A Comprehensive Review on Utilizing Nanomaterials in Enhanced Oil Recovery Applications

Abstract

Chemicals are a pivotal part of many operations for the oil and gas industry. The purpose of chemical application in the subsurface reservoir is to decrease the mobility ratio between the displaced fluid and the displacing one or to increase the capillary number. These have been the favorable mechanisms for Enhanced Oil Recovery (EOR). Recently, it became a mainstay with EOR researchers looking for effective and efficient materials that can be economically feasible and environmentally friendly. Therefore, when the development of chemicals reached a peak point by introducing nanosized materials, it was of wondrous interest in EOR. Unlike other sizes, nanoparticles display distinct physical and chemical properties that can be utilized for multiple applications. Therefore, vast amounts of nanoparticles were examined in terms of formulation, size effect, reservoir condition, viscosity, IFT, and wettability alteration. When a holistic understanding of nanoparticles is aimed, it is necessary to review the recent studies comprehensively. This paper reviews the most recently published papers for nanoparticles in oil in general, emphasizing EOR, where most of these publications are between the years 2018 and 2022. It covers a thorough comparison of using nanoparticles in different EOR techniques and the expected range of oil recovery improvements. Moreover, this paper highlights the gaps existing in the field-scale implementation of NPs in EOR and opens space for research and development. The findings of this review paper suggest that the selection of the best NPs type for an EOR application is critical to the reservoir rock properties and conditions, reservoir fluids type, EOR mechanism, chemicals type (surfactant/polymer/alkaline), chemicals concentration used in the flooding process, and NPs properties and concentration.

1. Introduction

As oil and gas remain the primary source of energy, companies are forced to adopt several approaches to ensure sustainable and efficient exploitation of petroleum resources. Some approaches involve launching technology and digitalization in the field and investing in new equipment; others suggest incorporating data science in daily analysis activities [1]. In fact, oil recovery remains the final goal for all research endeavors, which can bring us to summarize what is known about the oil recovery stages. Oil and gas recovery follows three main stages known as primary recovery; where natural reservoir forces produce oil without any reservoir injections, secondary recovery; when fluids are injected in the reservoir to maintain reservoir pressure higher than the bubble point pressure, and tertiary recovery methods known as enhanced oil recovery which will be extensively discussed in this paper [2]. Combined, primary and secondary recovery methods cannot produce more than one-third of the oil and gas reserves. This is due to the interfacial tension (IFT), capillary forces, oil viscosity, and rock wettability that hinders the flow of oil and gas [3,4,5,6]. Here come the role of enhanced oil recovery (EOR) methods which alter these properties to recover greater amounts of the remaining original oil in place (OOIP) [7,8]. Additionally, it is common to use well stimulation methods to improve the recovery of hydrocarbons in certain types of reservoirs [9,10,11,12].

EOR techniques are classified into thermal and non-thermal [13,14,15,16]. Thermal EOR methods include in-situ combustion, steam injection, hot water flooding, and electromagnetic heating [13,14,15,16]. Non-thermal EOR methods, on the other hand, include physical, chemical, and biological methods. Physical EOR methods involve nitrogen, carbon dioxide, hydrocarbon, and water injection; chemical EOR techniques include polymer, alkaline, and surfactant flooding. Finally, biological EOR is classified into biomass, biopolymers, solvents, and biosurfactants flooding [13,14,15,16]. Each method has an exclusive physical process that acts on a specific rock or fluid property. For instance, thermal EOR lowers the oil viscosity to improve its displacement; chemical flooding affects both the viscosity and the interfacial tension of the oil and rock wettability; miscible/immiscible gas flooding lowers the oil viscosity and improves the oil sweep efficiency [13,17,18,19].

Several studies proposed the utilization of nanomaterials in EOR mechanisms, which showed various environmental and economic benefits, as well as improvements in EOR performance [7,20]. When applied in EOR, nanomaterials provide additional modifications to fluid and rock properties, which favors residual oil recovery. For instance, nanomaterials can decrease the interfacial tension, enabling the mobility of oil. Furthermore, it enhances sand consolidation and rock wettability [21]. Unlike other additives, nanomaterials are resistant to degradation under reservoir conditions, where they can handle high salinity, temperature, and pressure environments [22,23]. Nanomaterials can be widely applied in several EOR techniques, where nanofluids used in EOR applications are synthesized by mixing nanoparticles (NPs) with the injection fluids [22,24,25].

Major improvements in laboratory analysis and synthesis have occurred since the late 2000s. Approximately, the available data on NP rapidly increased by 100s of articles, especially for those that deal with their applications in EOR. The evolution in the formulation, methodology, data analysis, and field studies resulted in transitioning from just a wishful implementation to a powerful candidate that can replace conventional chemicals in field operations. Consequently, this study aims to present a comprehensive review of the major recent studies conducted using NP in the oil and gas industry in general and in enhanced oil recovery in particular. It covers over 100 different studies published within the period from 2018 to 2022. The study also highlights the major challenges that still exist in the literature and that require further investigation. This provides insights for scholars to further explore this field by emphasizing the existing research gaps. The article is arranged as follows. Section 2 gives a general definition of nanomaterials and identifies the commonly used types in the application of EOR. Section 3 gives an overview of the commonly used EOR techniques without including nanomaterials in them. It follows with a deep investigation of different applications of nanomaterials in different EOR applications. Section 4 compares and discusses the expected recovery factors using various kinds of nanomaterials in EOR and then highlights the remaining existing challenges in utilizing nanomaterials in real-field applications. Finally, Section 5 summarizes and concludes the main points covered in this article.

2. Nanomaterials Definition and Types

Nanomaterials are nanosized particles that are smaller than one micrometer. They are classified according to their structure and shape as nanoparticles, nanoclays, and nanoemulsions, as shown in Figure 1 [26,27]. Nanoparticles are divided into inorganic nanoparticles, including ceramic and metal nanoparticles, and organic nanoparticles, including polymer, carbon, and lipid-based nanoparticles [28,29,30,31,32,33]. Nanoclays consist of layers of silicate minerals such as saponite and kaolinite, while nanoemulsions are suspended systems consisting of water in oil, oil in water, and bicontinuous nanoemulsions [28,34].

Ceramic, metal, metal oxide, and semiconducting nanoparticles are inorganic, while biomolecules and polymeric nanoparticles are organic [35,36]. Ceramic NPs consist of ceramic materials such as silica, alumina, titanium dioxide, zirconium, and calcium phosphates [30,36]. Ceramic NPs are porous, making them resistant to degranulation, degradation, and extreme environments (Temperature and pH). They are synthesized under heat or heat and pressure, and they consist of a solid core. Ceramic NPs can be a combination of a metal and a nonmetal, two nonmetallic solids at least, a nonmetal with at least two nonmetallic elemental solids, and metal and nonmetallic elemental [30].

Metal and metal oxide NPs include gold, silver, platinum, palladium, zinc and zinc oxide, copper and copper oxide, nickel and nickel oxide, titanium dioxide, and iron oxide [36]. Metal and metal oxide NPs are characterized by improved mechanical, electrical, electromagnetic, thermal, and chemical properties, making them feasible for many field applications [35].

Semiconducting NPs, such as cadmium telluride, cadmium selenide, zinc oxide, zinc sulfide, mercuric selenide, and others, are characterized by their electronic and optical properties that are size and shape-dependent [36,37]. Semiconducting nanoparticles are integrated into many technologies, such as microelectronic circuits, piezoelectric devices, and sensors. They are also broadly used in energy applications as corrosion coatings and catalysts [38].

Polymer-based NPs are colloidal bodies that are made up of small, water-soluble, non-toxic, stable, and biodegradable polymers. There are two types of polymer NPs: nanospheres and nanocapsules [36]. Polymeric NPs are formed by the dispersion of preformed polymers, monomer polymerization, hydrophilic polymer coacervation, and ionic gelatin. The most common polymer-based NPs are the ones made up of gelatin, polylactic acid, chitosan, and copolymer. Moreover, these NPs can be used to coat other types of NPs [36,39].

Other organic NPs include biomolecules-based NPs such as lipid, protein, nucleic acid, and polysaccharide-based NPs. These NPs can be integrated with other inorganic NPs to form biomolecule NPs hybrids [40]. These combinations aim to improve the surface properties of NPs.

Carbon-based NPs, including carbon dots, carbon nanotubes, carbon quantum dots, graphene, and others, are other types of NPs that are applied in biological imaging, chemical, and optical sensing, solar panels, sensors, photocatalysis, and other fields [36,41]. There are three main categories of carbon NPs: graphene quantum dots composed of sheet nanodots, carbon nanodots consisting of amorphous nanodots, and carbon quantum dots having crystalline structures [41,42]. Further classification of organic and inorganic nanoparticles is illustrated in Figure 2.

Nanoclays are a class of nanomaterials consisting of layers of mineral silicate or clay, as shown in Figure 3. They are classified according to their chemical structure and morphology [22]. Examples of nanoclays are bentonite, montmorillonite, hectorite, kaolinite, halloysite, and others. Nanoclays can be combined with polymers by in-situ polymerization, melt mixing, solo-gel templating, or solution methods to yield nanoclay-reinforced polymers [22,34]. Organoclays and nanoclays are prepared using hydrophilic clay molecules such as aqueous or solid phosphonium, alkyl/aryl ammonium, or imidazolium. Two outcomes can result from this ion-exchange reaction, the first is a further separation between the single sheets allowing the chains of cations to freely move between these sheets, and the second is the alteration of the surface properties of these sheets (i.e., hydrophilic to hydrophobic or organophilic). The morphology of polymer nanoclays is represented in Figure 3. X-ray diffraction, gravimetric analysis, Fourier transform, and inductive coupled plasma are commonly used methods to study the chemical properties of nanoclays [22,26,43].

Nanoemulsion is defined as a soft material that results from the dispersion of solid substances, droplets, and polymers, forming a viscous liquid. This liquid is a thermodynamically stable and isentropic system [44]. The discontinuous and dispersed phase is termed the internal phase, while the continuous outer phase is known as the dispersion medium, where the emulsifying agent is referred to as the intermediate phase; this is further demonstrated in Figure 4 [26]. Nanoemulsions are usually made by emulsification at high energy through ultrasonification, homogenization at high pressure, and microfluidizer, or by solvent displacement and phase inversion temperature and composition that are counted as low energy emulsification [26,44]. Oil in water, water in oil, and bicontinuous nanoemulsions are the three most common types of nanoemulsions [45,46].

3. Application of Nanomaterials in EOR

The implementation of nanoparticles in EOR techniques is a novel method that has proven to increase the recovery of oil in place more than conventional EOR processes in most cases [47]. The main aim of integrating nanoparticles in EOR methods is to boost the performance of each EOR technique by enhancing one or more parameters or mechanisms related to the recovery method. Sometimes, adding nanoparticles to the EOR method might reduce oil recovery due to porosity reduction, injection blockage, aggregation, and settling problems [48]. The respective mechanisms, challenges, oil recovery range, and agents used in each EOR mechanism are listed in Table 1.

The utilization of nanomaterials in several EOR applications comes with many benefits, such as IFT reduction, wettability alteration, and mobility improvement [22,49]. The following sections demonstrate the application of nanomaterials in different EOR methods.

Table 1. Classification of EOR methods with their respective mechanisms, challenges, limitations, agents utilized, and expected recovery rates, without including NPs.

EOR Methods		Mechanisms	Challenges	Agents	R.F.	Ref.
Chemical EOR	Alkaline Flooding	Lowers IFT Displacement and sweep efficiencies improvement Wettability alteration	Viscous fingering Expensive Heat and salinity sensitive Scale formation Not applicable in carbonate rocks Limited to oil of 13<API<35 Retention and chemical availability	15.87–20.4 Kg of alkaline/ bbl oil produced	5%	[13,21,22,50,51]
	Polymer Flooding	Increase in injected water viscosity and decrease its mobility Increase contact volume with the reservoir Modifies wettability Enhances displacement and sweep efficiencies	Not applicable for reservoir temperature >93 °C High salinity and shear degradation reduces viscosity High viscosity requires higher polymer concentrations Injectivity and stability issues High cost	136–227 g of polymer/ bbl oil produced	5–12%	[13,21,22,51,52,53,54]
	Surfactant Flooding	Decrease IFT Enhances displacement and sweep efficiencies Oil Solubilization Oil/water emulsification Wettability alteration	Surfactant adsorption and interaction with polymer Chemical degradation at high temperature Injectivity/stability problems at high salinity Retention/availability Limited to homogeneous formations of low clay/anhydrite/chloride concentrations High cost	6.8–11.34 Kg of surfactant/bbl oil produced	10–15%	[13,21,22,51,55,56,57]
Thermal EOR	In-Situ Combustion	Reduce oil viscosity and IFT through conduction and convection Air injected increases reservoir pressure Reduce oil saturation Liquid vaporizing and steam generation Improves displacement and sweep efficiency Gravity drainage	High costs involved Release flue gas that damages the environment Combustion is difficult to control Creates oil-water emulsions and increases sand production Severe corrosion and pipe failure due to high temperature HealHeat losses High coke slows combustion	10,000 scf of air/ bbl oil produced	10–15%	[13,21,22,50,58]
	Steam Injection	Thermal expansion Pressurizing the reservoir Reducing oil viscosity Solvent extraction and steam distillation Improving displacement and sweep efficiency Gravity drainage Reduce IFT	Heat losses and pollution Unfavorable mobility ratio Steam channeling Gravity override Limited to shallow and highly permeable sandstones or unconsolidated sands of more than 20ft pay zone thickness Requires high saturation of viscous oil Unfavorable for aquifers and gas caps High costs	0.5 bbl oil consumed/bbl oil produced	50–60%	[13,21,22,50]
Miscible Gas EOR Miscible Gas Miscible Gas	Flue Gas and Nitrogen Injection	Reduce oil viscosity Vaporizing light crude oil components Provide a gas drive to maintain pressure and assist injectivity Displacement efficiency improvement Oil expansion	Flue gas problems due to corrosion Viscous fingering and poor horizontal and vertical sweep efficiencies Limited to deep reservoirs Favorable in dipping formations Miscibility with light oil requires high pressure Asphaltene problems	10,000 scf of flue gas or N2/ bbl oil produced	5–15%	[13,21,22,59,60]
	HC Gas Injection	Enhance displacement efficiency Oil expansion and swelling Reduce oil viscosity Miscibility achieved in vaporizing and condensing gas drive Assist reservoir pressure	Materials are expensive The solvent may be trapped Poor horizontal and vertical sweep efficiencies cause viscous fingering Steeply dipping reservoirs are favorable to allow gravity stabilization Requires high pressure Gas corrosion Asphaltene problems	10,000 scf of LPG./ bbl oil produced	5–15%	[13,21,22,61,62]
	CO2 Injection	Miscibility between oil and CO2 is developed Reduce oil viscosity Oil swelling and expansion Reduce IFT between oil and CO2 Assist displacement efficiency Pressurize reservoir	Corrosion of wells Early CO2 breakthrough High solvent volume required per oil bbl CO2 availability Hard to control viscosity due to low CO2 viscosity Problems in stability and supply Asphaltene problems CO2 repressuring	10,000 scf of CO2/ bbl oil produced	5–15%	[13,21,22,63,64,65]

Table 1. Classification of EOR methods with their respective mechanisms, challenges, limitations, agents utilized, and expected recovery rates, without including NPs.

EOR Methods		Mechanisms	Challenges	Agents	R.F.	Ref.
Chemical EOR	Alkaline Flooding	Lowers IFT Displacement and sweep efficiencies improvement Wettability alteration	Viscous fingering Expensive Heat and salinity sensitive Scale formation Not applicable in carbonate rocks Limited to oil of 13<API<35 Retention and chemical availability	15.87–20.4 Kg of alkaline/ bbl oil produced	5%	[13,21,22,50,51]
	Polymer Flooding	Increase in injected water viscosity and decrease its mobility Increase contact volume with the reservoir Modifies wettability Enhances displacement and sweep efficiencies	Not applicable for reservoir temperature >93 °C High salinity and shear degradation reduces viscosity High viscosity requires higher polymer concentrations Injectivity and stability issues High cost	136–227 g of polymer/ bbl oil produced	5–12%	[13,21,22,51,52,53,54]
	Surfactant Flooding	Decrease IFT Enhances displacement and sweep efficiencies Oil Solubilization Oil/water emulsification Wettability alteration	Surfactant adsorption and interaction with polymer Chemical degradation at high temperature Injectivity/stability problems at high salinity Retention/availability Limited to homogeneous formations of low clay/anhydrite/chloride concentrations High cost	6.8–11.34 Kg of surfactant/bbl oil produced	10–15%	[13,21,22,51,55,56,57]
Thermal EOR	In-Situ Combustion	Reduce oil viscosity and IFT through conduction and convection Air injected increases reservoir pressure Reduce oil saturation Liquid vaporizing and steam generation Improves displacement and sweep efficiency Gravity drainage	High costs involved Release flue gas that damages the environment Combustion is difficult to control Creates oil-water emulsions and increases sand production Severe corrosion and pipe failure due to high temperature HealHeat losses High coke slows combustion	10,000 scf of air/ bbl oil produced	10–15%	[13,21,22,50,58]
	Steam Injection	Thermal expansion Pressurizing the reservoir Reducing oil viscosity Solvent extraction and steam distillation Improving displacement and sweep efficiency Gravity drainage Reduce IFT	Heat losses and pollution Unfavorable mobility ratio Steam channeling Gravity override Limited to shallow and highly permeable sandstones or unconsolidated sands of more than 20ft pay zone thickness Requires high saturation of viscous oil Unfavorable for aquifers and gas caps High costs	0.5 bbl oil consumed/bbl oil produced	50–60%	[13,21,22,50]
Miscible Gas EOR Miscible Gas Miscible Gas	Flue Gas and Nitrogen Injection	Reduce oil viscosity Vaporizing light crude oil components Provide a gas drive to maintain pressure and assist injectivity Displacement efficiency improvement Oil expansion	Flue gas problems due to corrosion Viscous fingering and poor horizontal and vertical sweep efficiencies Limited to deep reservoirs Favorable in dipping formations Miscibility with light oil requires high pressure Asphaltene problems	10,000 scf of flue gas or N2/ bbl oil produced	5–15%	[13,21,22,59,60]
	HC Gas Injection	Enhance displacement efficiency Oil expansion and swelling Reduce oil viscosity Miscibility achieved in vaporizing and condensing gas drive Assist reservoir pressure	Materials are expensive The solvent may be trapped Poor horizontal and vertical sweep efficiencies cause viscous fingering Steeply dipping reservoirs are favorable to allow gravity stabilization Requires high pressure Gas corrosion Asphaltene problems	10,000 scf of LPG./ bbl oil produced	5–15%	[13,21,22,61,62]
	CO2 Injection	Miscibility between oil and CO2 is developed Reduce oil viscosity Oil swelling and expansion Reduce IFT between oil and CO2 Assist displacement efficiency Pressurize reservoir	Corrosion of wells Early CO2 breakthrough High solvent volume required per oil bbl CO2 availability Hard to control viscosity due to low CO2 viscosity Problems in stability and supply Asphaltene problems CO2 repressuring	10,000 scf of CO2/ bbl oil produced	5–15%	[13,21,22,63,64,65]

3.1. Application of Nanomaterials in Chemical EOR

The integration of nanotechnology in chemically enhanced oil recovery can help overcome the major limitations of chemical EOR and improve its efficiency. Such limitations include chemical adsorption, retention, degradation, and precipitation due to reservoir water brines. These processes are mainly caused by the high salinity and high temperature of the reservoir, the pH and composition of the reservoir fluids, and the presence of clay minerals in the reservoir rock [24].

Surfactant and polymeric nanofluids are a mixture of nanoparticles with surfactant and polymer solutions, respectively. These two nanomaterial types are the most applied and studied in the chemical EOR. According to recent studies listed in Table 2 and Table 3, the most commonly applied nanoparticles in chemical EOR include SiO₂, TiO₂, Al₂O₃, graphene, and ZnO.

3.1.1. Nanosurfactant EOR

In nanosurfactant EOR, nanoparticles can help increase the displacement efficiency through rock wettability alteration and further reduction of interfacial tension [24]. Emulsions that provide conformance efficiency and stable foams that help achieve fluid diversion to low permeability locations are created in the reservoir. Nanoparticles reduce the surfactant adsorption onto the reservoir rock surface, where the surfactants are adsorbed onto the surface of the nanoparticles resulting in surfactant-coated NPs [66]. A low surfactant-to-NP ratio results in a low fraction of surfactant-coated NPs. Moreover, a high surfactant-to-NP ratio causes a bilayer of surfactant to form on the surface of NPs. A single-chain surfactant achieves maximum hydrophobic nature and flocculation on NPs, leading to optimal performance [66].

According to several studies, IFT reduction by surfactant nanofluids is optimum in high-salinity and high-temperature environments, especially when using silica nanoparticles (SiO₂) [66]. Mohajeri et al. [67] compared the performance of two surfactant nanofluids in reducing the oil/water interfacial tension [67]. The used surfactant nanofluids are zirconium dioxide (ZrO₂) NP mixed with sodium dodecyl sulfate (SDS), which is an anionic surfactant and cetyltrimethylammonium bromide (CTAB) known as a cationic surfactant [68]. The results showed that SDS/ZrO₂ nanofluid reduced the oil-water IFT by 81% more than the CTAB/ZrO₂ combination, which reduced it by 70%. The combination of silica NPs with anionic surfactants such as SDS has shown improvements in the performance of the surfactant, whether in IFT reduction, recovery of oil, and the reduction of surfactant adsorption [66].

Studies have shown that the NP’s surface becomes hydrophobic after the adsorption of surfactants on NPs. NPs carry the surfactants from the surfactant solution to the oil-water interface, where IFT is reduced by reducing the interfacial energy. Typically, surfactant molecules desorb from the oil-water interface in surfactant flooding, but the utilization of NPs helps prevent desorption, thus maintaining better IFT reduction [66].

When the interfacial energy decreases, wettability alterations occur along with a change in the relative permeability of oil and water. Nanoparticles can strongly alter the wettability of the rock from oil-wet to water-wet, which helps recover the residual oil more efficiently. Surfactant nanofluids have proven to be effective in recovering oil from carbonate reservoirs that are hydrophobic [66]. Nwidee et al. [69] studied the wettability alteration of surfactant nanofluids, where they compared the performance of ZrO₂ and NiO NPs with triton X-100 and CTAB surfactants at temperatures ranging from 0 °C up to 70 °C [69]. They found that the combination of CTAB with ZrO₂ and NiO yielded better overall performance in the efficiency of wettability alteration at all temperatures.

Surfactant flooding becomes economically unfeasible due to the adsorption of the surfactant molecules on the reservoir rock surface. Oil recovery is improved with less surfactant adsorption; here lies the main function of NPs in surfactant EOR [24,66]. An experiment using SiO₂ and Al₂O₃ NPs in SDS flooding of a kaolinite sample saturated with reservoir brine showed a significant reduction in surfactant adsorption. The addition of Al₂O₃ NP reduced the SDS adsorption on the surface of kaolinite by 38%, compared to 75% when using SiO₂ with SDS. Surfactant nanofluids have also improved oil recovery from sandstone reservoirs by increasing the effective permeability of oil, favoring oil displacement [66].

Another benefit of using NPs is to stabilize foams that are unstable in the presence of oil and reservoir brine. NPs help elongate the foam half-life and help withstand harsh reservoir conditions [24,66]. At the lamellae interface between the gas and liquid phases, NPs adsorb with strong adhesion energy by irreversible attachment. Additional studies on the application of nanoparticles in surfactant flooding and their corresponding incremental recovery factors are summarized in Table 2.

Table 2. Previous studies on the performance of surfactant nanofluids.

Surfactant	NPs	NPs Conc.	Base Fluid	Displaced Fluid	Mechanism	RF+	Ref.
Sulphanole	Light non-ferrous metal	0.001%	-	Heavy oil	Wettability and IFT alteration	17–22%	[70]
PRNS	Al2O3	100–10,000 ppm	Distilled water	Heavy crude oil	Wettability alteration	–	[71]
Cetyltrimethyl ammonium bromide (CTAB)	SiO2	0.05–0.5%	Brine (0.5 wt%)	Heavy crude oil	Emulsion stability	–	[72]
Non-ionic surfactant (Tween 80)	Acidic silica SiO2A, SiO2, and Al2O3	1 wt%	Distilled water	Heavy crude oil	Viscosity alteration	16%	[73]
Sodium dodecyl sulfate (SDS)	SiO2	0.1–0.5 wt%	Distilled water	Crude oil from Tahe oilfield	IFT Reduction	4.68%	[74]
SDBS (anionic surfactant) + 2-Propanol (alcoholic surfactant)	Carbon structures including MWCNT & nanoporous graphene + SiO2	0.3 wt%	Distilled water	Crude oil	Wettability and IFT alteration	–	[75]
Cetyltrimethyl ammonium bromide (CTAB)	SiO2	0.1–5%	Double distilled water	Normal heptane	IFT reduction	–	[76]
Octadecylamine (cationic surfactant)	Amphiphilc graphene-based Janus nanosheets	0.005 & 0.01 wt%	Brine	Crude oil	IFT and wettability alteration	≤7.5%	[77]
Tetramethylsilane (TMS.)	Nanohybrid of silica-graphene	0.01, 0.05, and 0.1 wt%	Brine (4 wt% NaCl)	Degassed crude oil	IFT reduction	–	[78]
TX-100 (nonionic surfactant)	SiO2	0.1 wt%	Brine (3 wt% NaCl)	Dehydrated crude oil mixed with kerosene	Wettability and IFT alteration	16%	[79]
SDBS (Sodium dodecyl benzenesulfonate)	Zinc oxide (ZnO)	0.1 wt%	Brine (3 wt% NaCl)	Crude oil from Tapis oilfield	IFT reduction	6.66-7.05%	[80]
SDBS	Sulphonated graphene	0.5–2 g/L	Brine (10,0000 ppm NaCl)	Degassed crude oil from S-W Iran	IFT and wettability alteration	8–14%	[81]
Oleic and polyacrylic acid, anionic, cationic, and nonionic surfactants	TiO2, SOx, and Al2O3	0.1 wt%	Distilled water	Heavy crude oil	Wettability alteration and reduction in disjoining pressure	6.2%	[82]
Alcohol polyethylene glycol ether carboxylic sodium (anionic surfactant)	SiO2	0–0.05 wt%	Brine (15 wt% NaCl)	Crude oil from the Bakken oilfield	Increased water wettability and reduced IFT	17.23%	[83]
Cocamidopropyl hydroxysultaine (CAPHS)	SiO2	4 g/L	Brine (3.5 wt% NaCl)	Crude oil	IFT and wettability alteration	3.12+ 5.39%	[84]
Anionic surfactants (SA and SB)	CNA and CNB	0.1 g/L	Synthetic brine (containing NaCl, KCl, CaCl2, MgCl2, and BaCl2)	Heavy crude oil from Colombian oilfield	IFT and wettability alteration	22%	[85]
Anionic surfactant Sodium Dodecyl Sulfate (SDS) and nonionic surfactant Triton X100 (TX100)	SiO2	0.2, 0.4, 0.6, 0.8, and 1 wt%	Brine (3 wt% NaCl)	Tapis crude oil	Surface and interfacial tension alteration	–	[86]
Sodium dodecyl sulfate (SDS.)	Al2O3	0.3 wt%	Synthetic reservoir brine	Crude oil from Iranian oilfields	IFT and wettability alteration	15.18%	[87]

Table 2. Previous studies on the performance of surfactant nanofluids.

Surfactant	NPs	NPs Conc.	Base Fluid	Displaced Fluid	Mechanism	RF+	Ref.
Sulphanole	Light non-ferrous metal	0.001%	-	Heavy oil	Wettability and IFT alteration	17–22%	[70]
PRNS	Al2O3	100–10,000 ppm	Distilled water	Heavy crude oil	Wettability alteration	–	[71]
Cetyltrimethyl ammonium bromide (CTAB)	SiO2	0.05–0.5%	Brine (0.5 wt%)	Heavy crude oil	Emulsion stability	–	[72]
Non-ionic surfactant (Tween 80)	Acidic silica SiO2A, SiO2, and Al2O3	1 wt%	Distilled water	Heavy crude oil	Viscosity alteration	16%	[73]
Sodium dodecyl sulfate (SDS)	SiO2	0.1–0.5 wt%	Distilled water	Crude oil from Tahe oilfield	IFT Reduction	4.68%	[74]
SDBS (anionic surfactant) + 2-Propanol (alcoholic surfactant)	Carbon structures including MWCNT & nanoporous graphene + SiO2	0.3 wt%	Distilled water	Crude oil	Wettability and IFT alteration	–	[75]
Cetyltrimethyl ammonium bromide (CTAB)	SiO2	0.1–5%	Double distilled water	Normal heptane	IFT reduction	–	[76]
Octadecylamine (cationic surfactant)	Amphiphilc graphene-based Janus nanosheets	0.005 & 0.01 wt%	Brine	Crude oil	IFT and wettability alteration	≤7.5%	[77]
Tetramethylsilane (TMS.)	Nanohybrid of silica-graphene	0.01, 0.05, and 0.1 wt%	Brine (4 wt% NaCl)	Degassed crude oil	IFT reduction	–	[78]
TX-100 (nonionic surfactant)	SiO2	0.1 wt%	Brine (3 wt% NaCl)	Dehydrated crude oil mixed with kerosene	Wettability and IFT alteration	16%	[79]
SDBS (Sodium dodecyl benzenesulfonate)	Zinc oxide (ZnO)	0.1 wt%	Brine (3 wt% NaCl)	Crude oil from Tapis oilfield	IFT reduction	6.66-7.05%	[80]
SDBS	Sulphonated graphene	0.5–2 g/L	Brine (10,0000 ppm NaCl)	Degassed crude oil from S-W Iran	IFT and wettability alteration	8–14%	[81]
Oleic and polyacrylic acid, anionic, cationic, and nonionic surfactants	TiO2, SOx, and Al2O3	0.1 wt%	Distilled water	Heavy crude oil	Wettability alteration and reduction in disjoining pressure	6.2%	[82]
Alcohol polyethylene glycol ether carboxylic sodium (anionic surfactant)	SiO2	0–0.05 wt%	Brine (15 wt% NaCl)	Crude oil from the Bakken oilfield	Increased water wettability and reduced IFT	17.23%	[83]
Cocamidopropyl hydroxysultaine (CAPHS)	SiO2	4 g/L	Brine (3.5 wt% NaCl)	Crude oil	IFT and wettability alteration	3.12+ 5.39%	[84]
Anionic surfactants (SA and SB)	CNA and CNB	0.1 g/L	Synthetic brine (containing NaCl, KCl, CaCl2, MgCl2, and BaCl2)	Heavy crude oil from Colombian oilfield	IFT and wettability alteration	22%	[85]
Anionic surfactant Sodium Dodecyl Sulfate (SDS) and nonionic surfactant Triton X100 (TX100)	SiO2	0.2, 0.4, 0.6, 0.8, and 1 wt%	Brine (3 wt% NaCl)	Tapis crude oil	Surface and interfacial tension alteration	–	[86]
Sodium dodecyl sulfate (SDS.)	Al2O3	0.3 wt%	Synthetic reservoir brine	Crude oil from Iranian oilfields	IFT and wettability alteration	15.18%	[87]

In order to achieve highly stable surfactant nanofluids, they must withstand high temperatures and high salinity environments [88]. This can be done by modifying the adsorption of the surfactant on the surface of NPs. The most commonly used NPs for such applications are metallic, metal oxide, and nonmetal NPs. Usually, metal NPs show great stability when mixed with surfactants, unlike their metal oxide and nonmetal counterparts. Nonmetal and metal oxide NPs require surface modifications to achieve the desired stability [88,89]. For instance, active groups, such as hydroxyl, carbonyl, and carboxyl groups, are attached to the surface of NPs to modify the chemical binding of the NPs with the surfactant. This increases the nanofluid stability and hence the capacity for oil displacement [88].

Based on the experiments made so far, the performance of surfactant nanofluid flooding not only depends on the type of NPs used but also on the surfactant type [61,62,63,64]. Each NP has a specific surfactant that yields an optimal performance when applied together. Among the studied NPs, SiO₂ displayed robustness and optimal performance under harsh conditions [61,62,63,64]. Furthermore, other factors such as the NPs and surfactant concentration, reservoir conditions, reservoir rock properties, and others can have a detrimental influence on the results of the nanosurfactant EOR.

There are no similar scenarios when applying nanosurfactant EOR. A nanosurfactant fluid might yield optimal performance in one reservoir while yielding the worst performance in the other. Each scenario requires extensive research to produce the best surfactant and NPs mix that yields the highest incremental recovery factor.

3.1.2. Nanopolymers EOR

Nanopolymers are classified into polymer-coated NPs and polymer NPs, where polymer-coated NPs are more effective when it comes to NPs agglomeration in the reservoir [22]. Polymer NPs are synthesized to avoid the dissociation of polymers in polymer solution at reservoir conditions [90]. Mixing NPs with a polymer solution enhanced the stability, performance characteristics, tolerance to harsh conditions, and thermal characteristics of the injectant compared to the sole application of NPs and polymer solutions [91]. NPs interact with polymers in 5 ways:

• Electrosteric repulsion.
• Electrostatic and van der Waals forces.
• Steric repulsion.
• Hydrophobic bonding.
• Hydrogen-hydrogen bonds.

Polymers bind to NPs through polymer grafting on the NP’s surface by chemical bonding. This is known as polymer-grafted NPs (PGN). Another method is the suspension of NPs in the polymer solution, known as polymer nanofluid suspension (PNS) hybrid [66,91]. Nanopolymers formed by PGN are more effective than those formed by PNS. This is due to the polyelectrolytes found in PGN that are not vulnerable to bonding with the cations present in brines.

The oil extraction efficiency is better in water-wet reservoirs than in oil-wet ones, where the NPs integrated into the polymer solution can alter the reservoir’s wettability. Nanoparticles reduce the capillary forces, switch the reservoir to water-wet, and consequently improve oil mobility and relative permeability, as shown in Figure 5 [91].

As shown in Figure 5, NPs develop a wedge coating when they come into contact with an oil-rich surface and consequently form a wedge film at the interface between the oil phase, rock, and nanofluid [22,66]. The rise in the wedge film results in a disjoining pressure gradient that alters the rock surface wettability [22,92]. Altering the rock wettability by NPs in nanofluids contribute to the improvement in the microscopic displacement efficiency.

Experiments have shown that the adsorption of polymers on the surface of the reservoir rock is reduced when adding NPs to the polymer solution. This is mainly because of the solution’s interaction and bonding between the NPs and the polymers [22,66]. Furthermore, the settlement of NPs in the reservoir pores (i.e., filtration) is reduced when using polymeric nanofluids rather than NPs alone. The adsorption of NPs in the pores of the rock can cause serious problems, where it lowers the rock’s permeability and blocks the pores and pore throats, leading to low mobility and EOR efficiency [91]. The polymer and NPs adsorption level in the reservoir is controlled by the polymer concentration (whether hydrophilic or hydrophobic) on the NP’s surface. Moreover, the rate of adsorption drops due to the forces of repulsion on the NP’s surface triggered by the polymer coating and due to decreased hydrophobic forces between the polymer-grafted NPs and the rock surface [91]. However, polymer nanofluid suspension (PNS) reduces adsorption by having NPs of the same charge as the reservoir rock surface. This will trigger repulsive forces between the nanofluid and the rock surface, improving the nanofluid stability and recovery efficiency [91].

NPs in polymeric nanofluids adsorb to the oil-water interface, consequently lowering the IFT at the interface. Stable emulsions are formed at the interface, which decreases the mobility ratio between the nanofluid and the residual oil. This improves the areal and vertical sweep efficiencies [91]. For many reasons, emulsions formed by polymer nanofluids are more effective than those formed by surfactants. For instance, the morphology of the emulsions formed by polymer nanofluids is kinetically affected by the volume of the residual oil. Furthermore, the NPs in polymer nanofluids are less susceptible to retention and can travel throughout the reservoir, maintaining stabilized emulsions. Such emulsions remain stable under extreme reservoir conditions, which is advantageous over emulsions created by surfactants [24,91].

Generally, polymers degrade under reservoir conditions, and the viscosity of the displacing fluid drops with temperature, which reduces the sweep efficiency. Another benefit of the utilization of NPs in polymer flooding is the improvement of the polymer viscosity and its stability under reservoir conditions (i.e., high pressure, temperature, and salinity). The viscosity of the polymer nanofluid is higher than that of the normal polymer solution due to the networking formed by NPs in the solution as a result of the hydrogen bonds between them [24].

NPs enhance the rheological behavior of the displacing fluid (polymer nanofluid), and this prevents the viscous fingering mechanism and ensures an appropriate mobility ratio. The viscosity of the displacing fluid drops in the reservoir due to the reaction of the cations found in the formation of water with amide and carboxylate groups in polymers [66]. In the case of polymer nanofluids, the electrostatic forces between NPs in the solution rise in the presence of brine cations. Consequently, the surface functionality is lost, which is desirable in EOR [22].

A summary of some recent studies performed on the application of NPs in polymer flooding and the corresponding incremental recovery rates are listed in Table 3.

Table 3. Recent studies on polymer nanofluids application in EOR.

Polymer	NPs Type	Nanofluid Type	Base Fluid	Polymer Conc.	Rock Type	R.F +	Ref.
Xanthan gum	Polymer-coated ZnO and SiO2	PGN	Seawater from the Persian Gulf	2000ppm polymer-coated NPs	Carbonate	19.28%	[25]
Hydrolyzed polyacrylamide (HPAM)	Al2O3 and SiO2	PNS	Brine (0.5–3.41 wt% NaCl)	2000ppm	Sandstone	11.3%	[93]
Polyacrylamide (PAM)	ZnO, SiO2, TiO2	PNS	Brine (3wt% NaCl)	1000ppm	Sandstone	12–20%	[94]
Polyvinylpyrrolidone/povidone (PVP–K30)	SiO2	PNS	Low salinity diluted seawater	1000ppm	Berea sandstone	6.5–55.38%	[95]
Xanthan gum	TiO2	PNS	Brine (50,000ppm NaCl)	2000ppm	Carbonate	12–25%	[29]
Xanthan gum	SiO2, TiO2, and Al2O3	PNS	Distilled water	0.5wt%	Sandstone	25.2% for SiO2, 27.6% for TiO2, and 28.4% for Al2O3	[96]
Gum Arabic	Graphene	PGN-PNS	High salinity brine	0.05g/L	Sandstone	5% for PNS–17% for PGN	[97]
Hydrophobic associating polyacrylamide (PAAM)	SiO2	PGN	Synthetic brine	0.15wt%	Berea outcrop sandstone	7.82%	[98]
Fluoropolymer	SiO2	PGN	–	0.1wt%	Carbonate	–	[99]
Partially hydrolyzed polyacrylamide (HPAM)	Graphene oxide (GO)	PNS	Synthetic brine (containing KCl, NaCl, KBr, CaCl2, MgCl2, and Na2SO4)	1 g/L	–	–	[100]

Table 3. Recent studies on polymer nanofluids application in EOR.

Polymer	NPs Type	Nanofluid Type	Base Fluid	Polymer Conc.	Rock Type	R.F +	Ref.
Xanthan gum	Polymer-coated ZnO and SiO2	PGN	Seawater from the Persian Gulf	2000ppm polymer-coated NPs	Carbonate	19.28%	[25]
Hydrolyzed polyacrylamide (HPAM)	Al2O3 and SiO2	PNS	Brine (0.5–3.41 wt% NaCl)	2000ppm	Sandstone	11.3%	[93]
Polyacrylamide (PAM)	ZnO, SiO2, TiO2	PNS	Brine (3wt% NaCl)	1000ppm	Sandstone	12–20%	[94]
Polyvinylpyrrolidone/povidone (PVP–K30)	SiO2	PNS	Low salinity diluted seawater	1000ppm	Berea sandstone	6.5–55.38%	[95]
Xanthan gum	TiO2	PNS	Brine (50,000ppm NaCl)	2000ppm	Carbonate	12–25%	[29]
Xanthan gum	SiO2, TiO2, and Al2O3	PNS	Distilled water	0.5wt%	Sandstone	25.2% for SiO2, 27.6% for TiO2, and 28.4% for Al2O3	[96]
Gum Arabic	Graphene	PGN-PNS	High salinity brine	0.05g/L	Sandstone	5% for PNS–17% for PGN	[97]
Hydrophobic associating polyacrylamide (PAAM)	SiO2	PGN	Synthetic brine	0.15wt%	Berea outcrop sandstone	7.82%	[98]
Fluoropolymer	SiO2	PGN	–	0.1wt%	Carbonate	–	[99]
Partially hydrolyzed polyacrylamide (HPAM)	Graphene oxide (GO)	PNS	Synthetic brine (containing KCl, NaCl, KBr, CaCl2, MgCl2, and Na2SO4)	1 g/L	–	–	[100]

The performance of NPs application in chemical EOR has been mostly assessed with surfactants or polymers separately. The literature lacks studies on the hybrid application of NPs in surfactant-polymer solution mixtures. We believe that this hybrid application can bring a synergetic effect on the performance of EOR applications knowing that SP (surfactant-polymer) flooding has been tested and proved to yield better results than separate polymer or surfactant flooding [101,102].

3.1.3. Synergy between Low Salinity Waterflooding (LSWF), Surfactant, and Nanoparticles

Low salinity waterflooding (LSWF) is a process that aims to modify the chemical properties of the waterflood to yield additional oil recovery during secondary recovery. LSWF mechanism offers great improvements in secondary recovery, especially in carbonate reservoirs. The effectiveness of the LSWF mechanism is critical to the mineralogy of the reservoir; the wettability alterations caused by this mechanism are controlled by the silica, clay, and anhydrite content of the reservoir rock [103]. The mechanisms of LSWF in carbonate reservoirs are classified into rock-fluid and fluid-fluid interactions. Rock-fluid mechanisms are mineral dissolution and wettability alteration through electrostatic interactions by electrical double-layer expansion and variation of surface charge, multivalent ionic exchange, and electrostatic bond linkages. These mechanisms are further demonstrated in Figure 6. As for the fluid–fluid interactions, these include the formation of water in oil microemulsions, IFT reduction, and fluid coalescence [103].

LSWF was proposed to be integrated into EOR mechanisms and nanoparticle-assisted flooding. Studies on low-salinity polymer flooding showed improvements in mobility control, mobility ratio, displacement sweep efficiency, and volumetric sweep efficiency, in addition to rock wettability. On the other hand, low salinity surfactant flooding promotes additional IFT reduction and wettability alteration, leading to a drop in capillary forces. Moreover, implementing LSFW prior to CO₂ flooding have shown to enhance the sweep efficiency due to rock wettability alteration by LSFW [103]. NPs have displayed great potential in reducing and preventing fine migration in the reservoir during LSFW [104]. NPs are being implemented in LSFW with EOR chemicals, such as surfactants, to modify the fluid system’s rheological properties, reduce surfactant adsorption on the rock surface, and minimize fine migrations. The LSFW success is critical to the NPs selection, where NPs must prevent pore throat plugging and formation damage by fines. The addition of surfactants to LSFW reduces the fluid system’s IFT, alters rock wettability, and eventually enhances oil recovery [103,104]. The stability of NPs during LSFW depends on the salinity of the injectant. NPs are stable in deionized water at room temperature, where the main forces present in the solution are Van der Waals attractive forces and hydration repulsive forces. Solution stability also depends on the type of present ions. However, the stability of NPs in low-high saline water is more complex, where NPs can either coagulate or achieve stabilization [104]. NPs stability in saline water depends on the NPs concentration, NPs size, and solution pH. Salt ions lead to NPs coagulation by preventing particle repulsion; moreover, proton exchange is dominant in the low-salinity solution, eventually increasing the surface potential. Higher NPs concentration reduces the pH of the system, whereas higher solution acidity and smaller NPs sizes improve the stability of NPs. The addition of salt ions to the solution reduces the zeta potential towards zero leading to NPs coagulation. For an effective surfactant EOR mechanism, injectant salinity is an important factor to consider. The dominant mechanisms when integrating surfactants with LSFW include capillary pressure, osmosis, wettability alteration, diffusion, IFT reduction, and electrical double-layer effect [104]. NPs stability increases when implemented in the LSFW mechanism, which also increases oil recovery.

The synergetic effects of including a surfactant in the LSFW mechanism include further wettability alterations and IFT reduction, especially in carbonate reservoirs. As for the synergetic effects of NPs in LSFW, studies have shown additional rock wettability switch to water-wet in addition to further IFT reduction. Moreover, an increase in solution viscosity, higher displacement efficiency, less chalk dissolution, and less formation damage were observed. Further increase in water salinity reduces NPs stability and the ability of wettability alteration of the mechanism [104]. The synergetic effects of combining NPs, surfactants, and LSFW on IFT reduction and wettability alteration are controlled by the NPs’ charge, concentration, and size. The optimal performance of the LSFW mechanism with NPs and surfactants in the carbonate reservoirs is achieved by alternating injection [104].

Figure 6. Rock-fluid mechanisms under LSFW in carbonate rocks; (A) EDL and surface charge variation; (B) MIE mechanism and; (C) Electrostatic bond interactions at the oil-brine-rock interface [103,104,105].

Figure 6. Rock-fluid mechanisms under LSFW in carbonate rocks; (A) EDL and surface charge variation; (B) MIE mechanism and; (C) Electrostatic bond interactions at the oil-brine-rock interface [103,104,105].

3.1.4. Factors That Influence the Nanofluid’s Performance

Many factors affect the performance of nanofluids, such as:

• Type: Each NP type alters unique properties. For instance, nonmetal NPs alter the wettability by reducing the IFT at the oil-water interface, whereas other NPs, such as metal oxides, affect other properties of the reservoir, such as oil viscosity or permeability [88].
• Concentration: This factor affects the interfacial tension and the disjoining pressure of the nanofluid. A higher concentration of NPs in the nanofluid generally results in a higher repulsion between the NPs and, consequently, higher disjoining pressure. Furthermore, as the NPs concentration increases, the IFT drops further. However, a high NP concentration may lead to agglomerations, which is undesired. Therefore, there is an optimal NPs concentration that compromises between the NPs agglomerations and nanofluid performance [88,89].
• Size: It is more desired to have smaller NP sizes in surfactant nanofluids since small sizes improve the separation pressure between NPs. However, NPs of this size will aggregate faster [88,89].
• Wettability: Hydrophobic NPs are more effective than their hydrophilic counterparts when it comes to the detachment of oil droplets from the reservoir rock. Hydrophilic NPs can lead to oil expansion and rapid detachment, which also makes the hydrophilic NPs a good candidate for EOR applications [88,89].
• Charge: The charge of the NPs directly affects the disjoining pressure, where the ability to separate the oil droplets from the rock surface is higher for nanofluids with charged NPs [88].
• Formation water salinity: The stability of the NPs in a nanofluid is related to the salinity of the environment (i.e., formation water and the carrying fluid). Higher salinity causes faster agglomeration. Generally, surface modifications are made to the NPs to tolerate the salinity of the environment. The lower the salinity of the environment, the better the performance of the nanofluids and the displacement efficiency [89].
• Formation temperature: The stability of the NPs in a nanofluid decreases with the increase in formation temperature, which also leads to faster NPs agglomeration. Nonetheless, the temperature does not affect the NP’s retention [89].
• Carrying fluid pH: Fluids with a pH close to the isoelectric point (i.e., pH where the net electric charge of molecules in the solution is zero) will have unstable nanofluids. Nanofluids are more stable when the solution pH is closer to 7 (neutral) [89].
• Crude oil composition: The composition of reservoir fluids influences the structure of NPs suspension in the nanofluid. Moreover, the incremental recovery factor from nanofluids is affected by the percentage of heavy components in the reservoir fluids [106].
• Rock mineral type and properties: The performance of a nanofluid depends on the reservoir lithology and properties; for instance, the performance of a particular nanofluid injected in a sandstone reservoir will yield a different performance than in a carbonate one. Moreover, rock wettability influences the adsorption of nanoparticles where oil-wet reservoirs cause lower NPs adsorption than the water and neutral-wet ones [89,106].

3.2. Application of Nanomaterials in Thermal EOR

Thermal EOR is performed exclusively on heavy oil reservoirs containing asphaltenes and resins. Hydrocarbons in such reservoirs are characterized by long carbon chains, consequently having high molecular weight, high viscosity, and high boiling point [22,49]. These properties make the recovery of such oil difficult using conventional fluids such as gas or water. Nanoparticles such as nickel, cobalt, and iron are integrated into thermal EOR in the form of nanocatalysts. These nanocatalysts help decrease the heavy oil viscosity. Additionally, they are applied in the aquathermolysis oil treatment process. This process involves the improvement of the oil quality by reducing its viscosity under the effect of nanocatalysts, where the quality of the oil normally increases when the size of the nanocatalysts decreases [22,49]. The reaction that reduces the viscosity of the heavy oil is usually slow, and the volume of heavy oil exposed to nanocatalysts is usually large due to the high surface-to-volume ratio of nanocatalysts [22]. The reactions that occur during the aquathermolysis process include hydrodenitrogenation, hydrogenation, hydrocracking, and hydrodesulfurization. The dominant reaction that takes place during aquathermolysis is aliphatic sulfur bond hydrolysis [22].

Lighter hydrocarbon fractions aggregate to form heavier ones, where nanoparticles combine with the lighter hydrocarbon compounds avoiding their aggregation and growth. This is mainly because the interaction between NPs and the lighter hydrocarbons is stronger than that between the hydrocarbons themselves [107]. The adsorption of heavy HC compounds on NPs involves heat absorption or release and is a spontaneous process. Furthermore, this interaction alters the NPs’ surface acidity, creating a modified surface chemical structure. The medium of the NPs’ surface turns from acidic to basic then to neutral when interacting with asphaltenes, as a result of the strong interaction between the acidic NPs and asphaltenes yielding weak chemical bonds. The adsorption of different iron oxide NPs, such as hematite, magnetite, and iron oxide NPs was investigated. Results have shown that the hematite NPs have the highest adsorption capacity and can achieve equilibrium faster. Moreover, the asphaltene adsorption on hematite was an exothermic process, while the asphaltene adsorption on magnetite was endothermic. This implies that the structural properties of NPs control the asphaltene adsorption on NPs [107]. Another study performed by Marei et al. [108] suggests that the size of the NPs can influence the adsorption performance of NPs, where the adsorption capacity of larger NPs is higher than that of smaller ones [108]. Moreover, the surface properties of NPs and their texture vary widely with NPs size, hence influencing the adsorption behavior. When comparing alumina and silica NPs, silicon dioxide was found to have the highest asphaltene adsorption potential. It was also found that the presence of resins can affect the adsorption performance of asphaltenes on NPs [107].

The asphaltene’s large molecule dissociates into the smaller molecule when it approaches the adsorption potential zone of the nanoparticle, as illustrated in Figure 7. The main reason for asphaltene adsorption on the NP surface is the interaction between the functional group of the deployed NPs and the main functional group of the asphaltene, which is composed of aliphatic and aromatic compounds [107].

3.2.1. Application of NPs in In-Situ Combustion Thermal EOR

In-situ combustion involves the injection of oxygen-enriched air into the reservoir. Oxygen will trigger the combustion of heavy crude oil in the reservoir at the reservoir temperature. The presence of catalyst nanoparticles in this process accelerates the reactions involved in in-situ combustion. These reactions include oxidation, steam thrust, polymerization, distillation, vaporization, and catalytic disintegration [107].

Metal and metal oxide NPs are the most studied NPs in in-situ combustion. It was observed that nickel oxide and cobalt oxide (Co₃O₄) NPs reduced the temperature of oxidation for n-C7 asphaltenes from 450 °C to 325 °C compared to 365 °C for Fe₃O₄ NPs. When an asphaltene molecule gets adsorbed on the surface of the NP, the temperature of its combustion and oxidation will drop significantly, which will assist the in-situ combustion process [109]. The utilization of copper NPs in the in-situ combustion inhibits the asphaltene oxidation reaction at low temperatures. Moreover, hydrophobic copper oxide NPs raise oxygen consumption during in-situ combustion [107]. In general, NPs utilization in in-situ combustion lowers the activation energy of residual oil, improves the oxidation efficiency (which lowers the asphaltenes’ temperature of ignition), and enhances coke ignition [107].

For silica NPs, it was found that the oxidation performance of asphaltene depends on the acidity of the nanocatalysts’ surface. The application of acidic and basic NPs triggers the production of methane and carbon monoxide. Bimetallic NPs have a larger catalytic activity than monometallic ones. Hence, their utilization helps reduce the rate of asphaltene oxidation at lower temperatures [107]. The oxidation temperature and the activation energy of asphaltenes rise with lower resin content in crude oil. Furthermore, when resin accumulates on the NPs’ surface, the oxidation efficiency increases. The catalytic performance of NPs drops with higher asphaltene aggregation, increasing the activation energy of asphaltenes [107].

3.2.2. Application of NPs in Steam Injection Thermal EOR

Steam injection in a heavy oil reservoir leads to hydrogenation, methanation, gasification, aquathermolysis, and steam reforming of heavy hydrocarbon molecules. Aquathermolysis is initiated with the break of C-S bonds found in n-C7 asphaltenes since this bond is the weakest in the asphaltene molecule. As a result, hydrogen sulfide gas is generated [107]. Steam injection thermal oil recovery includes steam-assisted gravity drainage, continuous steam injection, and cyclic steam stimulation, all of which do not provide more than a 50% recovery factor. Therefore, the role of nanoparticles is of great importance since it helps reduce the temperature of asphaltene dissociation and enhances oil recovery [107].

Metal oxide NPs improve the properties of heavy crude oil when contacting asphaltenes during steam injection. Such NPs reduce the reaction temperature of asphaltene, even though their catalytic activity differs from one another. The catalytic activity of metal oxide NPs depends on the surface-to-volume ratio. The upgrading efficiency of NPs is controlled by the metal concentration and the degree of particle homogeneity in porous media [107].

The gasification and the hydrothermolysis decomposition reactions in steam injection EOR are boosted when using a composite of different NP types. Moreover, composite NPs prevent heavy hydrocarbon addition reactions, which are achieved by decreasing the decomposition intensity at high temperatures [107]. Furthermore, the utilization of composite NPs can significantly reduce the decomposition temperature of asphaltene to a greater extent than that done by a single NPs species. Another benefit of utilizing NPs in steam injection is the reduction of interfacial tension, which improves oil mobility [107]. The integration of composite NPs can further improve tar gasification and elimination. Moreover, it can reduce the viscosity of heavy oil, leading to Newtonian rheological behavior when contacting steam and NPs.

3.2.3. Application of NPs in Electromagnetic Heating Thermal EOR

In this EOR process, electric currents of different frequencies are applied to heat the heavy oil reservoir, hence reducing oil viscosity. The use of dielectric nanofluids in association with this method can alter the oil-water interface and increase oil production. Magnetic NPs have shown better performance when integrated with this EOR method. Moreover, the viscosity of the utilized dielectric nanofluids effectively enhances the sweep efficiency of oil and hence increases oil recovery [107]. Metal oxide NPs can absorb induced microwaves, consequently increasing the temperature of the reservoir. As a result, microwave heating of metal oxide NPs can reduce the viscosity of heavy crude oil. However, there is an optimal concentration of NPs in the nanofluid that reduces the viscosity of crude oil; beyond this concentration, the oil viscosity will rise again [107].

3.3. Application of Nanomaterials in Miscible/Immiscible EOR

Unfavorable phenomena might occur during this EOR mechanism, for instance, viscous fingering, gravity underride and override, and undesired mobility ratio. Water alternating gas flooding has been applied as an alternative to reduce the influence of these phenomena [22,110]. Furthermore, NPs have been tested and used in WAG EOR, which enhanced the macroscopic and microscopic sweep efficiencies of this mechanism [110].

Moradi et al. [110] investigated the performance of the WAG EOR mechanism when integrating SiO₂ NPs. They compared the performance of WAG EOR with and without NPs. The outcome of the study was a 20% improvement in the recovery factor when utilizing SiO₂ NPs compared to the conventional WAG process. This is due to the adsorption of the NPs on the surface of the reservoir rock, hence altering the wettability from oil-wet to water-wet. Moreover, the IFT at the oil-water interface has dropped as a result of NPs alignment at the interface [110]. Zhang et al. [111] studied the fluid miscibility of the mineral water-oil interface in the presence and absence of surfactant-decorated NPs. Contact angle and IFT experiments were conducted on different concentrations of SiO₂ NPs coated with CTAB surfactant. The results of the experiments revealed that optimal miscibility is achieved by high pressure, low temperature, small NPs sizes (<40 nm), high surfactant concentration, more wetting state, and 0.5–0.6wt.% NPs concentration. Moreover, additional surfactants would require higher NP concentration, and larger NP sizes would require less NP concentration to achieve optimal miscibility. This is further demonstrated in Figure 8, where surfactants at the oil-water align around the NP’s surface. Deploying such NPs in the WAG mechanism under the mentioned conditions enhanced the recovery factor by more than 20% compared to conventional WAG EOR [111].

The use of NPs can prevent viscous fingering and improve gas viscosity, density, mobility ratio, and recovery factor. Dezfuli et al. [112] demonstrated the benefits of implementing NPs in supercritical CO₂ flooding and the optimum NPs volume fraction to be deployed [112]. The results of this study showed that the optimal volume fraction of silica NPs to be used in light oil reservoirs is 3.5%. Beyond this volume fraction, the increase in oil recovery starts to drop until it reaches a maximum value at a 4 wt.% NPs volume fraction [112]. The corresponding maximum recovery factor achieved by supercritical CO₂ injection with 4 wt.% silica NPs is 30.47%. Similarly, for heavy oil reservoirs, the optimal silica NPs volume fraction range is between 0 and 5 wt.%, and the maximum achieved ultimate recovery factor corresponding to supercritical CO₂ flooding with 5 wt.% silica NPs is 27.82% [112]. It is obvious that this value is technically feasible but commercially expensive.

Al-Shargabi et al. [113] illustrated the utilization of NPs from coal ash to stabilize the CO₂ foam in the reservoir and hence control its mobility [113]. CO₂ flooding effectiveness is improved after the incorporation of NPs in the injection fluid. Several factors affect the performance of NPs-assisted CO₂ foam. These factors include NPs size, NPs wettability, reservoir temperature, formation water salinity, NPs hydrophilic concentration, flow features, hydrocarbons, NPs type, and NPs retention [113]. Small NP sizes are better for the stability of the CO₂ foam due to more adsorption of surfactants on the NP’s surface. The NP’s wettability is controlled by the ratio of adhesion and cohesion forces, which in turn will affect the stability of the CO₂ foam and the fluid mobility in the reservoir. Reservoir conditions such as salinity and temperature also affect the performance of NPs enhanced CO₂ foam flooding, where more salinity reduces the surfactant adsorption at the interface, foam half-life, and hence the foam stability.

Similarly, the stability of CO₂ foam drops with the rise in the medium temperature [113]. CO₂ foam is more stable in more hydrophilic NPs and NPs with modified surfaces. Moreover, it was found that NPs assisted CO₂ foam for all NP types is more stable than surfactant foams without NPs. The NP-CO₂ foam stability is further controlled by the shape, density, size, wettability, and surface charge of NPs [113].

The main reason for the destabilization of the CO₂ foam is the surfactant adsorption on the rock surface and the absence of a stable front. Kalyanaraman et al. [114] investigated the improvement of CO₂ foam stability by the incorporation of polyelectrolytes and polyelectrolyte complex NPs (polyethyleneimine and dextran sulfate). It was found that the durability of surfactant-NP-CO₂ foam is higher when crude oil is present, and its viscosity is better than that of the conventional CO₂ foam created by surfactant. Moreover, the addition of polyelectrolyte complex NPs recovered 58.33% of the residual oil in place compared to 47.6% for surfactant-generated CO₂ foam. Surfactant-NP-CO₂ foam system was injected after flooding with surfactant-CO₂ foam, and an additional 9.1% of residual oil was recovered [114]. A highly stable lamella was developed at the interface by the integration of polyelectrolyte complex NPs during supercritical CO₂ foam flooding. This stable lamella ensures better foam stability and better compatibility of supercritical CO₂ foam with water. The results of Nazari et al. [115] proved that the optimal surfactant-polyelectrolyte complex NPs ratio yields a highly stable supercritical CO₂ foam in a high salinity environment and improves the oil recovery factor. Moreover, the study showed that the lowest saturation of residual oil and the highest increase in oil recovery are obtained by the optimization of electrolyte concentrations in the surfactant-polyelectrolyte complex NPs-supercritical CO₂ foam flooding [115].

Lai et al. [116] studied the performance of CO₂/N₂ responsive NPs during the CO₂ EOR mechanism. These NPs are created by silica NPs modification with 3-aminopropyltrimethoxysilane through the Eschweiler–Clark reaction. Results of the study showed that responsive NPs are a viable candidate for enhancing CO₂ flooding performance, where more than 26% of the OOIP was recovered. Furthermore, the wettability of the rock changed from oil-wet to water-wet, which was beneficial for the recovery of residual oil [116].

Another problem encountered during CO₂ miscible flooding is the asphaltene deposition on the reservoir rock surface. This would alter the reservoir rock properties and affect oil recovery. NPs such as ferric oxide and aluminum oxide were proposed by Azizkhani & Gandomkar, 2020, as direct asphaltene inhibitors during miscible CO₂ flooding. Results of the study showed that such direct asphaltene inhibitors could reduce the number of precipitated asphaltenes during the miscible NPs-assisted CO₂ flooding mechanism under reservoir conditions. Moreover, CO₂ miscible flooding with ferric oxide showed a better performance than with aluminum oxide. This is due to the higher solubility involved in Fe₃O₄-CO₂ flooding. Higher concentrations of NPs in the injected fluid result in lower precipitation of asphaltene during the flooding [117]. A similar study was performed by Hassanpour et al. [118] by comparing the performance of TiO₂ and Fe₂O₃. NPs in reducing asphaltene precipitation. The conclusion of this study also revealed that ferric oxide NPs showed a better performance than titanium dioxide in reducing asphaltene precipitation at the CO₂-water interface. Moreover, the optimal NPs concentration for this purpose was found to be 1%. Utilizing titanium oxide and ferric oxide NPs reduced the asphaltene precipitation by 17% and 18%, respectively [118]. Consequently, NPs are great candidates for reducing the asphaltene precipitation during miscible flooding, which in turn favors oil recovery.

NPs can also assist miscible EOR mechanisms in reducing the viscosity of residual oil and increasing the recovery factor. A new viscosity-reducing mechanism for heavy oil reservoirs was proposed by Shah [119]. This mechanism involves the integration of thermally conductive metallic NPs in supercritical CO₂ (viscosity-reducing injectant) flooding EOR coupled with soluble surfactants for further viscosity reduction. The thermal properties of the NPs enabled further increase in the injectant temperature and eventually lower oil viscosity. Oil viscosity reduction is further assisted by the chemical properties of the associated surfactant and the miscible properties of the injected supercritical CO₂ [119].

3.4. Cost Analysis of NPs for EOR Applications

The process of manufacturing nanomaterials is complex and expensive, especially if it is non-standardized [21,120]. Usually, the quantity of NPs used in laboratories is small and its cost implications are less consequential [121]. However, the number of nanomaterials to be used in a field-scale application depends on several factors: for instance, the required (optimal) NPs concentration in the injection fluid, the field size, rock and reservoir fluid properties, and the properties of the used nanomaterial (i.e., size, shape, and charge). Presently, economic analyses comparing oil prices with NPs costs are still scarce, which prevents the implementation of NPs in field applications. Field-scale application of NPs requires large NPs quantities, and eventually, the realistic economic implications of NPs at different oil regimes must be further investigated [121]. Typical prices of some common NPs in US$/gram are summarized in

Table 4. Indicative prices of most common nanoparticles in $/g [122].

Nanoparticle Type	Price in $/g
Aluminum Oxide (Al2O3)	0.7
Aluminum (Al)	3.8
Copper Oxide (CuO)	0.75
Copper (Cu)	5
Silica Dioxide (SiO2)	0.7
Silver (Ag)	4
Gold (Au)	55
Titanium Dioxide (TiO2)	0.8
Carbon Nanotubes	9.3–12.5

.

4. Discussion

4.1. Recovery Factor Evaluation of Different Methods

The recovery factor results of some previous studies listed in Table 2 and Table 3 that assess the potential of integrating NPs in chemical EOR are plotted in clustered column graphs shown in Figure 9 and Figure 10. According to Figure 9, the highest increase in oil recovery (16%) after incorporating NPs in surfactant flooding was obtained in the study by Taborda et al. [73], which tested silica and acidic silica NPs with tween 80. This indicates that this NP-surfactant combination can yield optimal performance. The second highest oil recovery increment after adding NPs to surfactant solution (15.18%) was achieved in the study by Tavakkoli et al. [87], where Al₂O₃ NPs were used in combination with sodium dodecyl sulfate surfactant. Silica NPs have also shown desirable performance when incorporated with alcohol polyethylene glycol ether carboxylic sodium in the study performed by Zhou et al. [83], where an oil recovery increment of 11.45% was achieved. Consequently, silica nanoparticles are found to be more effective than other NPs when it comes to enhancing oil recovery. Moreover, any NP’s performance depends on the reservoir rock conditions and properties, reservoir fluid type, surfactant type, and concentration used in the flooding process and the NPs concentration used.

As for the application of NPs in polymer flooding, NPs have brought more improvements in oil recovery when applied with polymer flooding than when applied in surfactant flooding. This conclusion can be drawn when comparing Figure 9 and Figure 10, where previous studies on the application of NPs in polymer flooding (see Figure 10) yielded higher oil recovery than that reported by previous NPs studies in surfactant flooding (see Figure 9). According to previous findings on nanopolymer flooding by Gbadamosi et al. [96], Keykhosravi et al. [29], and Ali et al. [25], the integration of Al₂O₃, SiO₂, and TiO₂ NPs with xanthan gum polymer yielded the highest increment in oil recovery compared to other studies using different polymer types. This indicates that the xanthan gum polymer is the best match with NPs in nanopolymer flooding. The study by Behera et al. [95] also yielded the highest incremental oil recovery when silica NPs with polyvinylpyrrolidone/povidone polymer were used. However, SiO₂ NPs had weaker performance than Al₂O₃ when used in combination with hydrolyzed polyacrylamide polymer, which indicates that each NP has an exclusive polymer that yields an optimal performance when applied together.

4.2. Challenges Involved in the Integration of NPs in EOR

Several technical, economic, and environmental challenges and limitations are encountered when applying NPs in EOR mechanisms. Some NPs, especially the magnetic ones, are expensive as a result of non-standardized and complex production in addition to service processes. Moreover, the field application of NPs requires an extensive volume of NPs to be deployed, which drastically raises the costs deeming such projects economically unfeasible. Furthermore, recycling utilized NPs for repeated applications is also quite complex and expensive. These limitations have been confirmed by Cheraghian et al. [21] and Foroozesh & Kumar [120]. Other environmental concerns are involved when utilizing NPs; for instance, the toxicity of some NPs groups as a result of high surface energy arising from unsaturated atoms.

Although selecting suitable NPs according to well and oil specifications is a complex process, the reservoir’s high temperature, pressure, and salinity conditions might deteriorate and damage the NP’s structure, eventually reducing their effectiveness. The loss of control over the large-scale dispersion of NPs in the reservoir and their corresponding intrinsic properties is a common technical challenge encountered in such applications. Moreover, attractive forces between NPs might be strengthened under reservoir conditions leading to NPs aggregation. This will eventually cause the blockage of some pores and pore throats, which will affect the long-term performance of NPs in EOR techniques. In some cases, NPs can deposit and attach to the reservoir rock surface, creating a monolayer or a multilayer. The created layer can negatively affect the rock properties (i.e., porosity and permeability). In surfactant nanoflooding, nanofluids manufactured by conventional methods are unstable in saline and high-temperature reservoir conditions. Other recently conducted studies confirmed these limitations, including the studies by Cheraghian et al. [21], Lashari & Ganat [24], Liu et al. [88], Foroozesh & Kumar [120], and Sagala et al. [123]. Consequently, to avoid such limitations, the influence of NPs on fluid-fluid and fluid-solid interactions must be meticulously assessed. Moreover, reservoir-integrated evaluation is a major step that must be considered before applying NPs in an EOR technique. The established screening method must be relevant to the NP’s integration in EOR.

For better implementation of NPs in EOR, further research, reservoir simulations, and investigations must be conducted to better understand and forecast the performance of NPs in the reservoir. NPs applications in the upstream oil and gas industry and the performance of NPs under reservoir conditions must be characterized rather than focusing only on research developments and laboratory experiments, as this proves the potential of NPs for field-scale implementation. Nevertheless, chemical interactions between NPs in porous media must be experimentally and numerically studied. Moreover, the adsorption capacity of each NP type on different solid surfaces must be assessed. This will give a clear view of how NPs will impact the IFT and contact angle alteration. In addition, the effect of NPs wettability on the capacity of adsorption is still unclear and needs further experiments. Further studies are required to visualize NPs transport in porous media during the suspension using supercritical CO₂ fluid. Furthermore, assessing the EOR capacity of metallic NPs is required, as such studies are still limited compared to those conducted on the EOR capacity of SiO₂ NPs. Finally, in polymer nanofluid flooding, polymers adsorb on the surface of NPs, creating a bound layer, where the thickness, stability, and influence of the bound layer on the size and shape of NPs should be theoretically and experimentally studied.

5. Conclusions and Recommendations

Frequent research has been conducted on the use of nanotechnology in the petroleum sector, particularly for enhanced oil recovery. Thus far, the findings are encouraging and suggest great improvements to the recovery factors when nanoparticles are used in different EOR techniques. Nanoparticles in EOR have many benefits; they can improve oil recovery by manipulating different properties such as the interfacial tension, wettability of the formation, mobility ratio, and others. Furthermore, the impact of NP on these properties is governed by the NP’s parameters, such as the NP concentration, NP size, and temperature.

According to several studies conducted on the application of NPs in EOR, the behavior of any NP used depends on the reservoir rock properties and conditions, reservoir fluids type, EOR mechanism, chemical type (surfactant/polymer/alkaline), chemicals concentration used in the flooding process, and NPs properties and concentration. The selection of the best NP is dependent upon these factors.

Although a lot of research is being conducted on the use of NP in EOR, many aspects in this field are still nebulous and require extensive research and investigations. For instance, the interactions among NPs in porous media, their adsorption capacity, and their influence on solid-fluid and fluid-fluid interactions. In addition, studies on the synergetic effects of utilizing NPs with a combination of several chemicals (surfactants, polymers, and alkaline) are still absent from the literature. Moreover, the field implementation of this approach is still in the appraisal stage, where NPs’ performance in the field scale remains unclear. Furthermore, due to the quick progress in the literature studies that focus on this area, review articles are highly needed to compare the progress and impact of different NP applications.