,156,157], the authors came to the conclusion that today only, less than 5% of the world’s oil production is accounted for by projects to increase oil recovery by tertiary methods. At the same time, EOR is one of the methods of oil production that increases the productivity of oil wells. It is carried out with artificial maintenance of reservoir energy or artificial change in the physical and chemical properties of oil)
[76][158]. Annual production through the use of such methods in the world is estimated at about 150 million tons. Additionally, with the help of EOR, you can obtain much more, hundreds of billions of barrels of oil
[77][159].
The same can be said about the injection of hydrocarbon gases, which is EOR only in cases of targeted oil displacement through the reservoir, and the usual injection into the gas cap through single wells to maintain reservoir pressure or utilize excess associated gas has always been a secondary development method, which is quite natural from physical principles
[78][162].
Enhanced oil recovery (EOR) technology enhances oil production from mature and aged oil fields by almost 10 to 20 percent when compared to conventional oil extraction methods. Mature wells are those oil reserves where production has reached its peak and have started to decline to owe to poor permeability or exhibiting heavy oil. Technically, EOR increases the permeability of the reservoir so that hydrocarbons can flow through the pathways easily and into the targeting-producing well.
Today, such boundary definitions have become vague, largely due to opportunistic considerations, and many authors allow free terminology and definitions. For this reason (different positions towards the EOR classification), different statistical sources contain radically different data on the number of EOR projects and the volume of oil production in them
[79][163].
In general, it can be stated that the general trend is an increase in the share of EOR gas projects, moreover, due to the use of carbon dioxide injection technologies while reducing projects for the injection of other gases
[80][166]. At the same time, almost all growth was provided by the development of CO
2 projects in the USA, the number of which reached 133. In general, it should be noted that the share of EOR projects in the USA (about 220) is exceptionally large and amounts to 60% of the global number of operating EORs in the world
[81][167].
Differences in estimates of the number of EOR projects are primarily associated with different approaches to projects for the production of heavy (heavy oil) and extra-heavy (extra-heavy oil) oil, as well as with the allocation of production due to thermal technologies from all heavy oil production in the project (often all production, including the stage of “cold” production by horizontal wells, is attributed to EOR)
[82][168].
A conservative assessment implies the exclusion of projects with extra-viscous oil (density less than 10 °API, which is directly indicated in the primary sources of publications), considering them as a separate category of hydrocarbons together with bitumen, more strict consideration of additional production in projects of heavy oil and gas methods
[83][170].
The share distribution of oil production volumes due to different EOR groups differs from the structure of the number of EOR projects; thermal EOR continues to play the first role, although there is a downward trend
[84][173]. The share of production through chemical technologies is growing noticeably, reaching 17–19%, significantly exceeding their weight share in the number of projects. This is due to the large-scale implementation of polymer and ASP flooding in China
[85][174].
In technological terms, the unrealized potential of EOR in all oil-producing countries is large. However, the general situation with EOR in the world indicates that in the context of globalization of the economy, and even more so at the time of the transformation of the world economy (multi-vector development of the fuel and energy complex, “energy turn”), EOR has no real prospects for large-scale development. First of all, due to large initial capital investments and long payback periods for projects, moreover, with increased technological risks of errors in forecasting the achieved levels of oil production. Statements about the need for special economic mechanisms for the implementation of EOR technologies have become commonplace. However, specific and effective solutions have not been developed or adopted in almost any country in the world today, perhaps with the exception of China
[86][176].
It is also important to note that over the past thirty years, there have been no fundamental successes in the development of EOR technologies in the world. All technological foundations of EOR are known, and it can be argued that there is only some modernizing development of them “in breadth” towards an evolutionary expansion of the conditions of applicability in terms of temperature and permeability of the formation, in terms of salinity of formation water. This is determined by the immutability of the scientific foundations of EOR and the lack of new fundamental research on capillary—chemical and rheological—in situ processes of oil displacement.