Experience in replacing oil with carbon dioxide abroad. Displacement of oil by injection of hydrocarbon and liquefied gases
Due to the depletion of easily recoverable oil reserves, all great effort are aimed at creating technologies and development methods that make it possible to produce hydrocarbons in difficult conditions. By using carbon dioxide as a displacing agent, a significant increase in oil recovery can be achieved. The greatest effect when displacing oil with carbon dioxide is achieved with miscible displacement, which is possible at reservoir pressure above the miscibility pressure. The displacement of oil by carbon dioxide is a rather complex process in which mass transfer, capillary and gravitational effects appear. The experience of using carbon dioxide to enhance oil recovery in the fields of Russia, Hungary and the USA is considered. The use of carbon dioxide is a promising method for increasing oil recovery if a reliable source is available. It is possible to produce carbon dioxide by burning hydrocarbon gas.
carbon dioxide
enhanced oil recovery method
oil reservoir
field
mixing repression
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Due to the depletion of easily recoverable oil reserves, increasing efforts are being directed towards creating technologies and development methods that make it possible to produce hydrocarbons in difficult conditions. One such method is to displace oil by injecting carbon dioxide (CO2) into the reservoir. Injection of carbon dioxide to enhance oil recovery began to be used in the mid-fifties. During this time, the mechanisms of physical and chemical interaction of carbon dioxide with water, oil and rock were studied; the features of oil displacement using carbon dioxide are determined; advantages and disadvantages compared to other methods of enhanced oil recovery are considered. Unlike other gases, when using CO2 as a displacing agent, a significant increase in the oil recovery factor can be achieved. Under laboratory conditions, with unlimited miscibility, the oil displacement coefficient can reach 100%.
In many ways, the productive effect of using carbon dioxide injection technology is due to the fact that CO2 is able to dissolve in oil and formation water to a greater extent compared to other gases. When dissolved in oil, carbon dioxide helps to increase oil in volume, which in turn helps to displace residual immobile oil. Based on laboratory experiments carried out on oil samples from the Radaevskoye field, it was found that with a mass content of CO2 in oil of 22.2%, its volumetric coefficient increases from 1.07 to 1.33. Injecting carbon dioxide helps reduce interfacial tension at the oil-water interface. When CO2 is dissolved in oil and water, the wettability of the rock with water improves, which leads to the washing of the oil film from the surface of the rock, transferring it from the film state to the droplet state, thus increasing the displacement coefficient. The ability of carbon dioxide to dissolve in water allows part of the CO2, which has better solubility in hydrocarbon liquids than in water, to pass into oil. When carbon dioxide is dissolved in water, the viscosity of the water increases slightly, and the resulting carbonic acid (H2CO3) dissolves some types of cements and formation rocks, increasing permeability. According to the results of laboratory studies at BashNIPIneft, the permeability of sandstones can increase by 5-15%, and of dolomites by 6-75%. The more carbon dioxide there is in the water, the more efficient the oil displacement becomes. The degree of solubility of carbon dioxide in water is influenced by the mineralization of water; with an increase in the degree of mineralization, the solubility of CO2 in water decreases.
Another advantage of carbon dioxide injection is the ability to increase oil mobility. In accordance with the laws of thermodynamics, at a high degree of oil expansion, part of the adsorption layer of oil in the pores is released, the viscosity decreases under the influence of dissolved gas, and the oil becomes mobile. This effect manifests itself to a greater extent when interacting with high-viscosity oils (more than 25 MPa∙s). According to laboratory studies, the higher the initial viscosity value, the greater its decrease (table).
However, in practice, the viscosity of fields where CO2 injection is used does not reach such high values. According to the analysis of carbon dioxide injection projects implemented in the world, the viscosity of oil is in the range of 0.4-3.0 MPa∙s.
In reservoir conditions, depending on temperature and pressure, carbon dioxide can be in a gaseous, liquid, or supercritical state. The critical point is characterized by a temperature of 31.2 °C and a pressure of 7.2 MPa. At temperatures below 31.2 °C, carbon dioxide can be in the liquid phase. The temperature at which carbon dioxide will be in a liquid state can increase to 40 ° C if hydrocarbons are present in the composition. At temperatures above 31.2 °C, CO2 will be in a gaseous state at any pressure. In the supercritical state, the density of carbon dioxide corresponds to the density of a liquid, and the viscosity and surface tension correspond to that of a gas. In this state, CO2 will displace oil with a decrease in the coverage of heterogeneous formations, which is typical for a low-viscosity agent.
It was determined experimentally that it is more efficient to inject carbon dioxide in a liquid state, and the optimal reservoir temperature should be close to the critical value. The greatest effect when displacing oil with carbon dioxide is achieved with miscible displacement, which is possible at reservoir pressure above the miscibility pressure.
The miscibility pressure depends on the composition of the oil and the saturation pressure. With increasing saturation pressure, as well as in the presence of methane or nitrogen in the oil, the miscibility pressure increases. High molecular weight hydrocarbon gases, including ethane, help reduce miscibility pressure. The miscibility pressure of CO2 is significantly lower than the miscibility pressure of hydrocarbon gases. If for the displacement of light oil by carbon dioxide the miscibility pressure will be in the range of 9-10 MPa, then for miscible displacement with hydrocarbon gas it is necessary from 27 to 30 MPa. In the case when the pressure in the formation does not reach the miscibility pressure, the interaction of carbon dioxide and oil produces CO2 containing the light phase of oil and oil without light fractions.
The displacement of oil by carbon dioxide is a rather complex process in which mass transfer, capillary and gravitational effects appear. When carbon dioxide is partially or completely miscible with oil, its rheological properties change, which contributes to the involvement of previously unused oils in development. The process of oil displacement by carbon dioxide is influenced by saturation conditions and previous displacement.
During the period of studying the technology of injecting carbon dioxide into the reservoir in order to increase the oil recovery factor, various approaches to its use were identified:
● injection of carbonated water;
● continuous injection of CO2;
● injection of CO2 slug followed by water injection;
● displacement of oil by alternating injection of CO2 and water;
● displacement of oil by injection of combined slugs of chemical reagents and CO2.
The main advantage of carbonated water injection is the relatively low consumption of carbon dioxide when injected into the reservoir compared to other variations of its use. The optimal concentration of carbon dioxide in water is 4-5%. Laboratory experiments to determine the efficiency of using carbonated water, carried out by UfNII, found that displacement of oil with carbonated water with a CO2 concentration of 5.3% allows for an increase in oil recovery by 14% compared to displacement with tap water.
The advantage of continuous carbon dioxide injection is the achievement of higher displacement efficiency compared to other technology applications. This occurs due to the fact that a shaft of oil is formed in front of the advancing volume of CO2, characteristic of processes occurring during mixing displacement. The disadvantages of continuous injection of carbon dioxide include viscous instability, which in some cases can significantly reduce the sweep factor and lead to early carbon dioxide breakthrough.
Compared to continuous displacement with carbon dioxide, the option of alternating injection of CO2 and water is more economical due to the reduction in volume, and therefore the cost of carbon dioxide. Also, the advantages of alternating injection include the fact that alternating injection of carbon dioxide and water can be effective for heterogeneous formations, depending on the ratio of CO2 and H2O. The literature provides the results of laboratory experiments, but also emphasizes that the effectiveness of each specific project should be based on experimental experience in which the conditions were as close as possible to real conditions. Experts have differing opinions regarding this carbon dioxide injection option. The results of laboratory experiments were published, as a result of which it was concluded that for a homogeneous formation with limited miscibility the best option Compared to alternating injection, there will be an option with injection of a continuous slug. It is also emphasized that alternating injection of carbon dioxide and water reduces the final oil displacement efficiency compared to continuous injection. Based on the results of other experiments, it was determined that for a homogeneous formation, alternating injection is effective, and the optimal rim volume is from 9 to 12% of the pore volume. According to the authors of this article, after analyzing laboratory and industrial experiments, including at the Radaevskoye field, as well as studying scientific works devoted to this issue, the effectiveness of the alternating injection technology has been proven. And the use of this option will be effective for heterogeneous formations, although the degree of effectiveness may vary.
In front of everyone obvious advantages The use of technology to enhance oil recovery by injecting carbon dioxide also has disadvantages. Compared to waterflooding, CO2 injection reduces the sweep factor. To reduce this effect, it is possible to use alternate injection of water and carbon dioxide, as well as selective isolation of certain intervals. In turn, using water alternately with CO2 can lead to the most significant complication that is possible when injecting carbon dioxide - corrosion of equipment in injection and production wells. Another disadvantage of this technology is that with incomplete miscibility with oil, CO2 extracts light hydrocarbons from it, and heavy fractions remain in the oil, as a result of which the oil becomes inactive, and it will be much more difficult to extract it in the future.
The next disadvantage of this technology is that carbon dioxide is a gas that, when saturated with water vapor, can form crystalline hydrates.
As CO2 dissolves in water and oil, a decrease in temperature will be observed. The degree of temperature reduction increases with increasing carbon dioxide concentration. Such a temperature effect when dissolving carbon dioxide can affect the formation of asphaltene-resin-paraffin deposits.
According to some estimates of the technology under study, it is noted that if it is not possible to ensure the delivery of carbon dioxide through affordable price in the required time frame, there is a high probability of missing the opportunity to improve final oil recovery. Ensuring supply at a later stage, when the field is already at a later stage and there is a decrease in reservoir pressure, only immiscible displacement is available, the effect of which is several times lower than with the miscible displacement mode; for some fields such an assessment is quite justified. The lack of an accessible source is a significant limitation for the application of carbon dioxide injection technology. For many fields, the production and transportation of CO2 to the site may not be economically viable.
In the Soviet Union, the first laboratory experiments on the use of carbon dioxide were carried out by VNII and BashNIPIneft. In 1967, CO2 injection in the form of carbonated water was implemented at the Aleksandrovskaya area of the Tuymazinsky field. The total volume of carbonated water injection was two pore volumes with a carbon dioxide concentration of 1.7%. The reservoir coverage by waterflooding in terms of power has been increased by 30%, the injectivity of injection wells has been increased by 10-40%. The specific effect of the amount of injected carbon dioxide per ton of oil produced was 0.17 t/t.
Injection of carbon dioxide at the Radaevskoye field began in 1984. As a result of the implementation of the CO2 injection project at the Radaevskoye field, 787.2 thousand tons of CO2 were injected, which is 2.6 times less than the designed volume for this period. Due to the injection of CO2, by July 1989, additional oil production amounted to 218 thousand tons. The specific effect of the amount of CO2 injected is 0.28 t/t. Difficulties arose when supplying dioxide, which were associated with breaks in the carbon dioxide pipeline. The supply of carbon dioxide was uneven. After numerous breakthroughs, its operation became impossible. This was the main reason for the termination of the experiment in 1988.
As a result of injection of 110 thousand tons of liquid CO2 at the Kozlovskoye field, the specific effect is equal to 0.125 t/t. Similar projects for injection of carbon dioxide into the reservoir were implemented at the Sergeevskoye field in 1984, where the specific effect of injection by July 1989 was 0.23 t/t. The injected volume amounted to 73.8 thousand tons. At the Elabuga field, CO2 injection began in 1987. The total injection volume was 58.3 thousand tons. A project was developed for the Olkhovskoye field. When using this technology, an increase in oil recovery was observed in all cases. However, significant capital investments and a long period before the start of payback of projects, as well as the lack of equipment that could ensure uninterrupted operation when injecting CO2, did not allow further development of the technology during this period.
There is extensive experience in using this technology abroad. Injection of carbon dioxide into reservoirs is actively used by the USA, Canada, Hungary, Turkey, Great Britain and other countries. Already in August 1981, around the world, excluding the countries of the USSR, 27 ongoing projects for CO2 injection, nine have been completed and 63 are planned.
In the USA, the carbon dioxide injection method was tested in 1978 in Texas in Scurry and successfully began to be implemented in the Permian Basin of West Texas and eastern New Mexico. Subsequently, carbon dioxide injection began in other regions, including the fields of the Rocky Mountains, the Midcontinent and the Mexican coast. The bulk of oil production by injection of carbon dioxide is carried out in the Permian Gulf region and amounts to about 62%. The remaining 38% comes from the Rocky Mountain, Midcontinent and Mexican Coast regions. To a greater extent, such indicators are based on the fact that the main deposits of natural CO2 are located in the Permian Basin; accordingly, carbon dioxide can be easily transported through gas pipelines to the nearest depleted oil fields. Considering that operating costs are this region lower than the others, it becomes the most popular for companies involved in CO2 injection.
As of 2014, there are 136 carbon dioxide injection projects being implemented in the world, carried out by 30 operating companies. Of these, 88 are considered successful, 18 are classified as promising projects, the remaining 20 started recently. Ten projects could not be implemented effectively. Most of, namely 128 out of 136, are sold in the United States. The youngest carbon dioxide injection projects include those started in 2014 at the Slaughter (Smith Igoe) field, which is located in Texas, USA, and is served by a large American oil company Occidental. Despite short term, the project is already considered successful, and the increase in flow rate is 2.65 m3/day/well. CO2 injection projects at the Charlton 19 and Chester 16 fields, located in Michigan, USA, developed by Core Energy, also started in 2014.
The Sacroc and Devonian Unit (North Cross) fields are among the most mature CO2 injection projects, having started in 1972 and are yet to be completed. The Sacroc deposit is located in Texas, USA. The development is carried out by Kinder Morgan. Flow rate increase -10.81 m3/day/well. Devonian Unit (North Cross), also located in Texas, USA. The operator company is Occidental. Flow rate increase - 7.84 m3/day/well. . The experience of using miscible displacement in other countries allows us to conclude that if there is an accessible source of CO2, the use of technology can significantly increase the final oil recovery factor of Russian fields.
Bibliographic link
Trukhina O.S., Sintsov I.A. EXPERIENCE OF USING CARBON DIOXIDE TO INCREASE OIL RECOVERY // Advances in modern natural science. – 2016. – No. 3. – P. 205-209;URL: http://natural-sciences.ru/ru/article/view?id=35849 (date of access: 04/27/2019). We bring to your attention magazines published by the publishing house "Academy of Natural Sciences"
When developing oil and gas fields, the energy of initial (static) and artificial (additional) reservoir pressures is used, under the influence of which oil and gas are displaced from the pore space of the reservoir into the well.
The initial reservoir pressure of oil fields is determined by the natural forces of the deposits: the pressure of the contour water under the influence of its mass, the pressure of the contour water as a result of the elastic expansion of rock and water, the pressure of the gas cap on the oil-bearing part of the deposit, the elasticity of the gas released from the oil previously dissolved in it, the gravity of the oil .
However, natural internal views The energy of hydrocarbon deposits, especially oil, does not provide high oil recovery from deposits. In order to increase oil recovery, artificial, additional energy sources are used by injecting water, gas and other reagents into productive formations. Currently, the main type of artificial impact on oil-bearing formations is their edge, edge and intra-side flooding.
Displacement of oil by water is currently the main method of oil recovery, both with and without impact on the formation.
The movement of fluid in an oil-bearing formation occurs through an extremely complex system of branched pore channels of various configurations and sizes.
The main forces that prevent the joint movement of immiscible fluids in the pore space and determine the magnitude of oil recovery are surface (capillary) forces, viscous resistance forces (hydrodynamic) and gravity (gravitational), which act together.
The location and amount of residual oil in reservoirs depends on whether the rock is preferentially wetted by water or oil. The less wetting residual phase in the form of individual droplets is retained in wide areas of the pores. The more wetting displaced phase, on the contrary, remains in narrow parts of the pores and in individual small pores. Each phase (water or oil) moves through its own system of pore channels, maintaining continuity. A particle of liquid can move into a channel occupied by another phase only under very large values external pressure gradient, and this is determined mainly by surface forces.
When oil is displaced by water from heterogeneous formations, oil recovery is strongly influenced by hydrodynamic forces (pressure gradient). The ultimate pressure gradient increases as permeability decreases. Therefore, with an increase in the pressure gradient in the formation, the number of interlayers involved in filtration increases, i.e. the reservoir coverage coefficient by flooding increases.
In a homogeneous formation, displacing water fills primarily small pores, while in a heterogeneous formation it occupies more permeable areas where large pores predominate. The reason for this difference is that on the pore scale of a homogeneous formation, the phase distribution is determined by surface forces, and when layers of different permeability are interlayered, by viscous resistance forces and gravity. However, having filled the highly permeable zones, water begins to be absorbed into low-permeable areas, displacing oil from there. The slower the flow of displacing water, the larger the size of the areas in which capillary equilibrium is established due to the absorption of water, and oil recovery tends to a certain limit.
Rice. 6. Scheme of changes in oil and water saturation of the productive
formation during its boundary flooding.
Nature of saturation of the feather space: 1 – water, 2 – oil;
However, at speeds of injected water movement that are lower than the minimum speed of capillary impregnation of low-permeability zones, oil recovery again decreases due to deterioration of displacement conditions in high-permeability areas.
A special situation arises when viscous plastic oil is displaced from the reservoir. In this case, oil recovery from highly permeable zones increases very sharply with increasing speed of water movement. The maximum of the curve of oil recovery versus water velocity is in the region of real filtration rates, which makes it possible to regulate oil recovery by changing the displacement rate.
Thus, a complex process of simultaneous displacement and redistribution of phases in the pore space of the reservoir occurs, which ultimately does not lead to the complete displacement of oil by water replacing it. In this case, the water saturation of the productive formation increases from the residual water saturation (K VO = 1 – K Н) at the initial oil saturation K Н in the zone unaffected by its development to the maximum value of the current water saturation (K VT = 1 – K HO), corresponding to the residual oil saturation K HO at the initial water injection lines. Based on modern ideas about the displacement of oil by water in a water-filled productive formation during boundary flooding, four zones are distinguished (Fig. 6).
The first zone is the aquiferous part of the formation below the level of oil-water contact (OWC), in which the pore space is completely filled with water. In the second zone, water saturation changes from maximum to the value at the oil displacement front. Section IIa is located on the initial water injection line and is characterized by residual oil saturation. Section IIb is represented by a zone of oil-water mixture, in which oil is gradually washed out. The third zone, the size of which can reach several meters, is the transition zone from water to oil. It is generally considered stabilized. The fourth zone is the undeveloped part of the formation.
During intra-circuit flooding of the productive formation, there are zones II, III and IV. Section IIa is located directly around injection well.
1. What happens to the oil in the reservoir when it is displaced by water?
2. Is it possible to displace oil from a reservoir with gas or other reagents?
Original document?
LECTURE 13
INCREASING OIL RECOVERY
1. Methods for increasing recoverable reserves
Enhanced oil recovery is a complex problem, the solution of which uses experience accumulated in all areas of the oilfield business. In the first place, of course, is the correct placement of wells on deposits, taking into account the geological structure of the formations and the implementation of regulation of the waterflooding process based on regular hydrodynamic studies of wells. The efficiency of reservoir operation is improved as a result of influencing the bottom-hole zones of the formation in order to increase flow rates and level out the oil and gas inflow profile, as well as the injectivity of injection wells, if any, to artificially maintain reservoir pressure. The efficiency of waterflooding can be significantly increased if chemical reagents are added to the injected water to facilitate more complete displacement of oil from the subsurface. All secondary and tertiary methods for increasing oil recovery are based on the use of certain physical laws discussed in previous lectures.
Depending on the conditions of occurrence of oils, their properties and composition. and also, based on economic feasibility, they use various technologies for the extraction of hydrocarbons. Of the most known technologies can be called injection of coolant into the reservoir to reduce the viscosity of oil. The same goal is pursued by injecting into the formations liquefied gases, which are oil solvents. The phenomenon of reverse evaporation and condensation of heavy hydrocarbons in a gaseous environment is used to develop technology for injecting high-pressure gases into the reservoir, which helps transfer part of the oil fractions into the vapor phase.
To equalize the mobility of water and displaced oil, quenched water is injected into the formations. To enhance oil recovery, foams stabilized by surfactants and movable combustion sources are used. Ultrasonic, vibration, and electrical methods of influencing the near-well zones of the formation are being studied.
2. Detergents and oil-displacing water properties
Waterfloodingdeposits is the main way to increase the efficiency of oil fields. But even with all its effectiveness, more than half of the oil reserves remain in the ground. One of the ways to increase the efficiency of waterflooding may be to inject water with high displacement properties into the reservoir. In accordance with modern concepts, the mechanism of the cleaning action of substances in relation to washing hydrocarbons from minerals is determined by their ability to improve the wetting properties of water and reduce their surface tension at the interface with oil and other surfaces. They must be disruptors of suspensions and emulsions, etc.
Depending on the structure and properties of the formation rocks, as well as the state of fluids in the porous medium, the parameters of the displacing fluid affecting oil-displacing properties may not be the same. If, for example, oil in a reservoir is in a dispersed state, then water characterized by low values surface tension at the interface with oil and well wetting the rock.
When flooding fractured reservoirs, it is advisable to use water with high wetting tension values (s× CosQ), capable of being intensively absorbed by capillary forces into blocks of rock broken by cracks.
However, the processes of water absorption into oil-saturated breeds are accompanied by the formation water-oil mixtures that negatively affect oil recovery due to disruption of the continuity of the oil phase. Such mixtures are formed less intensively when waters with low values (s× CosQ). If this is so, then under conditions of neutral (intermediate) wettability, when the contact angle is close to 90° , A shas minimal values, the oil recovery factor should increase. Such waters have bad cleaning properties, but their displacement capacity is the highest. In this regard, preference should be given to formation waters produced along with oil, and they should be injected back into the formations after appropriate treatment. Fresh water used to maintain reservoir pressure better wets the rock surface and forms more stable emulsions in contact with oil. In addition, they contribute to the swelling of clay cement, which is part of terrigenous reservoirs, and a decrease in the volume of pore space. True, some scientists believe that in this case oil is squeezed out of the shrinking filtration channel, but judging by the results of laboratory experiments given in their works, this is not so. It is much easier to explain the resulting effect by simply redistributing filtration flows by changing the structure of filtration channels.
In terrigenous reservoirs of fields in Udmurtia, where the content of clayey matter is insignificant (0-5%), a decrease in permeability during filtration of fresh and slightly mineralized waters is associated with an increase in the thickness of the layer of loosely bound water at the surface of the filtration channels. When the gas permeability of rocks changes from 0.2 to 0.9 μm 2, the relative decrease in permeability for fresh water compared to mineralized water averages 55%, varying from 34 to 75%.
Similar figures for changes in permeability for fresh water in relation to formation water (on average 46% with a range of changes from 29 to 67%) were obtained during experiments on sandstone deposits in Bashkiria, characterized by gas permeability from 0.3 to 0.9 μm 2.
The conducted studies indicate a decrease in the permeability of quartz silty sandstones containing a small amount of clay cement due to changes in the chemical composition of the injected water, which affects the thickness of the diffuse layer of bound (loosely bound) water on the surface of the filtration channels. As water filtered in a porous medium is desalinated, the thickness of this layer increases in accordance with (1), which leads to a decrease in permeability. With increasing mineralization of the injected water, the permeability of the rock increases again. Control measurements gas permeability measurements made after the studies showed that no structural changes in the structure of the pore space of the rocks occurred, and their absolute permeability did not change. More precisely, the average deviation was± 7.5%, which is within the error of permeability assessment in laboratory conditions.
,(1)
Where Dh- change in the thickness of the layer of bound water;
a - degree of electrolyte dissociation;
n - the number of ions into which the electrolyte molecule breaks up;
m - fluid viscosity;
r- radius of ions;
K is Boltzmann's constant;
T - absolute temperature;
m- mass of ions;
WITH 1 and C 2 - molar concentrations of salts in formation and injection water.
The mechanism of the process that causes a change in the water permeability of a porous medium is associated with cation exchange on the surface of clay particles that make up the cement of the rock. In this case, two types of interaction of the solution with minerals are possible. In the first case, when solutions containing the same cations as the complex absorbed by the clay substance are filtered, cation exchange is practically absent. The composition of the complex absorbed by minerals does not change, and the change in the thickness of the diffuse layer is determined primarily by the difference in salt concentrations in the injected and formation (bound) water.
In the second case, the change in permeability will be determined by the type of cations entering or leaching from the absorbed complex and the difference in the concentrations of formation water and injected fluid. The greatest changes in permeability are observed in the case of predominance of sodium cations in the absorbed complex.
| Sample No. | Permeability, µm 2 | Relative reduction in permeability, |
|
| For NaCl solution | for fresh water | ||
| 1878 | 0,230 | 0,096 | |
| 1879 | 0,136 | 0,034 | |
| 1881 | 0,018/ 0,012 | 0,013 / 0,0073 | |
| 1883 | 0,131 | 0,046 | |
| 1883a | 0,014 | 0,006 | |
| 3806 | 0,045 / 0,058 | 0,023 / 0,038 | |
| Average | |||
Note: the denominator indicates the permeability values of the second injection cycle of mineralized and fresh water.
In this regard, to restore the injectivity of injection wells developing deposits in terrigenous reservoirs, to maintain reservoir pressure, it is advisable to use water that has mineralization and a chemical composition close to the composition of reservoir water.
Moreover, to improve the filtration characteristics of reservoirs for injected water, you can add components containing chloride salts of polyvalent metals (for example, AlCl 2, FeCl 3) or sulfate (for example, Na 2 SO 4, K 2 SO 4), or nitrate ( for example, NaNO 3, KNO 3) additives that help reduce the thickness of the layer of loosely bound water and increase the permeability of rocks.
3. Treatment of water with surfactants
The necessary changes in the surface and wetting properties of liquids and the characteristics of phase interfaces in a porous medium can be achieved by adding surfactants to water.
Most surfactant molecules consist of long hydrophobic hydrocarbon chains with low residual affinity at one end and hydrophilic polar groups with high affinity at the other. Based on their chemical characteristics, all surfactants are divided into anionic active ones, cationic and nonionic substances. If the hydrocarbon part of the molecule of an ionic surfactant is part of an anion formed in an aqueous solution, the compound belongs to anionic active substances. Accordingly cationic substances form in aqueous solutions cations containing long chains of hydrocarbon radicals. Does not contain nonionic substances non-ionizing hydrophilic end groups. The surface activity of these substances is due to the peculiar structure of their molecules, which have an asymmetric (diphilic) structure, consisting of polar and non-polar groups. The non-polar and water-insoluble part of the molecule is the hydrophobic alkyl, aryl or alkylaryl radical, and the polar water-soluble represents the group polyethylene glycol or propylene glycol remainder.
A common nonionic surfactant is OP-10, on which great hopes were pinned fifteen to twenty years ago. Example cationic The surfactant is carbozoline O, which is used to hydrophobize sandstones. Anionic ones include: sulfonol NP-1, NP-3, sulfonates, etc.
The effect of various chemical additives on oil recovery was tested under laboratory conditions. At present, it has become clear to almost everyone that there is no universal means for increasing oil recovery. The same reagent behaves differently under different conditions. The table shows the results of laboratory studies of various reagents used to enhance oil recovery in field conditions Ural-Volga region. These studies were carried out in PermNIPIneft, BashNIPIneft, UdmurtNIPIneft, Giprovostok.
| Technology (rims of solutions of chemical reagents without detailed modifications) | Relative increase in coefficient oil displacement |
|
| Range of change | Average |
|
| Nonionic surfactants (type OP-10) from the beginning of the waterflooding process at post-washing of residual oil | 0 - 0,11 0 - 0,12 | 0,055 0,019 |
| Anionic surfactants (in carbonates) | 0 - 0,34 | 0,156 |
| The same (in terrigenous rocks) | 0 - 0,13 | 0,044 |
| Alkalis and compositions based on them | 0 - 0,38 | 0,155 |
| Polymers | 0 - 0,28 | 0,113 |
| Carbon dioxide | 0,05 - 0,28 | 0,122 |
The table shows that any technology may turn out to be completely ineffective under certain conditions, while another may have a positive effect. A striking example are anionic surfactants, which are practically ineffective in terrigenous reservoirs, while in carbonates they give very noticeable increases in the coefficient oil displacement.
Surfactants are adsorbed to varying degrees by the rock surface. Quantitative relationship between the specific adsorption of G in the surface layer, the change in surface tension with the concentration of the dissolved substance and the concentration With installed Gibbs equation
Where R- universal gas constant
T- absolute temperature.
The value characterizing the ability of a solute to reduce the surface tension of a solution is usually called surface activity
The amount of surface activity can be determined from the adsorption isotherm Г=f (C) and the dependence of surface tension on the concentration of the dissolved substances=f(C).
Initially, the surface tension quickly drops, and as the surface layer is filled with adsorbed molecules, the change s with increasing surfactant concentration it decreases and when adsorption reaches a constant value corresponding to complete saturation of the layer with surfactant molecules, it stops. Therefore, the surface activity of a surfactant is assessed by the value
those. the initial value of G 0 with the surfactant concentration tending to zero. The SI units of surface activity are H× m 2/kmol.
1 mN × m 2 /kmol=1Gibbs=1Dyn/cm/(mol/dm 3)
The most suitable for treating injected water are surfactants that significantly reduce the surface tension at the interface with oil at low concentrations, improve the wettability of the rock surface, low-absorbing on it and destructive water-oil emulsions. In addition, they must be cheap, completely soluble in fresh and formation water, and resistant to formation water salts. Mixtures of various surfactants usually have the best performance. In this regard, the main task of laboratory research becomes the selection of the best compositions for specific oil conditions. A huge amount of research requires a lot of time and money and therefore is rarely implemented in full.
The use of surfactants in industrial volumes to increase oil recovery encounters significant difficulties due to their adsorption by the huge surface of filtration channels. It should, however, be taken into account that as a result of water filtration following the rim of the chemical solution, partial desorption of the substance occurs and its transfer to other parts of the formation.
On the other hand, if adsorption did not occur, then the mechanism of action of the surfactant could not be fully realized. The results of studies of the effectiveness of polymer flooding using substances that reduce the adsorption of the active reagent on the rock surface are known, indicating the absence of a technological effect.
4. Alkaline flooding
Alkali solutions are injected into the formations in the form of slugs, propelled by fresh water. The mechanism of action of alkaline rims is associated with the formation of surfactants as a result of the interaction of alkali with oil, leading to a decrease in surface tension at the boundary of the solution with oil, hydrophilization of the surface of rocks (terrigenous to a greater extent). Due to the emulsification of oil, additional hydrodynamic resistance is created, contributing to an increase micro- and macro-sweep of the formation by waterflooding. Currently, field tests of alkaline flooding and its modifications are being carried out, expressed in the creation of mixtures of alkalis with various types Surfactants, thermo-alkaline flooding, etc. The effectiveness of alkaline flooding is closely related to the activity of oils, which depends on the content of acidic components in them that react with alkalis. The more active the oils, the more the surface tension at their interface with the alkali solution decreases.
5. Polymer flooding
Thickeningwater by adding to it water-soluble polymers are aimed at leveling the displacement front by eliminating or reducing viscous instability and preventing premature breakthrough of injected water into production wells. In this case, the main property of polymer solutions to resist the force applied to them is realized.
The higher the filtration rate of the polymer solution, all other things being equal, the higher the resistance factor. The magnitude of the resistance factor is determined by the ratio of the mobility of the polymer solution to the mobility of water. Another important indicator of the likely effectiveness of the method is the residual resistance factor, which is determined after washing the porous medium with water and desorption or destruction of the previously injected polymer. Due to the fact that in real conditions polymer flooding is ineffective due to a sharp decrease in filtration rates as the slug moves away from the injection well, the technology is not used anywhere in its pure form. It is used in combination with the injection of chemical compositions with self-regulating viscosity. Such reagents reduce their viscosity upon contact with oil and increase it upon contact with water, which makes it possible to most effectively displace oil in real hydrocarbon occurrence conditions, when the geological structure and reservoir properties of rocks change sharply within the deposit.
6. Use of carbon dioxide to increase oil recovery from reservoirs
Carbon dioxide, dissolved in water or introduced into the formation in liquid form, has a beneficial effect on the physical and chemical properties of oil, water and reservoir, which helps to increase oil recovery from formations.
CO 2 is a colorless gas heavier than air with a relative density of 1.529. Critical temperature 31.1° WITH; critical pressure - 7.29 MPa; critical density is 468 kg/m3. At a temperature of 20° WITHunder a pressure of 5.85 MPa it turns into a colorless liquid with a density of 770 kg/m 3. With strong cooling, CO 2 solidifies into a white snow-like mass with a density of 1650 kg/m 3, which sublimes at a temperature of -78.5° WITHand atmospheric pressure. The surface tension of liquid carbon dioxide decreases with increasing temperature.
| Temperature, ° WITH | ||||
| Surface tension, mJ/m 2 | 16,54 | 4,62 | 1,37 | 0,59 |
The solubility of carbon dioxide in water increases rapidly with increasing pressure. An increase in water temperature and salinity is accompanied by a decrease in CO 2 solubility. As the concentration of carbon dioxide increases, the viscosity of water increases. For example, at a temperature of 20° WITHand a pressure of 11.7 MPa, the viscosity of carbonated water is 1.21 MPa× With. The solubility of carbon dioxide in oils is a function of pressure, temperature, molecular weight and composition of the oil. As the molecular weight of hydrocarbons decreases, the solubility of CO 2 in them increases. With very light oils, CO 2 mixes completely at pressures of 5.6-7 MPa. Heavy oils do not completely dissolve in liquid carbon dioxide. The insoluble residue consists of resins, paraffins and other heavy hydrocarbons. With an increase in the ratio of the volume of liquid carbon dioxide to the volume of oil in the mixture, the solubility of oil increases.
To increase oil recovery, liquefied carbon dioxide is injected in the form of a slug and pushed through carbonated water. In this case, mutual dissolution of carbon dioxide in oil and hydrocarbons in liquid carbon dioxide occurs with corresponding changes in their properties. The viscosity of the oil decreases, and its volume increases, and the surface tension at the oil-water boundary decreases. For example, the increase in the volume of Arlan oil at a CO 2 concentration equal to 25% by weight reaches 30% at a temperature of 24° WITHand a pressure of 12 MPa, and its viscosity decreases from 13.7 MPa× from up to 2.3 mPa × c. Significant extraction of light hydrocarbons from oil is observed at temperatures and pressures above critical for CO 2 and therefore the process is similar to the process of retrograde evaporation of light fractions of oil into a phase enriched with carbon dioxide.
According to the results of laboratory studies, when the volume of the liquid carbon dioxide slug is 4-5% of the pore volume, oil recovery increases by more than 50% compared to conventional flooding. Injecting carbonated water allows, under favorable conditions, to increase the coefficient oil displacement compared to conventional flooding by almost 30%. Carbon dioxide is an effective means of increasing oil recovery from carbonate and terrigenous formations in which the reservoir pressure is 5.6 MPa or more and the temperature varies within 24 -71° C. The positive effect of carbon dioxide on oil recovery is also a consequence of its active chemical interaction with the rock. As a result of this interaction, the permeability of the rock may increase. Under the influence of carbon dioxide, the acidity of clay minerals increases, which promotes their compression and prevents swelling. Industrial experiments on injection of CO 2 into productive formations have yielded encouraging results.
7. Thermal methods for increasing oil recovery
For the first time, experiments on thermal effects on reservoirs in Russia began in the 30s. When injected into the reservoir hot water An increase in temperature causes a decrease in oil viscosity, a change in molecular surface forces, expansion of oil and rocks, and an improvement in the wetting properties of water. At the beginning of the process, hot water injected into the formation quickly releases heat to the rock, cools down to the formation temperature, and therefore a zone of cooled water is formed between the displaced oil and subsequent portions of the coolant.
Consequently, oil is practically displaced by water at reservoir temperature. The influence of the coolant on the efficiency of oil displacement begins to affect the later water period of reservoir development.
The movement of hot water in the formation is accompanied by a decrease in filtration resistance in the heated zone. The wettability of the surface improves, the intensity and role of capillary redistribution of liquids increases.
If a decrease in oil viscosity helps to increase oil recovery, then the intensification of capillary processes at the displacement front can have a significant negative impact on oil recovery. These phenomena can occur at low temperatures of the coolant in the formation (up to 80-85° WITH).
If superheated water vapor is injected into the formation, the formation is first heated due to the heat of superheating. In this case, the temperature decreases to the temperature of saturated steam, i.e. to the boiling point of water in reservoir conditions. Next, the latent heat of vaporization is consumed to heat the formation and then the steam condenses. In this zone, the temperature of the steam-water mixture and the formation will be equal to the temperature of the saturated steam until all the latent heat of steam formation is consumed. The formation will then be heated by the temperature of the hot water until its temperature drops to the initial formation temperature.
Another method thermal effects is the implementation of the in-situ combustion process. Oil is displaced by hot gaseous products of combustion of part of the oil, heated by water and steam. The total result of the impact of a moving combustion source in a formation consists of numerous effects that contribute to increased oil recovery.
First of all, light hydrocarbons are released, condensing in the unheated zone of the formation ahead of the combustion front and reducing the viscosity of the oil. The condensing moisture then forms a zone of increased water saturation; thermal expansion of liquids and rocks occurs, permeability and porosity increase due to the dissolution of cementitious materials; carbon dioxide formed during combustion dissolves in water and oil, increasing their mobility; Heavy oil residues undergo pyrolysis and cracking, which increases the yield of hydrocarbons from the reservoir.
The successful implementation of the process is facilitated by the uniform distribution of oil in the formation, high permeability and porosity of the rocks. More stable combustion sources occur in formations containing heavy oils with a high content of coke residue. Increased water saturation formation complicates the process. The heat wave generated during combustion is characterized by a temperature curve that has two falling wings with a maximum between them, corresponding to the temperature of the combustion source. According to laboratory data, its value reaches 550-600 ° C. The frontal wing of the temperature curve appears during the combustion of coke and partly oil due to the spread of heat by convective transfer by combustion products and condensation of hydrocarbon vapors and water due to thermal conductivity. After the moving combustion source, heated rock remains, which is gradually cooled by the oxidizer moving here. According to laboratory experiments, the thermal wavelength reaches several tens of centimeters. The speed of the wave depends on the flux density of the oxidizer and the concentration of oxygen in it and can vary from units to tens of meters per day. It is believed that when implementing the described technology, oil recovery can reach 70-85%.
8. Displacement of oil from the reservoir with solvents
The basis of the mechanism for displacing oil with solvents is the absence of surface tension at the interface with oil, which, in essence, does not exist. A solvent such as propane is pushed through by a cheaper agent. As the solvent slug moves, it is eroded from one edge by oil and from the other by a displacing agent. The degree of mixing of a liquid is characterized by the dispersion coefficient D, which is called the convective diffusion coefficient or mixing coefficient. This coefficient depends on the speed of movement and can exceed the molecular diffusion coefficient by several orders of magnitude. The process is greatly influenced by the difference in the densities of oil and solvent due to the curvature of the contact surface and the formation of gravitational tongues. The optimal size of the fringe, necessary to maintain its continuity until the displacement front approaches the production wells, for various conditions should be determined by special studies that take into account the specifics of the deposit. In practice, the sizes of solvent rims range from 4 to 12% of the pore volume.
The efficiency of the process is greatly influenced by the composition of the oil and the saturation of the pore space with various phases. If there is free gas in the oil part of the formation, the process slows down due to the mixing of propane with gas and the deterioration of its qualities as a solvent. A significant decrease in process efficiency is observed when there is a large amount of water in a porous medium.
The water blocks some of the oil, which then loses contact with the liquid propane. In such conditions, you can use solvents that are miscible with both water and oil, for example, alcohols. Following the slug, it is most rational to inject gas into the formation that is highly soluble in the solvent.
If the slug is propelled through the formation by gas, then liquefied liquids are usually used as a solvent. propane-butane mixtures and other heavier hydrocarbons.
The composition of the solvent must be chosen so that unlimited mutual solubility of the slug in oil and gas is observed. Under this condition, phase boundaries do not appear in the porous medium and oil is displaced more efficiently. To carry out mixed displacement of oil by a slug, it is necessary to select a composition of solvent hydrocarbons in which they are in a liquid state under reservoir conditions.
9. Displacement of oil by high pressure gas
According to experimental data, at some very high pressures, almost all components of oil dissolve in gas, with the exception of tarry and other heavy components. By then extracting this gas, which contains vapors of oil or its components, condensate can be obtained on the surface, which precipitates when the pressure decreases. Thus, the essence of the method lies in the artificial transformation of the deposit into gas condensate. In practice, this technology is difficult to implement, because to dissolve all the oil, very high pressures (70-100 MPa) and huge volumes of gas are required (up to 3000 m 3 under normal conditions to dissolve 1 m 3 of oil).
Reverse evaporation pressures are significantly reduced if the injected gas contains heavy hydrocarbon gases - ethane, propane or carbon dioxide. But the volume of gas required remains high. The process can be significantly simplified and cheaper if the most volatile fractions of oil are extracted. To do this, smaller volumes of dry gas must be injected at lower pressures compared to the pressure required to completely dissolve the oil.
Experiments have established that in the process of injecting high-pressure gases into a model of a formation containing light oils, oil recovery is greater than it should be only with reverse evaporation of oil fractions.
The gas moving through the reservoir is gradually enriched with ethane and heavier hydrocarbons, and methane, encountering fresh portions of oil with a saturation pressure lower than the pressure of the injected gas, dissolves in the oil. Gas containing a significant amount of heavy hydrocarbons is completely miscible with oil even at relatively low pressures and temperatures. At the same time, oil recovery is high, because the process becomes close to that observed when oil is displaced by a liquid solvent.
Alcohols and liquid carbon dioxide can mix with oil and water. However, some alcohols are poorly soluble in water (butyl and propyl), while others, on the contrary, are poorly soluble in oil (ethyl and methyl). Carbon dioxide dissolves in water and oil of different compositions and densities. Research on CO 2 began in the early 50s.
Mechanism of phenomena. Carbon dioxide, or carbon dioxide, forms a liquid phase at temperatures below 31.2 °C. However, when it contains hydrocarbons, the temperature at which liquid carbon dioxide can exist increases up to 40 °C. At temperatures above 31 °C, carbon dioxide is in a gaseous state at any pressure. A pressure of 7.2 MPa is also critical. At lower pressure, CO 2 goes from a liquid state to a vapor state (evaporates).
The density and viscosity of liquid carbon dioxide varies from 0.5 to 0.9 t/m 3 and from 0.05 to 0.1 mPa s, and gaseous - from 0.08 to 0.1 kg/m 3 and from 0.02 to 0.08 mPa s at pressures of 8-25 MPa and temperatures of 20-100 °C.
At high pressures (more than 15 MPa) and low formation temperatures (less than 40°C), the density of liquid and gaseous carbon dioxide becomes almost the same (0.6-0.8 t/m3).
Carbon dioxide dissolves in water much better than hydrocarbon gases. The solubility of carbon dioxide in water increases with increasing pressure and decreases with increasing temperature. Under reservoir conditions in water, the solubility of carbon dioxide ranges from 30 to 60 m 3 /m 3 (3-5 °/o). As water mineralization increases, the solubility of carbon dioxide in it decreases.
When carbon dioxide is dissolved in water, its viscosity increases slightly. However, this increase is insignificant. With a mass content of 3-5% carbon dioxide in water, its viscosity increases only by 20-30%. Carbonic acid H 2 CO 3 formed when CO 2 is dissolved in water dissolves some types of cement and formation rock and increases permeability. According to laboratory data of BashNIPIneft, the permeability of sandstones increases by 5-15%, and of dolomites by 6-75%. In the presence of carbon dioxide, the swelling of clay particles decreases. Carbon dioxide is 4-10 times more soluble in oil than in water, so it can pass from an aqueous solution into oil. During the transition, the interfacial tension between them becomes very low and the displacement approaches miscibility.
Carbon dioxide in water promotes the rupture and washout of the film of oil covering the rock grains and reduces the possibility of rupture of the water film. As a result, oil droplets with low interfacial tension move freely in the pore channels and the phase permeability of oil increases.
Carbon dioxide is much more soluble in oil than methane. The solubility of CO 2 in oil increases with increasing pressure and decreasing temperature and molecular weight of the oil. The methane or nitrogen content reduces the solubility of CO 2 in oil and increases the miscibility pressure. Oils with a high content of paraffinic hydrocarbons dissolve CO 2 better than oils with a high content of naphthenic and, especially, aromatic hydrocarbons.
At pressures above the pressure of complete miscibility, CO 2 and oil will form a single-phase mixture regardless of the content of CO 2 in it, i.e. there will be unlimited miscibility.
The pressure of complete miscibility for different oils is very different and can vary from 8 to 30 MPa or more. For light, low-viscosity oils, the miscibility pressure is lower, for heavy, high-viscosity oils it is higher.
At the same time, the miscibility pressure of CO 2 and oil depends on the saturation pressure of oil with gas. With an increase in saturation pressure from 5 to 9 MPa, the miscibility pressure increases from 8 to 12 MPa. The content of methane and nitrogen in CO 2 increases the miscibility pressure. For example, the content of 10-15% methane or nitrogen in CO 2 increases the miscibility pressure by more than 50%. Conversely, adding ethane or other high molecular weight hydrocarbon gases to carbon dioxide reduces the miscibility pressure.
An increase in temperature from 50 to 100 °C increases the miscibility pressure by 5-6 MPa.
Due to the influence of these factors on the miscibility pressure, CO 2 is only partially miscible with many oils at real reservoir pressures. However, in the formations, CO 2, in contact with oil, partially dissolves in it and at the same time extracts carbohydrates, becoming enriched in them. This increases the miscibility of CO 2 and as the front advances the displacement becomes miscible. As a result, the pressure required for miscible displacement of oil by carbon dioxide is significantly less than that of hydrocarbon gas alone. Thus, for miscible displacement of light oil by hydrocarbon gas, a pressure of 27-30 MPa is required, while for displacement of CO 2 9-10 MPa is sufficient.
When CO 2 is dissolved in oil, the viscosity of the oil decreases, the density increases, and the volume increases significantly: the oil seems to swell.
At high pressure and temperature, the mechanism of miscibility of CO 2 and oil is characterized by the process of evaporation of hydrocarbons from oil into CO 2, and at low temperatures the mechanism is more consistent with condensation, adsorption of CO 2 into oil.
At pressures below the miscibility pressure, the mixture of CO 2 and oil is divided into component phases: CO 2 gas containing light fractions of oil and oil without light fractions. Asphaltenes and paraffins can precipitate from oil in the form of a solid sediment.
The increase in oil density when CO 2 is dissolved in it does not exceed 10-15%, usually amounting to no more than 2-3%, which is associated with a significant expansion of the oil volume.
An increase in the volume of oil by 1.5-1.7 times when CO 2 is dissolved in it makes a particularly large contribution to increasing oil recovery when developing fields containing low-viscosity oils. When displacing high-viscosity oils, the main factor that increases the displacement coefficient is a decrease in the viscosity of the oil when CO 2 is dissolved in it. The viscosity of oil decreases the more strongly, the greater its initial value.
Initial viscosity of oil, Viscosity of oil at full saturation with CO 2,
mPa s mPa s
1000-9000 15-160
As you can see, the viscosity of oil decreases very strongly under the influence of CO 2 dissolution in it (no less than under the influence of heat).
I. I. Dunyushkin proposed an empirical formula for calculating the viscosity of oil saturated with CO 2 with its concentration in oil C n:
Here A and - empirical coefficients; - initial viscosity of oil, mPa s.
When the pressure decreases and the oil-CO 2 mixture separates into its component phases, the light components of oil transform into carbon dioxide. In this case, the remaining oil becomes heavier, its volume and the solubility of CO 2 in it decrease, and its density and viscosity increase. As a result, the mobility of the oil remaining behind the CO 2 displacement front decreases.
The mechanism of the oil displacement process . At reservoir pressure above the pressure of complete miscibility of reservoir oil with CO 2, carbon dioxide will displace oil as a common solvent (miscible displacement). Then three zones are formed in the reservoir - the zone of the original reservoir oil, the transition zone (from the properties of the original oil to the properties of the injected agent) and the zone of pure CO 2. If CO 2 is injected into a flooded reservoir, then a shaft of oil is formed in front of the CO 2 zone, displacing formation water.
Under laboratory conditions, when some oil models were displaced by carbon dioxide from homogeneous porous media, a displacement coefficient of 1 was achieved in several cases.
However, in experiments with real oils, the displacement coefficient does not exceed 0.94-0.95%, which is apparently explained by the precipitation of high-molecular oil components into a solid sediment.
When the pressure in the reservoir is less than the miscibility pressure, CO 2 partially dissolves in the oil phase, improving its filtration characteristics, and light oil fractions, on the contrary, turn into CO 2.
Component separation of oil occurs. Carbon dioxide, saturated with light fractions of oil, displaces oil partially saturated with CO 2. In the zone washed with CO 2, the residual oil acquires the properties of a heavy oil residue.
Laboratory experiments have established that CO 2 in liquid form displaces oil better than in gaseous form at a temperature close to critical (31°C) and pressure close to critical (7 MPa).
At a temperature in the formation above the critical level, CO 2 at any pressure will be in a gaseous state and displace oil with all the disadvantages inherent in an agent with low viscosity, i.e., with low coverage of heterogeneous formations by the process. Therefore, it is always advisable to inject carbon dioxide in liquid form into formations and select objects for its use with a temperature slightly different from the critical one (25-40 ° C).
Influence of volumetric effects on the displacement of oil by carbon dioxide . An increase in the volume of oil under the influence of CO 2 dissolving in it, along with a change in the viscosity of liquids (a decrease in the viscosity of oil and an increase in the viscosity of water) is one of the main factors determining the effectiveness of its use in the processes of oil production and its extraction from flooded formations.
The volumetric expansion of oils depends on pressure, temperature and the amount of dissolved gas. The volumetric expansion of oil under the influence of CO 2 is also affected by the content of light hydrocarbons (C 3 -C 7) in it. The higher the content of light hydrocarbons in oil, the greater its volumetric expansion. Volumetric expansion of oil in the reservoir or “swelling” of oil causes an artificial increase in the oil-saturated volume of the pore space of the reservoir. As a result, the pressure in the pores increases, as a result of which some of the residual immobile oil is additionally displaced into production wells. Volumetric expansion of oil, even with partial saturation with CO 2, increases its displacement coefficient by 6-10% due to an increase in phase permeability for oil, and, consequently, the final oil recovery of formations.
Technology and development systems . Due to the fact that pressure determines miscibility, the state of the oil-CO 2 mixture and the efficiency of oil displacement, the main controlled elements of the process technology are CO 2 injection pressure and maintaining reservoir pressure.
The optimal pressure at which CO 2 most effectively displaces oil should be determined in each specific case experimentally under conditions close to reservoir conditions, i.e., determination of the miscibility pressure for reservoir oils with CO 2 is carried out in the porous medium of a real reservoir.
Another important condition for the technology of displacing oil with CO 2 is its purity, on which miscibility with oil depends. Pure CO 2 (99.8-99.9%) has a minimum miscibility pressure, mixes better with oil and displaces it, and during liquefaction it can be pumped into formations without complications and the need to remove gases. If the mixture with CO 2 contains a large amount of light hydrocarbon and inert gases, injection of the mixture is possible only in a gaseous state.
If CO 2 is injected into the formation in a mixture with methane (natural gas) or nitrogen (flue gases), then the miscibility pressure will be very high, and the efficiency of CO 2 oil displacement will be reduced. This is explained by the fact that methane or nitrogen prevents the miscibility of oil and CO 2.
To displace oil with CO 2 alone, its high consumption is required for a noticeable increase in oil recovery. Due to the large difference in the viscosities and densities of CO 2 and oil, rapid breakthroughs of CO 2 to production wells through highly permeable layers are possible, their gravitational separation and a significant decrease in the sweep coefficient compared to waterflooding. As a result, the effect of increasing oil displacement by CO 2 may be less than losses in oil recovery due to a decrease in displacement coverage. In order to save CO 2 , prevent its breakthrough to production wells, reduce gravitational effects and increase the sweep factor, it is advisable to combine the use of CO 2 with waterflooding. Various modifications of this method are used.
Carbonated water flooding . The simplest way to inject CO 2 into the formation is to inject water that is fully or partially saturated (3-5%) with CO 2 . In the reservoir, CO 2 passes from water into the oil remaining behind the front, changing its volume and filtration properties, viscosity and phase permeability. In this case, the front of CO 2 concentration in water significantly lags behind the displacement front. The lag depends on the coefficient of displacement of oil by water, the coefficient of distribution of CO 2 between oil and water, the concentration of CO 2 in water, pressure and temperature and varies from 2 to 8 times, i.e. the path traveled by the front of displacement of oil by water is 2-8 times the distance traveled by the front of the initial concentration of CO 2 in water.
This circumstance significantly increases the time it takes to obtain the effect, the duration of oil field development and the consumption of injected water. Laboratory experiments and numerical calculations carried out at BashNIPIneft show that the coefficient of oil displacement by carbonated water increases by only 10-15% when five to six pore volumes are injected into the formations. The reservoir sweep coefficient in the case of using carbonated water is slightly higher than with conventional waterflooding. This is explained by a decrease in capillary forces at the phase boundaries and a decrease in the contact angle of rock wetting with water. Gravitational forces, well pattern density and development system have the same effect on the process of oil displacement by carbonated water as on conventional waterflooding.
Carbon dioxide slug displacement . The lag of the CO 2 front from the front of oil displacement by water can be avoided (or significantly reduced) by injecting pure CO 2 into the formation in the form of a slug in a volume of 10-30% of the pore volume, which is then propelled by water. When oil is displaced from a watered formation by a CO 2 rim, the following characteristic zones of saturation will exist (immiscible displacement).
Zone I - single-phase flow of oil in the presence of buried water.
Zone II - joint movement of CO 2, oil and water, accompanied by active mass transfer between these phases.
Zone III - movement of the oil shaft in the presence of buried water and trapped gas. Here, mass exchange of carbon dioxide occurs between phases, but to a lesser extent than in zone II.
Zone IV is the movement of carbonated water in the presence of oil devoid of light fractions and therefore inactive oil and trapped CO 2. Mass transfer is extremely limited, since a shaft of buried water moves in front of the CO 2-free injected water, which is saturated at the front of the CO 2 displacement of oil.
Zone V - movement of injected water in the presence of residual oil. The CO 2 contained in the oil passes into the injected water, and its concentration decreases in these zones from a maximum value to zero in the direction opposite to the flow movement.
Zone VI - movement of water in the presence of residual oil and in the absence of CO 2.
If the size of the CO 2 rim is small, then over time zones II and III disappear. Water overtakes CO 2, and oil is displaced by carbonated water. Between zones I and IV, two new zones appear: zone VII, in which oil is displaced by water devoid of CO 2, and zone VIII, in which oil is displaced by carbonated water. Saturation of water with CO 2 occurs in zone IV, i.e., at a distance from the injection line. As a result, the lag of the CO 2 front from the displacement front (size of zone VII) when injecting a CO 2 slug is always less than when injecting carbonated water. Subsequently, the injected water is saturated with CO 2 in the area of the trapped gas.
Ultimately, the trapped gas disappears and only zones VI and V remain in the formation. In zone VI, the volume of oil containing no CO 2 is significantly less than in zone V. The important thing is that water transports CO 2 from areas where oil is practically stationary (zones IV and V), in areas not affected by CO 2. As a result, unlike the use of other solvents or hydrocarbon gases, even small slugs of CO 2 provide a noticeable increase in oil recovery.
With an increase in the volume of CO 2 injected into the formation, oil recovery from the formation will naturally increase.
As the size of the slug increases, the oil displacement coefficient increases unevenly; as the slug increases, the increase decreases. As a result, with small rims, the CO 2 consumption per ton of additionally produced oil is lower than with large ones. On the other hand, with an increase in the slug, the development period decreases and the consumption of injected water is reduced. A similar dependence of oil recovery on the size of the slug is obtained in a heterogeneous formation. In most cases (with low heterogeneity of formations), the optimal volume of the CO 2 slug is in the range from 20 to 30% of the pore volume.
When oil is displaced by a CO 2 slug, oil recovery very much depends on the conditions for gravitational separation. With high vertical permeability of the formation, oil recovery can be 2-2.5 times less than with zero permeability across the thickness of the formation.
Displacement of carbon dioxide and water by alternating slugs . Research, experimental and analytical, shows that more high efficiency This method can be obtained by injecting the required volume of CO 2 in small portions alternately with water or simultaneously injecting CO 2 and water. The efficiency of this process depends to a large extent on the ratio of the sizes of CO 2 and water portions, i.e., the gas-water ratio during alternating injection.
With a decrease in this ratio, the viscous instability of CO 2 advancement decreases (it is more evenly distributed throughout the formation), the likelihood of premature breakthrough of CO 2 through highly permeable layers into injection wells decreases, and as a result, the sweep factor increases. At some water to CO 2 ratios, the sweep factor may be higher than with conventional flooding or carbonated water injection. At the same time, with a low ratio of gas and water volumes, the process efficiency approaches the injection of carbonated water.
With an increase in the gas-water ratio, an unfavorable manifestation of gravitational instability is possible due to different densities of water and CO 2. Water will tend downward, and CO 2 will tend to the top of the formation. Or, with a sharp layered heterogeneity, CO 2 will break into production wells along highly permeable layers, and then water will rush there, ensuring a low coverage of the displacement process. Therefore, there is an optimal ratio of the volumes of CO 2 and water during alternating injection to achieve the greatest effect, which should be justified by special studies and calculations based on the real conditions of heterogeneity of formations, solubility of CO 2 in water and oil, etc.
The decisive factor when choosing the ratio of CO 2 and water injection volumes is to prevent CO 2 breakthrough to production wells. Typically this ratio can vary from 0.25 to 1.
The sizes of rims (portions) of CO 2 and water can be quite large - up to 10-20% of the pore volume with complete miscibility of CO 2 and oil, high oil saturation and sufficient uniformity of the formation. In the case of weak miscibility of CO 2 and oil (heavy oils, low pressure), the portions of CO 2 and water should be small during alternating injection.
With increasing heterogeneity of formations and oil viscosity, the sizes of CO 2 and water portions should decrease. For low-viscosity oils and weak heterogeneity of formations, CO 2 is advisable to use from the beginning of development.
In heterogeneous formations and with high-viscosity oil, higher final oil recovery can be obtained by using CO 2 at a late stage of development, i.e. in a flooded formation. This unexpected effect is explained by the different solubility of CO 2 in oil and water.
Other possible technologies that increase reservoir coverage by displacement . In addition to displacing oil with carbonated water and various CO 2 slugs, in some projects, in order to increase the efficiency of CO 2 use, it was proposed, after alternate injection of CO 2 and water, to alternately inject water and other, more accessible gas (natural, flue, etc.). In this case, the miscible displacement of undissolved CO 2 by cheaper gas occurs, the residual saturation of the CO 2 formation decreases and, as a result, its consumption decreases.
To reduce the mobility of free CO 2 in the formation with incomplete miscibility and increase coverage, it is possible to use water-soluble surfactants and aqueous solutions of sodium silicate to form foams and gels in highly permeable layers. The main problems in this case are stabilization of foams, adsorption of surfactants and preservation of the gel in a mineralized environment. Laboratory experiments confirm the feasibility of implementing these measures, which increase the displacement coverage of heterogeneous formations.
In the project for the additional development of the flooded formation B 2 of the Radaevsky oil field (oil viscosity 20-22 mPa s) using CO 2, the All-Union Oil and Gas Research Institute proposed injecting it alternately with an aqueous polymer solution to improve the coverage and distribution of CO 2 throughout the reservoir volume. According to calculations, the use of polymers with CO 2 at the Radaevskoye field can increase oil recovery from 10 to 13%.
Hungarian specialists have implemented the following, in their opinion, the most effective technology for displacing CO 2 oil from depleted formations.
Carbon dioxide is injected into the depleted formation at low pressure (2 MPa), it replaces free hydrocarbon gases in the formation.
Reservoir pressure due to CO 2 injection increases from 2 MPa to the initial one (10-13 MPa).
If there is free CO 2 in the porous medium, oil is displaced by supersaturated carbonated water (28-30 m 3 CO 2 per 1 m 3 of water).
With this technology, it was possible to obtain an oil displacement coefficient in the covered part of the formation of more than 90% at a high CO 2 flow rate (about 0.8 of the pore volume) and low water flow rate (0.53-0.7 of the pore volume). About 70% of the injected CO 2 is extracted from the reservoir and, after regeneration, can be reused with appropriate equipment. But it is advisable to use such technology only in cases where a large, cheap source of CO 2 is located near an oil field, for example, a field of natural CO 2 with a high concentration (more than 70-80%).
Development systems . The use of CO 2 to enhance oil recovery does not impose special requirements on the development system, but it must be in-line, five-row, three-row or single-row, or various modifications of area flooding must be used. Preference should be given to active, i.e., small-row development systems.
The use of multi-row systems is undesirable due to the possible selection of large volumes of CO 2 by the first rows of production wells. If it is necessary to use such systems, the gas-water ratio should be reduced.
Placing wells to apply the method is possible at any grid density - up to 40-50 ha/well or more, since CO 2 does not worsen the drainage conditions of the formations. As with conventional waterflooding, the density of the well pattern should be taken depending on the heterogeneity of the formations in terms of permeability and discontinuity, based on the condition of more complete drainage coverage. When developing formations in which significant gravitational segregation of water and CO 2 is possible (formations with large thickness and vertical permeability), the density of the well pattern should be increased. When deciding on the density of the well network, one should take into account the condition, tightness, conditions and possible duration of operation of the injection wells, the need to drill backup wells and take maximum measures to protect the metal of the casing pipes from corrosion.
Current projects . The first field experiment on injection of CO 2 into an oil reservoir in our country was carried out at the Aleksandrovskaya area of the Tuymazinskoye field. The experimental area included one injection and two production wells and had the following geological and field characteristics: area along the well line 14.2 hectares, pore volume 258,800 m 3 , oil-saturated formation thickness 6.1 m, porosity 22%, permeability 0. 6 µm 2 , oil viscosity in the reservoir is 15 mPa s, the distance between the injection and production wells is 338 and 263 m, respectively.
Before the start of the experiment, 80,000 m3 of water was pumped into the injection well. In December 1967, they began injecting CO 2 into the formation in the form of carbonated water. Simultaneously with the injection of CO 2 into the pumping and compressor pipes, process water was pumped into the interpipe space at a flow rate of 150-220 m 3 /day. At the bottom of the well, mixing of injected CO 2 and water took place with an average concentration of 1.4%. In total, two pore volumes of carbonated water were injected, including 4780 tons of CO 2, which amounted to about 2% of the pore volume.
The results of studies of the injectivity profile of the injection well indicate an increase in thickness flooding coverage of the formation by 30%. The injectivity of the injection well increased by 30-40%. In general, due to the injection of carbonated water, according to BashNIPIneft, an additional 27.3 thousand tons of oil were produced in the area, which corresponds to an increase in oil recovery by 15.6% of its initial reserves compared to water injection. An additional 5.8 tons of oil were produced per ton of injected CO 2 . This effect is clearly overestimated.
In Hungary there are a number of deposits containing significant volumes of CO 2. This explains the great interest shown in this country in the use of CO 2 to increase oil production, in theoretical and experimental research in this direction. To conduct a field experiment, the middle lens of the Verkhnee Lishpe section of the Budafa field was selected. The site has the following geological and field characteristics: pore volume 1,250,000 m 3 , initial geological oil reserves 713,500 tons, formation thickness 4-10 m, porosity 21-22%, permeability 0.03-0.13 μm 2 , saturation of associated water 30%, temperature 68 °C, pressure 10.5 MPa, oil viscosity 1.12 mPa s, gas content 70 m 3 /m 3.
By the time CO 2 was injected into the layers, 280,675 m3 of oil had been extracted, which corresponded to an oil recovery of 39.3%, including 230,576 m3 due to water injection. Since July 1969, they began to inject CO 2 to restore reservoir pressure after depletion to 12 MPa, then water. Since September 1970, alternating injection of water and CO 2 was carried out in a 1:1 ratio, and since July 1973, water alone was injected. Injection was carried out initially in three wells, and from March 1972 - in five wells. By the end of 1972, 45,375,100 m3 of gas containing 81-83% CO2, which is about 6% of the pore volume, and 221,679 m3 of water were injected. 38,359 m3 of oil were extracted, i.e. about 5% of the balance reserves of the entire area, 67,607 m3 of water and 22,822,685 m3 of gas, including 14,017,964 m3 of carbon dioxide, or 31% of what was pumped into layers.
Using the material balance method, it was determined that oil recovery from the formation exposed to CO 2 increased by 10%. An increase in the drainage coverage coefficient by thickness was noted, which at the beginning of 1970, mid-1971 and mid-1972 was 0.58, respectively; 0.65; 0.78. As can be seen, the increase in formation coverage by drainage is very large. Field development continues and further increases in oil recovery are expected.
This experiment on immiscible displacement of oil by CO 2 can be considered quite successful.
At the end of 1975, CO 2 injection began at the Lovasi field. Here, an increase in oil recovery by 10-15% is expected.
The most widespread use of CO 2 for oil production is being studied in US oil fields. In the 50's and early 60's, several small field experiments were conducted using carbonated water. There was an increase in the injectivity of injection wells and the flow rate of production wells. Based on the analysis of the results of these experiments, as well as laboratory and theoretical studies, it was concluded that the displacement of oil by CO 2 slugs is greater.
In the 60-70s, commercial experiments of various scales with CO 2 rims began in the USA. Currently, 59 experiments are being carried out with with total area plots of more than 40 thousand hectares and oil production of more than 1.5 million tons/year.
In several experiments, CO 2 was injected into formations containing highly viscous oil periodically, similar to steam cyclic stimulation, when after a certain volume of CO 2 was injected into the formation, the injection well began to operate as a production well. At the same time, the oil located in the area of these wells dissolves the injected CO 2, as a result of which its viscosity decreases and its mobility increases.
Technological and economic efficiency . The effect of using CO 2 to increase oil recovery is expressed in an increase in the displacement coefficient due to the volumetric expansion of oil, its solubility and miscibility with oil (elimination of capillary forces) and a decrease in oil viscosity. In the formation zone where CO 2 has passed through, the average residual oil saturation decreases by 1.5-2 times, and the oil displacement coefficient can reach an average of 85-90%, i.e. 15-25% higher than during waterflooding.
However, the effect in increasing oil recovery from reservoirs is not as high as in increasing the oil displacement coefficient, due to a decrease in the coverage of the reservoir by the working agent.
A decrease in the viscosity of oil and a slight increase in the viscosity of water when CO 2 is dissolved in them (by 15-20%) cannot always compensate for the negative effect of gravitational forces and the high mobility of CO 2 in the formation if it does not mix with oil. Therefore, the coverage of heterogeneous formations by the process of displacement of CO 2 with incomplete miscibility with water can be 5-15% less than during flooding, unless special measures are taken to increase the coverage.
As a result, the increase in the final oil recovery factor from the use of CO 2 can be only 7-12%. For example, at the Kelly Snyder field, after injecting 8% CO 2 of the reservoir pore volume in section I, about 80% of CO 2 and water entered the reservoir layers, constituting only 20% of the reservoir volume, and other layers, occupying 50% of the reservoir volume, accepted less than 20% of the CO 2 injection volume.
The main task when using CO 2 to increase oil recovery is to use all possible means and methods to increase the coverage of layers with the working agent, i.e., to reduce the negative influence of gravitational forces and CO 2 mobility. This can be achieved using appropriate technology for injection of CO 2 and water, opening up formations in wells, isolating formation intervals, downhole equipment, and placing wells depending on the geological and physical characteristics of specific deposits.
An important indicator of the efficiency of CO 2 use is the ratio of the volume of CO 2 injected into the reservoir to the volume of additionally produced oil. This ratio, naturally, depends on many factors - oil properties, saturation and heterogeneity of the formation, and also to a large extent on technology - the size of the slugs. The size of the rim can be 10-30% of the pore volume. As the size of the CO 2 slug increases, the effect increases, expressed in increased oil recovery from the reservoir. But at the same time, the consumption of CO 2 per ton of additionally produced oil also increases.
Based on experimental studies, analytical calculations on mathematical models of reservoirs and ongoing field experiments, it can be assumed that under optimal conditions for the use of CO 2, its consumption per ton of additional oil will range from 800 to 2000 m 3, and with utilization and reinjection of CO 2 - from 500 to 1300 m 3, or 1-2.5 t/t.
The efficiency of the process of displacing oil by CO 2 is greatly influenced by the initial oil saturation. The greater the oil saturation of the formation at the beginning of CO 2 application, the higher the effect, since most of the CO 2 is spent on useful saturation, expansion and displacement of oil.
The ratio of water and gas volumes significantly affects the coverage of formations by the displacement process and the efficiency of CO 2 application. Therefore, when using CO 2 to increase oil recovery, it is extremely important to determine the optimal sizes of slugs and the ratio of water and gas during their alternating injection in specific geological and physical conditions of the fields. This is possible only on the basis of mathematical (adequate to the model process) reliable information about the structure and state of saturation of the formation and correct economic criteria.
The economic efficiency of using CO 2 to increase oil recovery is determined based on its costs per unit volume of oil at the mouth of an injection well, i.e., specific additional oil production, and the price of oil.
The costs of CO 2 can vary widely depending on the source of its production.
Natural CO 2 from deposits located near oil fields will obviously be the cheapest. Natural accumulations of CO 2 have so far been discovered in the Semividovskoye field ( Western Siberia) and Astrakhan. It contains up to 20-30% of inactive components - methane, nitrogen, etc.
The largest resources of artificial CO 2 are provided by power plants, factories for producing artificial gas from coal, shale and other chemical plants. From the flue gases of a 250 MW thermal power plant, 2.5 million tons of CO 2 can be obtained per year.
Plants producing artificial hydrocarbon gas from coal emit 3-4 times more CO 2 as a by-product than the target product. This gas must be purified, compressed and transported to oil fields. According to some projects, with a transportation distance of up to 800 km, the cost of 1000 m 3 CO 2 will be 35-40 dollars. At this cost of CO 2 and the indicated specific consumption for oil production, 1 ton of additional oil will cost approximately 30-80 dollars. Even with such unit costs, the method is of industrial interest at the current oil price.
Disadvantages of the method, limitations, problems . The main disadvantage of the method of extracting residual oil using CO 2 is the reduction in the sweep of formations by displacement compared to conventional waterflooding, especially when it is incompletely miscible with oil. If it were possible to ensure that the coverage of formations by displacing CO 2 was the same as during waterflooding, then it would be possible to obtain a significant increase in oil recovery, since in the zone where CO 2 mixes with oil, very little residual oil remains - 3-5% . As noted, the reduction in the coverage of formations by displacement can be reduced in different ways - by improving the conditions of miscibility with alternating rims of water and gas, changing their size, selective isolation of certain intervals of formations to level out the advancement of CO 2, cyclic impact on the formations, appropriate placement of wells and opening up formations in them and etc.
Another disadvantage of the method, apparently, should be considered that CO 2, under conditions of incomplete miscibility with oil, extracts light hydrocarbons from it, carries them away, and heavy oil fractions remain in the formation. It will be more difficult to remove them in the future, since they become less mobile and, possibly, fall out onto the surface of the pores, changing the wettability of the medium.
A limitation for the use of CO 2 for the purpose of increasing oil recovery, in addition to geological and physical criteria, will obviously be the availability of CO 2 resources in the area of oil fields or available for transportation to the fields with favorable economic indicators. We can assume that the distance of the CO 2 source from the field is more than 400-600 km, its cost (at the mouth of injection wells) is more than 40-50 rubles. and the low selling price of oil will be serious obstacles to the use of CO 2 on an industrial scale.
The most difficult problems that arise when using CO 2 to increase oil recovery include the possibility of corrosion of injection and production wells and oilfield equipment, the need for CO 2 recycling - removal from produced hydrocarbon gases on the surface and reinjection into oil reservoirs. Pure CO 2 (without moisture) is not dangerous in terms of corrosion. But when alternating with water in an injection well or after mixing with it in the formation and when appearing in production wells and on the surface, it becomes corrosive.
A complex technical problem is the transport of liquid and its distribution among wells, requiring special pipes, welding quality, etc.
When water that is incompatible with formation water is used together with CO 2, more favorable conditions are created for salt precipitation in formations, bottomhole zones of wells, risers, surface equipment, etc.
A significant drawback limiting the implementation of the method is the relatively large absorption of CO 2 by the formation - losses reach 60-75% of the total injection volume. They are caused by the retention of CO 2 in dead-end pores and stagnant zones. All this leads to a large specific consumption of CO 2 per ton of additionally produced oil.
The future of the method . Of all the known methods for increasing oil recovery, the use of CO 2 is perhaps the most universal and promising. According to the mechanism of interaction of CO 2 with oil, water and rock, the method has undeniable advantages over others. A particularly important advantage of the method is the possibility of its application in flooded formations and the relative ease of implementation. Based on a combination of factors, this method can be considered as the highest priority method for increasing oil recovery, applicable in most oil fields with a sustainable increase in oil recovery from 5 to 12%. However, the use of the method in the future will be determined mainly by the resources of natural CO 2, since the need for it (approximately 1000-2000 m 3 per ton of oil production) will be difficult to satisfy from chemical production waste, although this source of CO 2 is economically profitable.
The potential capabilities of the method of increasing oil recovery using CO 2, according to forecasts by the Office of Technology Assessment of Congress and the US National Petroleum Council, can reach 40-50% of all oil reserves additionally extracted by new methods (1.1-5.8 billion tons) depending on many factors - oil price, minimum rate of return, cost of natural CO 2, technology efficiency, etc. Additional recoverable oil reserves in the United States due to the use of CO 2 are estimated to be 0.5-3 billion tons. The level of additional oil production by 2000 may range from 30 to 150 million tons/year.
The maximum values of additional recoverable reserves of the oil production level are determined under extremely favorable conditions - the price of oil reaches the cost of alternative types of liquid fuel (artificial oil from coal or shale), the process technology is highly efficient, the profit rate is 10%, the cost of CO 2 does not exceed 35 dollars. per 1000 m 3, etc.
The prospects for using CO 2 to increase oil recovery in our country are also very broad. Projects have been drawn up and the necessary preparatory work is being carried out for the injection of CO 2 into oil-bearing formations in many fields (Kozlovskoye, Radaevskoye, Abdrakhmanovskaya area of the Romashkinskoye field, Sergeevskoye, Olkhovskoye, etc.). In the future, the method of increasing oil recovery using SSb, naturally, will be used in all on an increasing scale.
- Basic Research. – 2015. – No. 11 (part 4) – P. 678-682
- Technical Sciences (02/05/00, 13/05/00, 05/17/00, 05/23/00)
- UDC 622.276
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Pages
678-682
EXPERIENCE AND PROSPECTS FOR NITROGEN INJECTION IN THE OIL AND GAS INDUSTRY
1This article discusses the possibility of using nitrogen for injection into oil and gas condensate deposits to increase oil and condensate recovery based on research by foreign scientists. Due to its widespread availability, low cost and lack of corrosive effect, nitrogen is the most preferred injection agent among non-hydrocarbon gases. Nitrogen has a low ability to mix with oil, but it quite successfully evaporates hydrocarbon liquid in reservoir conditions and can be used for gravity displacement. Nitrogen can serve as a squeezing agent when injecting methane and carbon dioxide into deposits. The implementation of nitrogen injection in the fields of the United States and the Middle East made it possible to increase current oil recovery. In the current macroeconomic conditions, nitrogen injection is a real alternative to the cycling process.
nitrogen injection
enhanced oil recovery
immiscible displacement
maintaining reservoir pressure
1. Abdulwahab H., Belhaj H. Abu Dhabi International Petroleum Exhibition and Conference. “Managing the breakthrough of injected nitrogen at a gas condensate reservoir in Abu Dhabi.” Abu Dhabi, UAE, 2010.
2. Arevalo J.A., Samaniego F., Lopez F.F., Urquieta E. International Petroleum Conference & Exhibition of Mexico. “On the exploitation conditions of the Akai reservoir considering gas cap nitrogen injection.” Villahermosa, Mexico, 1996.
3. Belhaj H., Abu Khalifesh H., Javid K. North Africa Technical Conference & Exhibition. “Potential of nitrogen gas miscible injection in South East Assets, Abu Dhabi.” Cairo, Egypt, 2013.
4. Clancy J.P., Philcox J.E., Watt J., Gilchrist R.E. 36th Annual Technical Meeting of the Petroleum Society. “Cases and economics for improved oil and gas recovery using nitrogen.” Edmonton, Canada, 1985.
5. Huang W.W., Bellamy R.B., Ohnimus S.W. International Meeting of Petroleum Engineers. “A study of nitrogen injection for increased recovery from a rich condensate gas/volatile oil reservoir.” Beijing, China, 1986.
6. Linderman J., Al-Jenaibi F., Ghori S., Putney K., Lawrence J., Gallet M., Hohensee K. Abu Dhabi International Petroleum Exhibition and Conference. “Substituting nitrogen for hydrocarbon gas in a gas cycling project.” Abu Dhabi, UAE, 2008.
7. Mayne C.J., Pendleton R.W. International Meeting of Petroleum Engineers. “Fordoche: an enhanced oil recovery project utilizing high-pressure methane and nitrogen injection.” Beijing, China, 1986.
8. Sanger P.J., Bjornstad H.K., Hagoort J. SPE 69th Annual Technical Conference and Exhibiton. “Nitrogen injection into stratified gas-condensate reservoirs.” New Orleans, LA, USA, 1994.
9. Tiwari S., Kumar S. SPE Middle East Oil Show. “Nitrogen injection for simultaneous exploitation of gas cap.” Bahrain, 2001.
Currently, liquid hydrocarbons dissolved in gas (condensate, propane-butane fraction) are the most valuable raw materials for petrochemical industry and are already considered a no less important target product than natural gas. In this regard, increasing condensate production volumes is becoming an increasingly urgent task. The main reason for the decrease in the condensate recovery factor (CRE) is the precipitation of heavy hydrocarbon components of the gas into the liquid phase when the pressure in the reservoir decreases below the saturation pressure. One of the ways to increase oil and condensate recovery from reservoirs is to maintain reservoir pressure by injecting non-hydrocarbon gases.
The task of choosing a working agent is to achieve a balance of positive and negative factors that accompany the injection of a specific gas into a reservoir under the specific conditions of the selected field. Despite the high rates of oil displacement when injecting carbon dioxide, the use of CO2 is limited due to its high cost and high degree of corrosive effect on well equipment. The best alternative to methane among non-hydrocarbon gases is nitrogen. Huge reserves of nitrogen are present in the atmospheric air, and methods for its production are quite simple, cheap and well studied. Nitrogen has low corrosive activity, which is very important for the smooth operation of downhole equipment. The physicochemical properties of N2 also combine well with the properties of formation fluids. The disadvantages of using nitrogen include poor miscibility with oil, however, its use with the right approach to development management is technologically and economically justified.
The possibility of using non-hydrocarbon gases to increase oil and condensate recovery has been actively considered by foreign oil and gas companies since the early 1970s. In commercial practice, nitrogen is used as:
– pushing agent when pumping portions of carbon dioxide, natural gas and other components during mixing displacement. CO2 and natural gas have high oil displacement rates, but due to their rising costs and possible unavailability of volumes needed to pump, the use of additional nitrogen squeezing volumes is considered an acceptable way to improve oil recovery;
– an alternative to natural gas when maintaining reservoir pressure by injecting an oil deposit into the gas cap. The essence of this method is to replace hydrocarbon gas produced in the field with cheaper nitrogen. In addition, due to in-situ segregation, nitrogen gradually becomes a barrier between the oil and gas parts of the reservoir, as a result of which, due to poor miscibility with oil, it minimizes the risks of breakthrough to the bottom of production wells and provides the so-called “gravitational displacement”;
– displacement of “pillars” of high-viscosity oil during waterflooding. In a situation where low-moving oil is trapped in the structural uplifts of the reservoir, drilling additional production wells carries serious risks for the economics of the project. In this case, nitrogen is used to reduce the viscosity of oil and provide gravitational displacement when pumped into a separate well;
– displacement of gas from the gas cap. If there are significant gas reserves in the gas cap and significant depletion of the oil part of the deposit, nitrogen can be used to additionally extract volumes of natural gas by pumping additional volumes of nitrogen;
– miscible displacement of oil. This method is applicable in the presence of a reservoir with low-viscosity oil that can mix with nitrogen at reservoir pressure and temperature;
– maintaining reservoir pressure in the gas condensate reservoir.
The wide range of uses of nitrogen is associated with positive results from numerous laboratory studies. Experiments on contact evaporation (CVD) of a hydrocarbon liquid during N2 injection showed that when 50% of the pore volume of the reservoir is filled with nitrogen, up to 16% of the liquid phase from the mixture evaporates. Analysis of experiments on pumping nitrogen through a core saturated with “heavy” oil indicates that mixing of hydrocarbons with the agent does not occur, however, at equivalent reservoir pressure and temperature, nitrogen is quite inert, and its properties are comparable to the properties of the reservoir fluid, which has a positive effect on filtration process in the pore space.
The process of producing nitrogen from air is divided into five stages:
1) air compression to 0.6–0.7 MPa using axial or centrifugal compressors;
2) removal of impurities (water vapor, carbon dioxide, etc.) mechanically due to their adsorption in a heat exchanger at low temperatures;
3) cooling in a block-type heat exchanger to a temperature of –196 °C;
4) separation of nitrogen and oxygen through low-temperature distillation;
5) compression of nitrogen to the required injection pressure using centrifugal pumps or reciprocating pumps.
The nitrogen production plant includes gas turbine, compressor, working engine, adsorption tanks, heat exchanger, molecular sieves for removing impurities, distillation tanks. Today, there are several modifications of stations for nitrogen production; the most popular are membrane-type adsorption stations. Most deposits Russian Federation located in northern regions with harsh climatic conditions, so there is no need for an additional refrigeration chamber for a nitrogen installation. Currently a number Russian manufacturers offers block-type nitrogen plants, which are compact and simple in design, but are significantly inferior to foreign ones in production volumes - up to 60 thousand m3/day, while the largest nitrogen plant in the USA can produce up to 120 thousand m3/day. Some domestic operating companies use self-propelled nitrogen units for well development, however, these units are also characterized by low productivity (up to 40 thousand m3/day).
Despite the large number of prerequisites for the use of nitrogen to increase oil recovery, not a single project can do without a thorough analysis of technical, technological and economic indicators. One example of the use of nitrogen is Fordoche Field, an oil and gas condensate field in Louisiana, USA. The reservoir is a sandstone with an average permeability of 6 mD, a porosity of 20%, the nature of saturation is light, low-viscosity oil and a gas-condensate cap. At the stage of selecting a displacement agent, water (negative impact on the RPP for oil) and natural gas (as a product for sale) were excluded. Laboratory studies and 3D modeling data showed the high efficiency of nitrogen in immiscible oil displacement, and it was decided to inject a mixture of 70% nitrogen and 30% methane into the dome part of the reservoir (Fig. 1).
Rice. 1. Nitrogen concentrations when injected into the dome part of the reservoir, Fordoche Field
The implementation of injection of a mixture of N2 and CO2 since 1979 for two years made it possible to increase the current oil recovery of the reservoir with a slight degree of depletion, however, due to a number of economic problems, among which there is a decrease in the cost of production, the project was stopped ahead of schedule. It is noted that no nitrogen breakthroughs into production wells were recorded, but the nitrogen concentration increased by an average of 4% per year.
Nitrogen injection was carried out at a cluster of fields in the state of Wyoming, USA. The Rocky Moutains gas condensate-oil reservoir under consideration is a sand formation with high degree layered heterogeneity and low permeability (2 mD). Depletion of the deposit at the time of sale was 40%, and saturation pressure was reached. Pumping a mixture of 35% nitrogen and 65% methane made it possible to maintain constant condensate production for several years, but after pumping nitrogen above 0.6 of the pore volume of the reservoir, the share of liquid hydrocarbons began to sharply decrease. This fact coincided with an increase in the nitrogen concentration in well production to 90% in the gas phase. After this, nitrogen injection was stopped, and pressure was maintained with dried natural gas.
It should be noted that the implementation of nitrogen injection into oil deposits always accompanied special complex measures to manage injection and carefully monitor the operation of the production fund. Frequent studies of product composition for nitrogen concentration are necessary for timely detection and prevention of breakthroughs of the injected agent, regulation of the injection process, and changes in the ratio when injecting a mixture of gases. Features of the use of nitrogen to maintain reservoir pressure can also make adjustments to the placement of the field's project fund.
In today's environment of low market prices for oil, injecting nitrogen into oil reservoirs may not only not justify the cost of additional equipment, but also seriously worsen the economics of the project. At the same time, the current situation has not affected the price of gas condensate, and therefore nitrogen can be considered to increase the CIC at large gas condensate fields in the north of the Tyumen region.
Despite ongoing research in this direction, the main way to increase condensate recovery from formations is still considered to be reinjection of gas into the reservoir to maintain reservoir pressure above the saturation pressure. The works of foreign authors provide an analysis of the possibility of using nitrogen as an injection agent. Laboratory studies have shown that injection of nitrogen into the reservoir allows one to reduce the saturation pressure and thus prolong stable condensate production. One of the problems is the high degree of dispersion between nitrogen and wet gas molecules in reservoir conditions. This fact depends on the geological structure of the reservoir: a high degree of dispersion is characteristic of homogeneous reservoirs; in a heterogeneous reservoir, the dispersion depends on the injection rate of the displacing agent and is determined by the value of the Reynolds number. At high Reynolds numbers, which are typical for injection in reservoir conditions, the dispersion interaction of nitrogen and condensate has virtually no effect on the final condensate recovery. It has been experimentally established that when injected nitrogen interacts with condensate molecules, the precipitated liquid can occupy up to 25% of the volume (for methane this figure is 18–20%). However, when pumping nitrogen at a level of 120% of the rock volume, a positive effect is observed in the form of a significant increase in the condensate recovery coefficient - up to 90%. Conducted in the work of A.Yu. Yushkov's economic studies have shown that the cycling process using dried natural gas is economically ineffective, and therefore the consideration of nitrogen as an alternative agent is a more pressing issue. A schematic diagram of the implementation of nitrogen injection in the gas condensate field is shown in Fig. 2. The list of necessary equipment for obtaining nitrogen and subsequent separation from well production is the same for oil and gas condensate fields.
Possible applications nitrogen to maintain reservoir pressure has been considered in several gas condensate fields in the UAE. The Middle East field is a large homogeneous gas condensate reservoir with an anticlinal structure. Average porosity is 18%, lateral permeability is 10 mD. The field has been developed since 1974, and additional capacity for reinjection began to be built in 2001. At the initial stage, a number of PVT studies were carried out, which revealed a slight increase in saturation pressure during the interaction of nitrogen with reservoir gas. The construction and adjustment of a hydrodynamic model of the reservoir made it possible to evaluate the dynamics of liquid phase precipitation in the reservoir when pumping natural gas and its mixture with N2 (Fig. 3).
Despite the stabilization of the processes of condensate precipitation, the final condensate recovery when implementing nitrogen injection is only 2% higher than that when injecting natural gas. At the same time, a breakthrough of nitrogen to the nearest production wells is observed within a year after the start of injection. This project is considered in the long term, taking into account current economic prerequisites. Assuming stable prices for necessary equipment and products, implementation of the project is possible in the 2020s.
Rice. 2. Scheme of nitrogen injection in the gas condensate field
Rice. 3. Condensation when pumping gas mixtures
Nitrogen feasibility studies have also been conducted for the Cantarell field and south-eastern UAE assets. The minimum mixing pressures for specific formations were determined, a comparison was made with methane and carbon dioxide, according to the results of which nitrogen was recognized as a suitable injection agent, taking into account technical, technological and economic indicators. However, it is worth noting that for each specific field the results may be different due to differentiation by thermobaric conditions and composition of reservoir fluids.
The review of domestic and foreign sources allows us to formulate the following conclusions:
1) the physicochemical properties of nitrogen and its abundance make it one of the most accessible and fairly effective agents for increasing oil and condensate production from formations;
2) existing methods obtaining nitrogen and its separation from well production is characterized by a high degree of knowledge, simplicity and accessibility;
3) practical experience, coupled with a significant amount of theoretical research, indicates the positive impact of nitrogen injection on the development of hydrocarbon fields;
4) availability in the Russian Federation large deposits with significant reserves of condensate increases the importance of searching effective methods increasing condensate recovery, one of which could be nitrogen injection to maintain pressure in the gas condensate reservoir/cap.
Reviewers:
Grachev S.I., Doctor of Technical Sciences, Professor, Head of the Department “Development and Operation of Oil and Gas Fields”, Institute of Geology and Oil and Gas Production, Federal State Budgetary Educational Institution of Higher Education “Tyumen State Oil and Gas University”, Tyumen;
Sokhoshko S.K., Doctor of Technical Sciences, Professor, Head of the Department of “Modeling and Control of Oil and Gas Production Processes”, Institute of Geology and Oil and Gas Production, Federal State Budgetary Educational Institution of Higher Education “Tyumen State Oil and Gas University”, Tyumen.
Bibliographic link
Ignatiev N.A., Sintsov I.A. EXPERIENCE AND PROSPECTS FOR NITROGEN INJECTION IN THE OIL AND GAS INDUSTRY // Fundamental Research. – 2015. – No. 11-4. – P. 678-682;URL: http://site/ru/article/view?id=39486 (date of access: 04/27/2019). We bring to your attention magazines published by the publishing house "Academy of Natural Sciences"
