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In this chapter, the recent advances in chemical flooding, including the application of nanoparticles, novel surfactants, and the combination thereof will be discussed and described. The main rock and reservoir fluids properties that influence the effectiveness of chemical flooding will be addressed. The emphasis will be given on wetting properties and recent advances in methods for measuring wettability. The technological and economic challenges associated with chemical injection will be posed, and reсent solutions will be given. Especially, the challenge of applying chemical EOR methods to carbonate reservoirs will be covered, and suggestions to overcome it will be given. Moreover, the current worldwide applications of chemical EOR will be discussed and future plans will be outlined.
Skolkovo Institute of Science and Technology, Moscow, Russia
Alexey Cheremisin
Skolkovo Institute of Science and Technology, Moscow, Russia
*Address all correspondence to: anastasia.ivanova@skoltech.ru
1. Introduction
Alternative renewable energy sources, such as solar, wind, or hydrogen energy, are actively developing in the world. However, traditional oil and gas are still dominating sources of energy, and their global demand is growing continuously. Therefore, it is important to continue developing and enhancing recovery from existing oil fields or discovering new production fields [1]. However, the reserves of conventional, easily accessible hydrocarbons are consistently declining, which is attributed to the fact that the production of conventional oil has surpassed the increase of its reserves. Therefore, since the last several decades, there has been an increasing trend toward the development of unconventional sources of oil and gas, such as viscous (heavy) oils and bitumen, oil sands, oil and gas saturated low-permeability reservoirs, which will significantly contribute to reserves restocking. The majority of unconventional resources are deposited in remote regions with complex geological conditions (depth, porous media structure, mineralogical variations, etc.) under harsh reservoir properties, such as high temperature and salinity, and thus, their development involves the application of new technologies of exploration and recovery [2].
Several stages of recovery and reservoir development are known [3]. At the first stage, also called the primary stage, oil is extracted using the natural energy of the formation, due to which oil flows freely to the production well. However, over time, the initial reservoir pressure decreases, which consistently leads to a decrease in the oil recovery factor. In this case, secondary methods (or improved oil recovery methods) are used to maintain the pressure, such as the injection of water or gas into the reservoir. It is well known that after waterflooding more than 50% of residual oil will remain unproduced [4]. Such inefficient recovery after secondary methods is attributed to the reservoir’s rocks and fluids properties, such as hydrophobic wetting properties and high oil viscosity. Therefore, enhanced recovery methods (or tertiary methods) are applied to change or modify reservoir properties of matured fields, facilitating the displacement of oil toward the production well. These methods include thermal formation stimulation (steam and air injection), chemical flooding (surfactant and polymer injection), gas injection (N2 and CO2), microbes injection, and combination of the methods. Generally, tertiary EOR technologies aid in incremental oil recovery more than primary and secondary methods [5]. However, the effective deployment of EOR methods requires a deep understanding of the mechanisms behind the fluid distribution and displacement through the porous media, which in turn control overall oil production.
In the face of diverse EOR advances, chemical methods are one of the promising techniques applied to recover residual and trapped oil [6, 7]. However, due to some challenges associated with chemical mismatch and high cost, porous trapping, and plugging issues, in the past decades, not many projects have been conducted in the fields. Nevertheless, the rising oil prices and market demand encourage many researchers around the world to further develop chemical EOR technology to make it more efficient yet cost-effective and environmentally friendly.
This review focuses on the fundamentals of chemical EOR in order to explain the main aspects behind screening procedures for chemicals and suitable reservoirs with an emphasis on surfactant injection. The work discusses the main types of studied surfactants and their properties (phase behavior, interfacial tension [IFT], and wettability) that should be evaluated prior to their application and the methods that are usually used. Subsequent sections describe the main advantages and challenges associated when surfactant flooding applied in sandstone or carbonate reservoirs. The novel approaches of using nanoparticles in surfactant flooding, so-called nanoEOR, will be addressed. Finally, examples of field applications will be given. This work mainly focuses on the overall properties of common chemicals and practical recommendations rather than on detailed descriptions of phenomena related to chemical EOR.
Various methods are being developed and applied to improve and enhance oil recovery from different reservoirs [2]. Conventionally, the effectiveness of the method or technology applied for reservoir development is assessed by means of the oil recovery factor (%) which is usually calculated by multiplying several factors:
where pore-scale displacement is a measure of how much of the oil has been pushed out from any of the rock accessed by injected fluids, sweep calculates how much reservoir rock has been reached by injected fluids, drainage is an extent to which wells can access all the separate segments of the reservoir, and commercial cut-off indicates the limit of economic production.
Generally, pore-scale displacement and sweep efficiency are two main factors that can be controlled and modified by applying EOR methods. As a result, it facilities the oil displacement toward the production wells, increasing the overall recovery factor.
Waterflooding is the widely used method for decreasing residual oil saturation by pore-scale oil displacement. However, reservoirs show low oil recovery during waterflooding because more than half of the original oil in place (OOIP) is still left trapped in the complex pore matrix due to the low capillary number of water [8]. The capillary number is defined as the ratio between viscous and capillary forces (Eq. (2)) and controls the residual oil saturation [9] and as a result, the pore-scale displacement.
Nc=v∗μγ∗cosθ,E2
where μ is the brine viscosity, v is Darcy’s velocity, θ is contact angle, and γ is IFT between oil and water phases.
It is well known [10] that to reduce residual oil saturation (i.e., enhance oil recovery), the capillary number should be increased drastically to 10−3 or higher from the typical number of waterflooding—10−7. Indeed, in works [11, 12], it was shown that an increase in the capillary number to 10−4 to 10−3 reduces the residual oil saturation to 90%, and if the capillary number reaches about 10−2, then the residual oil saturation tends to reach zero. Note that the relation between the capillary number and residual saturation is known as the capillary desaturation curve.
In practice, to modify the capillary number, chemical EOR methods, including surfactant flooding, are widely used. As it can be seen in Eq. (2), a capillary number can be increased in several ways: (1) by increasing the viscosity of the injected fluid; (2) by increasing injection fluid velocity; (3) by decreasing IFT between immiscible phases (water and oil); and (4) by decreasing a contact angle. However, an increase in the velocity of the injected fluid can lead to an undesirable increase in the injection pressure compared with the reservoir pressure. Therefore, more often, EOR methods are applied to change and modify the injected fluid viscosity, IFT, or wettability. For instance, the viscosity of injected water can be increased by adding long-chain molecules such as polymers, which due to the formation of a network of topological entanglements, impart high viscosity to the aqueous solution and in some cases, viscoelastic properties [13]. It is important to note that the main purpose of polymer addition is increasing sweep efficiency. Indeed, when a low-viscosity fluid (water) is injected into a reservoir, it will tend to bypass oil sections of the reservoir as it moves along, creating an uneven (fingered) profile. These fingers can have different shapes ranging from a “fleshy” finger [14] to a “skeletal” finger [15]. As a result, it will displace residual oil unevenly, leaving many pores with hydrocarbons untreated. Therefore, in order to reduce the mobility of the water and viscous fingering, polymers are added to the displacement fluid (water).
Furthermore, to reduce the IFT at the interface between two immiscible liquids, such as displacement fluid and oil, as well as to modify the wetting angle, surfactant solutions are used due to their unique properties [16]. Indeed, surfactant molecules are amphiphilic—they consist of hydrophobic (oil-soluble) and hydrophilic (water-soluble) parts. Due to amphiphilic properties, surfactant molecules can self-orient at the surface or interface via hydrophobic or electrostatic interactions, resulting in a reduction of surface energy. Depending on the charge of the hydrophilic group, surfactants are divided into ionic (charged) and nonionic (not charged). The most commonly used surfactants in chemical EOR are listed in Table 1. Conventionally, the type of surfactant for a specific reservoir is chosen accordingly to the screening procedure performed with reservoir rocks and fluids. A summary of general properties applicable to every type of surfactant is illustrated in Table 1.
Usually used as a cosurfactant to improve the properties of ionic surfactants
Improve stability of ionic surfactants
Amphoteric (depending on the pH, can act differently in aqueous solutions—in an acidic solution they exhibit the properties of cationic surfactants, and in an alkaline solution—anionic surfactants)
Effective in IFT reduction and wettability alteration
Have high stability at high temperatures and salinities
High cost
Table 1.
The list of typical surfactants used in chemical EOR and their general properties.
Some types of surfactants have been found to be very effective in terms of IFT reduction, as such carboxylate surfactants can lower the IFT from 20 to 50 mN/m to 10−3 to 10−2 mN/m at reservoir conditions and thus increase the capillary number in 1000 times [17, 18]. The decrease in IFT between the displacement and displaced fluids makes the oil more mobile in the pore throats due to reduced capillary trapping. However, one of the main properties of surfactants that are lowering the IFT to values ~10−3 to 10−2 mN/m is significantly influenced by various factors, such as surfactant type and concentration, the concentration of monovalent and divalent ions in brine (salinity), water-oil ratio (WOR), oil composition, reservoir mineral composition, temperature, and pressure. Therefore, some surfactants that lower IFT at ambient conditions may not be applicable under reservoir conditions (high temperatures and mineralization).
Although many factors affect surfactants’ ability of IFT reduction, their common property is the existence of optimal concentration, at which the minimum of IFT can be observed. This concentration is known as critical micelle concentration (CMC) and varies for different surfactants depending on their chemical structure. The CMC is the main controlling parameter for surfactant properties and needs to be optimized for every surfactant system for enhanced oil recovery [19]. Typically, this concentration lies in a range between 0.001% and 0.01% for commonly used surfactants. By increasing the surfactant concentration above the CMC point, the IFT curve starts to grow slightly [17, 19]. Notably, although, at the CMC point, the minimum IFT is reached, for practical cases concentration of surfactant is chosen of one–two orders of magnitude higher because of high retention and adsorption of surfactant molecules during penetration through the pore networks.
3. Wettability of formation rocks, its modification, and measuring methods
Capillary number can be also increased by reducing the contact anglecosθ (Eq. (2)) that is determined by the forces between injected fluid and rock surfaces. This contact angle is defined in terms of rock-wetting properties. According to the general definition, wettability is the property of a liquid to maintain contact with a solid surface that stems from intermolecular interactions [20].
In terms of oil recovery, wettability is the main parameter that governs produced and injected fluids distributions in the porous networks, which in turn affects the properties of the multiphase flow of reservoir fluids. The wetting state of rock surfaces stems from a chemical equilibrium between rock/oil/brine that formed over years. Generally, wetting preferences of surfaces are divided into three types such as water-wet (hydrophilic), mixed-wet, and oil-wet (hydrophobic). In the water-wet state, oil forms droplet with the minimum contact area at the surface, showing a contact angle θ~0°. If oil drop spreads, the surface is considered hydrophobic or oil-wet with a contact angle close to 180°. When rock surfaces do not exhibit particular wetting preferences, the wetting state is referred to intermediate. In this case, the contact angle can be calculated by the balance of the surface tension forces between phases (Young equation) that determine the shape of a drop on the surface. Notably that when rock surfaces demonstrate several wetting preferences, for example, some areas are hydrophilic and others are hydrophobic, the wettability type is mixed.
The wetting state of reservoir rock controls the arrangement and migration of oil, brine, and gas throughout the pore channels. The distribution of wetting and nonwetting fluids depends on capillary forces, and thus, wetting fluid tends to occupy small pores while nonwetting remains in large pores. In terms of oil recovery, this means that if the rock exhibit hydrophobic wetting state, water as a non-wetting fluid will penetrate through the pores with a larger size, leaving small pores unaffected [18]. This phenomenon explains the low efficiency (low recovery factor) of waterflooding in hydrophobic oil reservoirs (i.e., carbonates), as the water moves through the big pores, while major oil resides in small pores, where water cannot access due to the capillary pressure effect.
This phenomenon is the main reason that prevents developing especially carbonate reservoirs by waterflooding, because the majority of them exhibit hydrophobic or oil-wet wetting preferences [21, 22]. Compared with sandstones, the wettability of carbonate reservoirs appears to be more complex. Indeed, the initially hydrophilic wetting state of carbonate rocks can be changed towards more hydrophobic when interactions between minerals and oil components take place. In research work, several possible mechanisms of wettability alteration due to such interactions have been proposed:
Adsorption of polar organic components or carboxylic acids from oil, such as asphaltenes, resin fractions, benzoic, palmitic, oleic, and octanoic acids [23, 24, 25];
Ion binding, which is led by the surface charge of carbonates [26].
It is important to estimate the initial wettability of rocks accurately for selecting a proper EOR technology for reservoir development. Conventionally, wettability studies are conducted at a core-scale by using Amott–Harvey [27], USBM [28, 29], and contact angle methods [30]. The popularity of these laboratory methods stems from their cost-effectiveness and simplicity. Although Amott–Harvey and USBM methods are widely used in laboratories, they provide information about the average wettability of the core sample. Furthermore, the investigation of reservoir rock wettability by these methods is limited, because as it was shown in work [31], only samples with permeability no less than 10 mD can be studied. Moreover, these methods cannot account for a mixed wettability state (case when different surfaces of rock exhibit both hydrophilic and hydrophobic wetting preferences), as it impossible to determine the number of areas, which have water-wet or oil-wet states, and thus they provide only the integral wettability index.
Another commonly used method for wettability investigation is measuring the contact angle between fluids (water or oil) and the surface. This method is based on the analysis of droplet shape when it spreads on the surface. In this case, wettability is assumed in terms of contact angle values. As such, wettability is referred to hydrophilic if oil forms an angle 0° < θ < 70° with the surface, intermediate wet—70° < θ < 110°, and hydrophobic—110° < θ < 180°. The reverse trend of contact angle values is considered if using water instead of oil. The main difference between contact angle measurements and USBM and Amott–Harvey methods is that by measuring angles the data of wetting preference of a particular sample surface can be collected, and thus mixed wettability state can be determined correctly. However, the contact angle measurements cannot provide the average or integral wettability index. Therefore, in order to measure the wettability accurately, one should consider using a combination of different methods.
Nevertheless, direct study of the fluid-rock interactions by these methods is constrained, as they measure the average wettability on macroscale (mm) and cannot account for rock surface properties, such as its roughness, chemical composition, and pore structure that significantly influence fluids flow and distribution [32]. Therefore, in the past decades, advanced microscopic techniques, including high-resolution scanning electron microscopy (SEM), transmission electron microscopy (TEM) coupled with cryogenic technique and environmental scanning electron microscopy (ESEM) are proposed as new methods for the investigation of reservoir fluids arrangement in porous structure [33, 34]. For example, the authors [33] illustrated that by collecting the elemental maps of rock samples via coupled SEM imaging with the X-ray analysis of the elements the arrangement of reservoir fluids (brine and oil) in the porous network can be obtained. Furthermore, with the recent advances in microscopy, it has become possible to use cryogenic techniques (i.e., Cryo-TEM) and ESEM in order to study surface wettability at microscale (μm) [35, 36]. Indeed, in the work [37] authors carried out the wettability measurements of the middle Bakken samples using ESEM technique. The authors concluded that the results obtained at microscale could be applied for more accurate calculation of multiphase flow parameters (e.g., relative permeability and capillary pressure), which in turn would improve the development of primary or secondary oil recovery processes. Moreover, the application of microscopic techniques is particularly essential while developing the carbonate reservoirs, as these reservoirs show complex wetting behavior due to challenging pore structure, mineral composition, and heavy oil. Indeed studying the rock/brine/oil chemical interactions would give an insight into how to optimally modify wettability to mixed or water-wet, which in turn would increase oil recovery from carbonate reservoirs.
The authors [22] investigated the reason for the hydrophobic wetting properties of carbonate reservoir rocks using combined microscopic tools. The advanced microscopic technologies were first used to identify the adsorbed organic layers on rock surfaces that were proposed to be the key reason for hydrophobic wetting state of carbonates. It was shown [22] by using the ESEM approach that the surface had two wetting preferences. As such, the surface areas that were covered with hydrocarbon layers had hydrophobic wetting properties, while pure calcite areas exhibited hydrophilic state. This result was also confirmed by EDXS analysis of different areas. It was also revealed that the main parameters of multiphase fluids distribution in the pore channels, such as capillary pressure curves, could be evaluated more accurately when using data of microscale wettability variations and the thickness of the organic layers (180 ± 12 nm).
Furthermore, the obtained results can be used to explanation of the reasons for complex wettability behavior in carbonate reservoir rocks. Indeed, based on developed methods [22], it was suggested that some asphaltenes or oil acids could react with calcium ions on the surface by the ionic bond between calcium (Ca2+) and oxygen (O−) from the carboxyl group (COO−). This is the initial layer of hydrophobic organic layers on carbonate surfaces, on which other oil hydrocarbons can adsorb, forming bigger hydrophobic regions. As a result, initial hydrophilic wettability alters toward more oil-wet and water-injection becomes ineffective. Importantly, this explanation can be also applied when developing other carbonate oil reservoirs with high content of carboxylic acids or asphaltenes in oil.
Furthermore, in [38], it was shown that the wettability of carbonates measured by a common laboratory method (contact angle) that differs from wettability measured in corresponding areas of the surface at the microlevel. As such, results demonstrated that wettability at the microlevel was mixed (i.e., hydrophilic and hydrophobic zones) while at the macrolevel surface showed only hydrophobic wetting preferences. These findings bring into question the applicability of macroscale data in reservoir modeling for enhanced oil recovery and geological storage of greenhouse gases.
Traditionally, wettability should be altered towards more hydrophilic in order to increase the oil recovery factor from hydrophobic reservoirs (including carbonates). As a result, spontaneous water imbibition into a porous media will be promoted, leading to the enhancement of oil recovery. In this regard, many different surface active chemicals, such as surfactants, have been widely tested for wettability alteration towards more water-wet. Table 2 summarizes some literature data on change in water advancing contact angle after treating rock surfaces with various surfactants.
Summary of contact angles changes after surfactants treatment.
As can be observed from Table 2, the values of the contact angle between surface and water correspond to the hydrophilic wetting state after treatment of different surfactants.
Notably, the effectiveness of wettability alteration depends on molecular structure and the ionic nature of surfactants. For instance, it was shown that some anionic surfactants with ethoxy and proxy groups in a mixture with Na2CO3 were promising agents for alteration of wettability of carbonate surfaces from oil-wet to water-wet [42]. Contrary to this, the authors [39] suggested that cationic surfactants could be more effective for wettability changing in carbonates reservoirs than anionic ones. The authors explained this by the formation of ion pairs that occur between negatively charged oil components adsorbed on carbonate surfaces and positively charged surfactants. As a result, desorption of oil components from surfaces will be facilitated, leading to a consistent oil recovery increase. Furthermore, it was illustrated that wettability is altered more effectively due to the electrostatic interactions than by hydrophobic interactions. This hypothesis has been also supported by work [43], where the authors studied the wettability alteration process of carbonate cores using different surfactants—anionic (SDS), cationic (CTAB), and nonionic (TritonX-100). The authors showed that cationic surfactant (CTAB) was more effective than anionic (SDS) and non-ionic (TritonX-100) ones in terms of changing the wetting state of the carbonate surface. The phenomenon of wettability changing has been explained by taking into account the irreversible desorption of acids adsorbed onto carbonate surfaces by CTAB surfactants via electrostatic interactions. Notably, for nonionic surfactants, the mechanism of wettability alteration was explained by ion exchange and polarization of π-electrons, whereas for anionic surfactants, the main mechanism of wettability alteration was found to be via hydrophobic interactions between surfactant tail and adsorbed hydrophobic oil components [43].
However, although the evident effectiveness of surfactant flooding mechanisms in wettability alteration, an optimal surfactant that can be both technically and economically feasible has not been found yet. Indeed, the main challenge is surfactant adsorption or retention during the injection process in the reservoir. The unproductive loss of surfactant decreases its effectiveness to lower brine/oil IFT and changing wettability.
Furthermore, although anionic surfactants have been found to be very promising for IFT reduction at reservoir conditions, the value of their adsorption onto hydrophobic or mixed-wet carbonate surfaces was estimated to be higher than in sandstone reservoirs. For instance, it was shown [44] that the adsorption value of typical anionic surfactant onto sandstone and limestone samples equaled 0.03 mg/g rock and 0.21 mg/g rock, respectively. In contrast, the adsorption value of cationic surfactant onto carbonate rocks was calculated to be only 0.12 mg/g rock [44]. The high adsorption value of anionic surfactants in carbonate reservoirs can be explained by the existence of electrostatic interactions between positively charged rock surfaces and negatively charged surfactant heads. Moreover, in high salinity brines of 5% CaCl2, MgCl2, or NaCl, the adsorption of anionic surfactant has been observed to be even higher due to the increased positive zeta-potential of the carbonate surfaces [45].
Therefore, although surfactants have been regarded as promising surface-active agents and laboratory experiments demonstrated their potential in wettability alteration, their industrial applications are limited due to high retention and adsorption onto reservoir rocks. Subsequently, different additives, such as alkalis and nanoparticles, have been studied as sacrificial agents to surfactant molecules in order to decrease their loss and improve efficiency for field applications.
4. Recent advances in chemical EOR: application of nanoparticles as oil/brine IFT and wettability modifiers
Traditionally, surfactant flooding as chemical EOR method has been developed and applied in sandstone oil reservoirs due to its economic and technical effectiveness [7]. Contrary to this, developing carbonate oil reservoirs with surfactant flooding is limited because of high loss of surfactant, resulting in increased operational costs. Nevertheless, many modeling and experimental studies have shown that surfactant flooding in oil-wet carbonate reservoirs could be a promising way of enhancing oil recovery [17]. Several effective ways have been proposed in the literature in order to overcome the high surfactant loss in carbonate reservoirs.
Conventionally, so-called “sacrificial” agents, such as sodium carbonate, sodium bicarbonate, or polyacrylate have been used to decrease the adsorption of surfactants [46]. The popularity of alkali addition to surfactants stems from their ability to increase pH (>7–8) that lead to an alteration of surface charge from positive toward more negative, which in turn results in a decrease in electrostatic attraction of anionic surfactant molecules to negatively charged surfaces.
However, it should be pointed out that some carbonate reservoirs consist of anhydrites (CaSO4) that can react with alkali and cause the precipitation of CaCO3following the reaction [47]:
CaSO4+Na2CO3→Na2SO4+CaCO3↓E3
Interestingly, it was observed that nonionic or cationic surfactants show less adsorption value on carbonate rocks in comparison with anionic ones [39]. Although, the adsorption value of these surfactants is low, they have been reported to show less effectiveness in terms of oil/brine IFT reduction due to their chemical structure and properties [45]. Therefore, there is still a need for studies of developing the optimal chemical mixtures consistin of surfactants and “sacrificial” agents that can significantly reduce IFT, and exhibit low adsorption values.
Recently, the application of nanoparticle dispersions has been proposed to be promising alternative agent instead of alkali for decreasing adsorption of surfactant onto carbonate surfaces [48]. In the last years, the interest of using nanoparticles for enhancing effectiveness of surfactant EOR has been rapidly growing, with many studies being carried out [48, 49, 50, 51]. Nanofluids or nano-assisted chemical EOR is defined as an injection of fluids that consist of 1–100 nm nanoparticles in colloidal suspension.
Several groups of nanoparticles exist—magnetic (Fe3O4, etc.), metal and non-metal oxides (ZrO2, TiO2, SiO2, Al2O3, ZnO, etc.), and metallic (Cu, Pt, Au, Ag, etc.) [52, 53, 54]. For EOR purposes, the most commonly studied groups of nanoparticles are metal and non-metal oxides due to their unique physical and chemical properties [55]. For instance, these nanoparticles have shown good tolerance to mono and divalent ions (brine) and high thermal stability [56]. In this regard, many experimental studies have been carried out with these types of nanoparticles in order to evaluate their influence on surfactant EOR.
The main mechanisms of nanoparticles as EOR agents include wettability alteration, water/oil IFT reduction, increasing viscosity of injected fluids, disjoining pressure effect, and preventing asphaltene precipitation. Indeed, as it was shown in work [57], the inclusion of nanoparticles enhanced surfactant properties by increasing the stability of surfactant solutions and by helping in the reduction of oil/brine IFT. Moreover, studies also suggest the nanoparticles reduce the volume of surfactant needed for EOR, and thus improve the project economy.
In recent years, several studies have been reported about the influence of different nanoparticles (SiO2, ZnO2, and Al2O3,) on water/air surface and brine/oil IFTs in mixture with surfactants [50, 58, 59]. However, the influence of nanoparticles on the interfacial layer remains uncertain, with some contradicting trends existed in the literature. For instance, Ravera et al. [60] demonstrated that the surface and IFTs of cationic surfactant upon addition of SiO2 nanoparticles increased. On the contrary, Al-Anssari et al. [61] and Lan et al. [62] reported that the inclusion of a small amount of SiO2 nanoparticles to cationic and anionic surfactants resulted in IFT decrease. Furthermore, these results were supported by a study [63], where IFT reduction was observed in the presence of anionic surfactant and high (10 wt.%) concentration of nanoparticles. Moreover, according to the results of Zargartalebi et al. [64], IFT between anionic surfactant solutions with small concentrations (1000 ppm) of hydrophobic or hydrophilic SiO2 nanoparticles and hydrocarbons decreased significantly when the surfactant concentration did not exceed the CMC. However, contrary to this, in the work [59] only a slight IFT reduction between oil and surfactant solutions with 0.5 wt.% ZnO2 nanoparticles was observed. While further increase of surfactant concentration showed no effect on IFT in a range of all nanoparticle concentrations tested [59].
Interestingly the addition of SiO2 nanoparticles to non-ionic surfactant Tween 20 showed a significant reduction of IFT from 44 to 10 mN/m [65]. The IFT decrease from 39 to 17.5 mN/m has been also observed while studying the SiO2/Fe2O3 nanocomposites resulting in an overall 31% OOIP improvement [66]. As can be seen, despite having a significant number of publications in this area, researchers worldwide remain inconclusive over the interfacial behavior of nanoparticles augmented surfactant injection fluids, and further research is required in this area.
Since the development of hydrophobic carbonate oil reservoirs is emerging, different types and combinations of nanoparticles have been tested as additives to surfactant solutions in order to alter wettability towards more water-wet and thus enhance oil recovery [50, 67]. The authors in [67] reported that the addition of SiO2 nanoparticles to anionic surfactant (SDS) aided in the reduction of water contact angle on carbonate surfaces. Importantly, the effect of nanoparticle addition was more pronounced when the surfactant’s concentration was near CMC. Indeed, it was observed that the water advancing contact angle changed from ∿140° to 72° when only 0.2 wt.% of SiO2 nanoparticles were added to the SDS surfactant solution. Whereas, the treatment in surfactant solution without nanoparticles led to less contact angle reduction ∿150° to 110°, illustrating oil-wet preference of carbonate surfaces.
Therefore, the authors [67] suggested that SiO2 augmented surfactant solutions could be an effective fluid for EOR application in carbonate reservoirs, where the oil recovery process depends on wettability alteration. The effect of different nanoparticles and/or nanocomposites on surfactant property to change the wettability of carbonate surfaces has also been studied in many articles. The results of these studies are summarized in Table 3.
The summary of nanoparticles and/or nanocomposites effect on the contact angle of water on carbonate surfaces.
As it can be seen in Table 3, the inclusion of nanoparticles and/or nanocomposites to surfactant solutions helps in wettability alteration of carbonate rocks toward more hydrophilic. As a result, the oil recovery factor also increases. These results have been obtained in different studies with different types of nanoparticles tested, and thus, nanoparticles have been widely regarded as a promising EOR agent.
Therefore, the application of nano-assisted surfactant flooding may be a new chapter of chemical flooding for developing carbonate reservoirs. However, in order to scale this technology from the laboratory to field applications, more laboratory and modeling studies are required.
5. Field applications and challenges of chemical enhanced oil recovery
Generally, after many laboratory screening tests (stability, IFT, static and dynamic adsorption, wettability, and core flooding), successful candidates are selected for a single well tracer test (SWTT). In this test, the surfactant is injected into a well as a slug, and the oil saturation before and after is calculated. This test is performed in order to evaluate the amount of oil that can be reduced. Such a test is less expensive and usually is carried out before a field pilot test.
The scheme of injection may be different depending on reservoir conditions. As such, a scheme may include a so-called preflush, followed by a main slug and postflush. The preflush with alkaline is used to dilute the reservoir brine in order to reduce the concentration of divalent ions that can cause unfavorable surfactant degradation. For instance, sodium silicate, sodium carbonate, and sodium hydroxide were used in preflush slug in Bell Creek project and Salem field [78, 79]. As a postfluch slug usually includes polymers (biopolymers or synthetic) for improving the sweep efficiency after surfactant flooding.
Traditional types of surfactants used in EOR include but are not limited to petroleum sulfonate, ethyl sulfate, alkyl benzene sulfonate, carboxylates, etc. Moreover, many new surfactants are being synthesized mainly for EOR applications in high salinity and temperature conditions, such as biosurfactants and Gemini [80]. However, even if a novel surfactant shows promising economic and technical results in the laboratory, there is no guarantee that this surfactant will have the same effect in the field. The main reasons for this are surfactant production in a field-scales (tones), logistics, and the high cost of chemicals used for synthesis. For example, there are many works dedicated to the development of new effective surfactants that would be applicable in high temperatures and salinities conditions [17, 81]. However, when it comes to the field, the economic evaluation limits their implications.
Therefore, there are not many actual field projects reported in the literature. Moreover, historically, surfactant flooding as an EOR method was developed for sandstone oil reservoirs [17]. This stems from many factors, including pore matrix structure, mild reservoir conditions, low chemicals retention, and adsorption values. Carbonate reservoirs are considered to be promising candidates for surfactant EOR, but exhibit more complex structure and physical-chemical properties than sandstones, and thus only a few projects were conducted with them. Figure 1 illustrates the number of surfactant projects conducted worldwide from the 1990s to the 2000s. It can be seen that the number for sandstone reservoirs surpasses the number of carbonates [82]. Only two projects were performed in carbonates in the USA—Cottonwood Creek [83, 84] and Yates field [85, 86], and one project in Semoga field Indonesia [87] However, it is interesting to point out that pilot tests of surfactant injection in carbonate reservoirs gave promising results. For instance, the Yates field pilot test showed a two-fold increase in oil recovery factor by using commercial surfactant Shell 91-8 [84, 86]. Therefore, surfactant flooding has been regarded as a promising alternative to CO2 injection in carbonates [88].
Figure 1.
Surfactant flooding projects that were conducted worldwide from the 1990s to 2000s [82].
It is important to note that in order to increase the applicability of surfactant EOR, the oil price should not be less than 50$/bbl and the cost of used chemicals should be decreased to a minimum so that the economy of the project will be profitable. This can be done, for instance, by developing the production factories close to the field, which will improve the local chemical production services. Moreover, the governmental support of local development companies is also needed to compensate for the economic risks of chemical EOR.
This chapter presents recent trends in chemical EOR with the emphasis on surfactant flooding and its applications for ensuring cost-effective hydrocarbons production. The mechanism of EOR applications and recent progress in chemical flooding have been addressed. The main challenges of chemical EOR have also been discussed. Field applications of surfactant EOR have been surveyed worldwide, illustrating a trend towards sandstone reservoirs rather than carbonates. Furthermore, a new type of chemical flooding, namely nano-assisted EOR, has been discussed with regards to improving surfactant flooding effectiveness. Nevertheless, the application of this new method is limited to laboratory tests and pilot scales. This can be attributed to some uncertainties associated with technology economics (instability of oil prices), a lack of understanding of the short-term and long-term environmental impact of nanoparticles applications. Therefore, a few recommendations for the future research of chemical EOR can be highlighted:
More studies are required for assessing the effectiveness of nanoparticles in chemical EOR, including an understanding of wettability alteration mechanisms and the impact on foam stability at reservoir conditions. Economic models of nanoparticles applications should be evaluated and compared with other chemicals involved.
Evaluation of nanoparticles application in carbonate reservoirs. So far, conventional chemical flooding is not economically feasible in carbonates. Therefore, new reagents should be investigated for developing an efficient EOR technique yet cost-effective.
Studies are required to investigate the environmental impact of nanoparticles, including reservoir rocks and their possible transfer to underground water. Furthermore, the separation technology of nanoparticles from produced water should also be studied, as already existing membranes may not be efficient with a new method.
There is a lack of modeling of nanoparticles application in EOR for designing field implications. So far, modeling with conventional software is limited, and thus more studies are required to fill this gap.
This work was supported by the Ministry of Science and Higher Education of the Russian Federation under agreement No. 075-10-2022-011 within the framework of the development program for a world-class Research Center.
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Written By
Anastasia Ivanova and Alexey Cheremisin
Submitted: 31 January 2022Reviewed: 29 July 2022Published: 02 November 2022
Open access peer-reviewed chapter
