student

The answer will be

• Paraphrase
• Provide some figures/pictures and diagrams with reference
• 1000 words
• Harvard Referencing

Vol.:(0123456789) 1 3 International Nano Letters (2019) 9:171–202 https://doi.org/10.1007/s40089-019-0272-8 REVIEW An overview of chemical enhanced oil recovery: recent advances and prospects Afeez O. Gbadamosi1  · Radzuan Junin1  · Muhammad A. Manan1  · Augustine Agi1  · Adeyinka S. Yusuf2 Received: 6 January 2019 / Accepted: 9 April 2019 / Published online: 29 April 2019 © The Author(s) 2019 Abstract Despite the progress made on renewable energy, oil and gas remains the world’s primary energy source. Meanwhile, large amounts of oil deposits remain unrecovered after application of traditional oil recovery methods. Chemical enhanced oil recovery (EOR) has been adjudged as an efcient oil recovery technique to recover bypassed oil and residual oil trapped in the reservoir. This EOR method relies on the injection of chemicals to boost oil recovery. In this overview, an up-to-date synopsis of chemical EOR with detailed explanation of the chemicals used, and the mechanism governing their oil recovery application have been discussed. Challenges encountered in the application of the various conventional chemical EOR methods were highlighted, and solutions to overcome the challenges were profered. Besides, the recent trend of incorporating nanotechnology and their synergistic efects on conventional chemicals stability and efciency for EOR were also explored and analysed. Finally, laboratory results and feld projects were outlined. The review of experimental studies shows that porescale mechanisms of conventional chemical EOR is enhanced by incorporating nanotechnology, hence, resulted in higher efciency. Moreover, the use of ionic liquid chemicals and novel alkaline–cosolvent–polymer technology shows good potentials. This overview presents an extensive information about chemical EOR applications for sustainable energy production. Keywords Polymer · Surfactant · Foam · Nanofuid · Enhanced oil recovery · Nanotechnology Abbreviations AA Acrylic acid AlCl3 Aluminium chloride Al2O3 Alumina or aluminium oxide AlOOH Hydrophobic alumina AM Acrylamide AMC12S 2 Acrylamido-dodecyl sulfonate AMPS 2-Acrylamido-2-methyl-1-propanesulfonic acid AOS Alpha olefn sulphonate API American Petroleum Institute APTES (3-Aminopropyl)triethoxysilane ATBS Sodium acrylamido terbutyl sulfonate CaCl2 Calcium chloride cP Centipoise CTAB Cetyltrimethylammonium bromide EDA Ethylene diamine EOR Enhanced oil recovery FA Fly ash Fe2O3 Iron oxide IONP Iron oxide nanoparticle FTIR Fourier transform infrared microscopy GLYMO (3-Glycidyloxypropyl)trimethoxysilane HAPAM Hydrophobic associative polyacrylamide HBAPAM Hyperbranched associative polyacrylamide HEC Hydroxy ethyl cellulose HLPN Hydrophobic and lipophilic silicon nanoparticle HPAM Hydrolyzed polyacrylamide IFT Interfacial tension IIT Illinois Institute of Technology nanoparticle LHPN Lipophobic and hydrophilic polysilicon nanoparticle MgCl2 Magnesium chloride MgCl2 Magnesium oxide MeDiC8AM 2-Methyl-N,N-dioctyl-acrylamide * Radzuan Junin r-radzuan@utm.my Afeez O. Gbadamosi gbadamosiafeezo@gmail.com 1 Department of Petroleum Engineering, Faculty of Chemical and Energy Engineering, Universiti Teknologi Malaysia, 81310 Skudai, Johor Bahru, Malaysia 2 Department of Chemical and Petroleum Engineering, Afe Babalola University, PMB 5454, Ado-Ekiti, Nigeria 172 International Nano Letters (2019) 9:171–202 1 3 MWCNT Multi-wall carbon nanotube NaCaS Sodium caseinate NaCl Sodium chloride NaHCO3 Sodium hydrogen carbonate NP Nanoparticle NWPN Neutrally wet polysilicon nanoparticle OOIP Original oil in place PAA Polyacrylic acid PA-S Poly(AMPS) styrene PAMAM Polyamido amide PAM Polyacrylamide PEG Polyelectrolyte glycol PECNP Polyelectrolyte nanoparticle PGN Polymer grafted nanoparticle PNS Polymeric nanofuid suspension PNRS Petroza commercial surfactant POEOMA Poly(oligo(ethylene oxide) mono methyl ether methacrylate) PSNP Polysilicon nanoparticle PG Propyl gallate PVA Polyvinyl alcohol PVP Polyvinyl pyrrolidone SiO2 Silica or silicon oxide SC Sodium cumenesulfonate SDS Sodium dodecyl sulphate TiO2 Titanium oxide TTFA Thermally treated fy ash TX-100 Triton X 100 surfactant WA Wettability alteration WF Waterfooding Introduction Oil and gas resources remain the world’s major contributor to energy supply even with the recent energy generation from renewable sources [1, 2]. As global energy demand increases in juxtaposition to dwindling energy resources, maximizing oil recovery from previously under-exploited reserves becomes crucial to meet the ever increasing energy demand [2]. The processes of oil recovery are majorly in three stages namely: primary, secondary and tertiary (EOR) stage. After the application of primary and secondary oil recovery techniques, two-third of the original oil in place (OOIP) remains in the reservoir [3, 4]. This is either because the oil is trapped by capillary forces (residual oil) or bypassed in some other way. The bypassed oil arises due to reservoir heterogeneities or because of unfavourable mobility ratio between the aqueous and oleic phase. On the other hand, the residual oil is made up of discrete ganglia that are produced when a fnger-like protrusion of the oleic mass forms a narrow neck by the combined efects of local pressure gradient and interfacial tension (IFT) [5]. To enhance the overall oil displacement efficiency, numerous EOR methods have been devised and utilized [4, 6–9]. During oil recovery, the overall oil displacement efciency is a combination of macroscopic (volumetric sweep) and microscopic (pore scale) displacement efficiency. Macroscopic displacement efciency is a measure of the efectiveness of the injected fuids in contacting the oil zone volumetrically with respect to the total reservoir volume while microscopic displacement efciency is the efciency related to the ability of the displacing fuid(s) to mobilize oil trapped at the pore scale when it contacts the oil. Summarily, any mechanism that can increase oil recovery efciency at either the micro or macro-scale or both is benefcial for EOR [10]. The devised and utilized EOR methods are majorly categorized into thermal and non-thermal EOR methods [11]. Unfortunately, thermal EOR methods are unsuitable for reservoirs with great depth and thin pay zone. Thus, nonthermal EOR has received prodigious attention for recovering oil bypassed or trapped in the reservoir [12]. Amongst all the EOR techniques, chemical EOR method, a non-thermal EOR method, has been adjudged as the most promising because of its higher efciency, technical and economic feasibilities and reasonable capital cost [13]. The application of this EOR method became popular in the 1980s due to higher oil prices and technological advancement that enables understanding their mechanism. Chemical EOR methods increase oil recovery by increasing the efectiveness of water injected into the reservoir to displace the oil. Dependent on the type of chemical EOR process, chemicals injected with the water slug alter the fuid–fuid and/or fuid–rock interaction in the reservoir. This includes lowering of the IFT between the imbibing fuid and oil or an increment in the viscosity of the injectant for improving mobility and conformance control. Besides, the injected chemicals results in wettability alteration of the rock to increase oil permeability [14]. The well-known traditional chemical EOR methods are polymer fooding, surfactant and alkaline fooding [15]. However, the conventional chemical EOR methods have their limitations. Polymers, whose main recovery mechanism is to increase viscosity of injectants and consequently mobility, sufers viscosity loss in the presence of reservoir brines and elevated temperature conditions. Surfactant and alkali lose their efciency during their fow in porous media due to adsorption phenomena. Subsequently, diferent modes of chemical food injections were devised, studied and applied for EOR processes. These include the binary mix of alkali–surfactant (AS), surfactant/polymer (SP), alkaline/polymer (AP), and alkaline/surfactant/polymer (ASP) slug (see Fig. 1). The synergy of the combined conventional chemicals recorded an improved efciency during their applications in oil wells. Recently, the use of foam enhanced by surfactants and polymers, for improved stability International Nano Letters (2019) 9:171–202 173 1 3 and mobility control have been studied and found to improve oil recovery [16–19]. More recently, the evolution of nanotechnology and their applications to improve the efciency of various processes in the felds of metallurgy, electronics, medicine, aeronautics, catalysis, and fuel cells have prompted its use and application in the oil and gas industry [20–23]. The feld of nanoscience and nanotechnology describes the creation and exploitation of materials with structural features having at least one of its dimensions in the nanometre range (1–100 nm). The “engineered nano-material” is called nanoparticle. The resultant improvement in the functional properties of a process generated due to addition of nanoparticles is attributable to their scalable and quantum efects. The application of this functional materials requires a base fuid such as gas, oil, water, or any other suitable liquid substance, hence, they are termed nanofuid. The application of nanotechnology has profered solutions to various oil and gas problems ranging from drilling operations, petroleum exploration, inhibiting asphaltene depositions and gas hydrate formations, hydraulic fracturing jobs and EOR [24–27]. For EOR processes, nanofuid fooding has been evaluated and explored as a chemical EOR process with feld application reported in Colombia [28]. The mechanism of the improved oil recovery were identifed as structural disjoining pressure, wettability alteration, IFT reduction and improved viscosity of injectant [29]. More recently, the addition of nanoparticles to conventional EOR chemicals have been studied and reported to yield novel materials with excellent and fascinating properties. For example, polymeric nanofuids, a synergistic combination of nanoparticle and polymers were found to possess improved rheological properties and stability for application in the presence of high-temperature and high-salinity conditions [30]. Furthermore, the synergistic application of nanoparticles with surfactant lowers their adsorption via competitive adsorption mechanism, while their applications with foams generate stable foams with longer half-life [31]. This overview is a fundamental study that presents the current scenario of available research on chemical EOR. First, a survey of conventional chemical EOR method was carried out. The conventional EOR chemical types were identifed and the mechanism of their EOR applications are discussed, and their limitations are highlighted. Thereafter, the binary application of conventional chemical EOR methods were also defned and analysed. Afterwards, the recent trend of incorporating nanotechnology for chemical EOR was also explored. The various nanofuid types, mechanism of their application and laboratory studies were outlined. Finally, the challenges associated with chemical EOR methods were enumerated and recommendations for future works were profered. Conventional chemical EOR methods The notable conventional EOR chemicals are polymers, alkali, and surfactants. The injection of polymers with waterfoods increases the viscosity of the aqueous phase, and consequently mobility as they move from the injection well towards the producer. Additionally, the polymer solution increases oil recovery by reducing permeability to water in the reservoir [32]. Surfactant solutions reduce the IFT between water and crude oil by reacting with certain crude oil constituents, thereby, solubilizing interfacial flms, and causing emulsifcation [33]. The IFT reduction causes lowering of the capillary forces of trapped and residual oil. Besides, surfactant adsorb on reservoir rocks to change rock wettability, hence, an increased oil recovery. Alkali fooding operates with a mechanism in similitude to surfactant solutions though with a diferent injectant [34]. Foam fooding ensures diversion of injected fuid from thief zones to low permeable regions of the reservoir [35]. Meanwhile, AP, AS, and ASP fooding are borne out of the basis to incorporate the diferent strengths and efciency of alkali, surfactant and/or polymer solutions to improve the pore scale and sweep efciency of the OOIP [36]. Polymer fooding When waterfooding of an oil reservoir proves inadequate due to viscous fngering phenomena culminating in early water breakthrough, polymer fooding may be introduced/ incorporated. The process of polymer fooding involves the injection of high molecular weight water-soluble polymers along with the water slug to increase the viscosity of the Fig. 1 Classifcation of EOR technologies 174 International Nano Letters (2019) 9:171–202 1 3 injectant [37, 38]. The incremental viscosity of the injectant improves the mobility and conformance control of the injected slug and eradicates viscous fngering phenomena. Consequently, early water breakthrough normally encountered in waterfooding process is suppressed and an incremental oil recovery factor is achieved. Polymer fooding has been successfully implemented in many oilfelds either on a pilot scale or commercial scale for several decades. This includes the Daqing oilfeld in China, East Bodo Reservoir and Pelican Lake feld in Canada, Marmul feld in Oman, and Tambaredjo feld, Suriname, to mention just a few [39]. In addition, polymer fooding has maintained its increasing importance to the current energy market. The most notable contribution is the reported incremental oil production of up to 300,000 bbl/day from Daqing oil feld in China [33]. Mechanism of polymer fooding Polymer fooding improves oil recovery through a combined mechanism of mobility control, disproportionate permeability reduction and viscoelastic nature of the polymers. Mobility control Mobility ratio is defned as the ratio of the mobility of the injectant (water) to the mobility of the displaced fuid (oil). Equation (1) depicts the mobility ratio of a waterfood as: where M is the mobility ratio, µo is oil viscosity (cP), 휇w is water viscosity (cP), Ko is permeability to oil (mD), and Kw is permeability to water (mD). Mobility ratio dictates the stability of the oil displacement process. If M > 1, this is an indication that the water is more mobile than the oil. This depicts unfavourable condition as water fngers through the oil zone leading to an early breakthrough and a lower oil displacement efciency (see Fig. 2a). To ensure a high macroscopic sweep efciency, it M = (1) Kw휇o / Ko휇w , is always required that M ≤ 1. Figure 2b illustrates the way polymer foods infuences oil recovery through the reduction of mobility ratio. The presence of polymer in the displacing phase causes an increase in the viscosity of the injectant. Consequently, this results in a stable front of the displacing phase totally denuded of viscous fngers and/channels within the reservoir, thereby, resulting in a higher oil recovery [5, 16, 40]. Disproportionate permeability reduction (DPR) In addition to the concept of mobility ratio, polymer foods improve sweep efciency through disproportionate permeability reduction. Due to the heterogeneous nature of some reservoirs, they possess an uneven distribution of permeability (having a diferent permeability in diferent layers). This results in channelling of excessive water production through high permeability layers, leading to large amount of movable oil and gas remaining trapped in low permeability zones thereby causing poor recovery in primary and secondary stages of production [41]. During polymer fooding, the polymer solutions injected into the heterogeneous reservoir builds up fow resistance to water in the portions of the reservoir it penetrates, thus, lowering the water relative permeability (Krw) while ensuring little or no reduction in the oil relative permeability (Kro). This mechanism is termed disproportionate permeability reduction (DPR). The increased resistance of the polymer to water diverts subsequently injected water into unswept or poorly swept (low permeable) regions of the reservoir through segregation of fow pathways and layer formation on pore wall by the adsorbed polymer, thereby, resulting in a higher oil recovery [42]. Viscoelasticity of  polymeric molecules Polymer viscoelasticity is the third mechanism posited to be responsible for improved macroscopic efciency during polymer fooding. Unlike Newtonian fuids, polymers undergo a series of expansion and contraction (stretching and recoiling) during their fow in porous media [43]. This helps the polymeric Fig. 2 Typical mobility ratio of a waterfooding process (M>1.0), b polymer fooding process (M≤1.0) [5] International Nano Letters (2019) 9:171–202 175 1 3 molecules to generate additional “elastic viscosity” which improves macroscopic and microscopic displacement efciency. Urbissinova et  al. [44] and Veerabhadrappa [45] investigated the efect of viscoelastic properties of polymer on macroscopic sweep efciency. The elastic diference of the polymer solution with the same shear viscosity was generated using polymer of similar average molecular weight but diferent molecular weight distribution (MWD). The result of their individual experiment indicated that high elastic polymer solution exhibited a considerably higher resistance to fow through porous media and stability of the propagating front thereby minimizing fngers. This cumulated in a higher sweep efciency, lower residual oil saturation and an improved oil recovery. Types of EOR polymers Generally, two major classifications exist for polymers used during polymer fooding recovery operations, namely, synthetic polymers and biopolymers. Typical examples of synthetic polymers are polyacrylamides and it derivatives such as partially hydrolysed polyacrylamide (HPAM), hydrophobically associating polyacrylamide (HAPAM), and copolymers of acrylamide. On the other hand, biopolymers include xanthan gum, scleroglucan, hydroxyethylcellulose, carboxymethylcellulose, welan gum, guar gum, schizophyllan, mushroom polysaccharide, cellulose, and lignin (see Table 1). It is noteworthy that feld application of HPAM and xanthan gum are the most widely reported and will be discussed further. For additional information of other polymer types, Taylor et al. [46] provided a comprehensive review of water-soluble of HAPAM, and Kamal et al. [47] described the state-of-the-art review of copolymers of acrylamide polymers for EOR. Additionally, Pu et al. [48] published a detailed review of polysaccharide biopolymer for EOR. Finally, Wever et al. [49] chronicled a general review of polymers for EOR. Partially hydrolysed polyacrylamide (HPAM) Hydrolysed polyacrylamide (HPAM) is water-soluble, synthetic straightchain polymers used in EOR applications. It is a copolymer of polyacrylamide and polyacrylic acid obtained by the partial hydrolysis of PAM or by copolymerization of sodium acrylate with acrylamide [10]. They are widely regarded as the most used polymer for EOR [50]. HPAM is mostly preferred during feld applications because it is resistant to bacterial attack, it has good water solubility, mobility control and it is a low-cost polymer [32, 48]. When used during polymer fooding, the polymer molecule undergo partial hydrolysis which converts some of the amide groups (–CONH2) to carboxyl groups (–COO–), as illustrated in Fig. 3. Typical degree of hydrolysis (DOH) for this polymer is 15–35% of the acrylamide (AM) monomers. Hence, they are negatively charged. The DOH accounts for many of the physical and rheological properties of the polymer solution such as adsorption, viscosity and water solubility. Nonetheless, HPAM is very sensitive to external factors such as pH, temperature, salinity, shear forces and hardness. In reserTable 1 Merits and demerits of biopolymers Polymer type Merits Demerits Xanthan gum High resistance to salinity, temperature and shear Possess long-term stability High susceptibility to biodegradation and oxidation High risk of plugging of rock pores Carboxymethylcellulose The biopolymer is environmental friendly It has good solubility in water It sufers from oxidative decomposition and thermal degradation Schizophyllan Good resistance to temperature and salinity High thickening efciency Low adsorption of its molecule on rock surface It is a non-toxic material Highly susceptible to biodegradation Hydroxyethylcellulose High solubility in water Good tolerance to temperature and mechanical shearing Excellent viscosifying efect Biodegradation problem Welan gum Possess long-term stability Excellent viscoelastic efect Performance dependent on inorganic cations present in reservoir Scleroglucan Good resistance to shear and temperature efect Excellent viscosifying efect High risk of biodegradation and oxidation Poor flterability of the material in rock pores Guar gum It is an environmental friendly material Excellent hydration properties and good compatibility to salts over a wide range of pH High risk of plugging in porous media It sufers from poor thermal stability and weak elasticity Lignin It is an environmentally friendly material Readily available at a low cost Insoluble in water Biodegradation and oxidation efects Cellulose Good resistance to temperature and mechanical shearing Water-insolubility and heterogeneous swelling 176 International Nano Letters (2019) 9:171–202 1 3 voirs characterized by extreme conditions of this factors, HPAM molecule loses its viscosity enhancement property and consequently its efciency [47, 51]. Field applications of HPAM as polymer for EOR have been reported in literature [47, 52]. Xanthan gum Xanthan gum polymer is a polysaccharide obtained via fermentation of glucose and its isomer fructose by diferent bacteria. Xanthomonas campestris bacterium is widely regarded as the most efcient producer of xanthan gum [53]. Figure 4 depicts the chemical structure of xanthan gum displaying the presence of carbohydrates: glucose, mannose and glucuronic units. The biopolymer is characterized with rigid polysaccharide chains which make it resistant to degradation in the presence of salinity, temperature and shear forces [54]. The polymer is also regarded as a polyelectrolyte due to the presence of charged moieties (i.e., acetate and pyruvate groups) on the side chain of the biopolymer. Due to its high molecular weight which ranges from 2 to 50 ×106 g/mol, xanthan gum demonstrates high thickening capability required for mobility control in reservoirs [10, 49]. Compared to synthetic acrylamide polymer such as HPAM, xanthan gum has a more rigid structure. Modelling the rheological behaviour of xanthan gum with available theoretical model (such as Herschel–Bulkley and Ostwald’s models) shows the polymer exhibits shear thinning behaviour which corresponds with an appropriate injectivity for feld operations [48]. Relative to HPAM, xanthan gum is less sensitive to mechanical shear, elevated salinity and/or divalent ion concentration, and displays good resistance to high temperatures. For a given temperature, the viscosity of xanthan solution display resistance to increasing temperature conditions when the ionic strength is high. This is because xanthan gum undergoes a cooperative conformational transition from a disordered conformation to a more rigid and ordered structure upon the addition of salt, hence, their improved stability [55]. Conversely, the viscosity of xanthan solution decreases strongly with increasing temperature at low ionic strength [48, 49, 55]. The major drawback of the application of this polymer for numerous feld operations is the potential plugging risk caused by the cell debris and bacterial sensitivity. Researchers have shown that salt-tolerant aerobic and anaerobic microorganisms degrade xanthan gum resulting in high loss of its solution viscosity [48]. Albeit, biocides such as formaldehyde can be used to suppress the growth of xanthan gum degrading microorganisms, however, their use render the environmental impact of the polymer obsolete and make the overall polymer fooding process expensive. Field application of xanthan gum fooding was reported in ShengLi Gudong oilfeld in China where successful pilot test was conducted and feld trials were implemented with a favourable response to water cut and oil production rate. Challenges of polymer fooding The main objective of the addition of polymers to displacement fuids is to viscosify the injected brine. However, signifcant interactions such as electrostatic interactions and London dispersion forces occur between the transported polymer molecules and rock surface in the reservoir [5]. These causes retention of polymer molecules and results to the formation of a bank of injection fuid wholly or partially Fig. 3 Structure of partially hydrolysed polyacrylamide (HPAM) Fig. 4 Structure of xanthan gum biopolymer [54] International Nano Letters (2019) 9:171–202 177 1 3 denuded of polymer depending on the degree of retention of the transported polymer molecules. Hence, the fnal viscosity of the injectant in the reservoir is lower than the target viscosity required, thus, resulting in a reduction of the efectiveness and efciency of the polymer food [56]. Factors that infuence the retention of polymers in porous medium include polymer type and concentration, molecular weight, rock permeability, fow rate, salinity, temperature and the presence of clay minerals. Overall, polymer retention is an important factor that governs the economic viability of a polymer fooding process as they have an impact on the rock permeability, the viscosity of the injected polymer solution, and consequently the oil recovery process. The three main polymer retention mechanisms in porous media are hydrodynamic retention, mechanical entrapment and polymer adsorption. Figure 5 illustrates the polymer retention mechanisms. Further details of these mechanisms have been reviewed in our previous article [57]. Surfactant fooding Surfactant fooding is a proven EOR technique used for mobilizing residual oil trapped in the reservoir [58]. The aim of surfactant injection into reservoir for improving oil recovery factor is to alter the fuid/fuid interaction by reducing IFT between the oil and brine, and fuid/rock properties via wettability alteration of the porous medium. A surfactant, otherwise known as surface-active agent molecule is amphiphilic in nature. This means surfactants are characterized with two functional groups within their organic shell. These are the hydrophilic group which is usually water-soluble and hydrophobic or non-polar group which is often oil-soluble. The lipophilic hydrophobic group is usually a long-chain hydrocarbon, fuorocarbon, a siloxane chain, or a short-polymer chain, which may or may not be branched. On the other hand, the lipophobic hydrophilic group is formed by moieties with their classifcation depending on the inherent organic compound. The moieties include quaternary ammonium salts, carboxylates, alcohols, sulfonates, polyoxyethylenated chains and sulphates. Various laboratory and feld applications of surfactants have been reported in literature [59]. Mechanism of surfactant fooding Surfactant flooding improves pore-scale displacement efciency through the mechanism of interfacial tension reduction, or wettability alteration, or a combination of both mechanisms. Interfacial tension reduction During secondary recovery via waterfooding, it is practically impossible for water to displace all the oil in the pore scale due to trapping of oil by capillary forces. This capillary force is measured by a dimensionless capillary number (Nc) defned in Eq. (2) as: where 휇 is the displacing fuid viscosity, v is the displacing Darcy velocity, 휃 is the contact angle, and 휎 is the IFT between the displacing fuid (water) and the displaced fuid (oil). Nc is closely related to residual oil saturation and oil recovery and increases as residual oil saturation decreases. Consequently, a higher Nc will result in a higher oil recovery. A typical brine fooding has a Nc in the range of 10−7 to 10−6. Increasing Nc from this value to a range of 10−2 reduces the residual oil saturation to the barest minimum and result in an increase of the oil recovery factor. From Eq. (2), this can be achieved in three ways: (1) increasing the displacing fuid viscosity (휇); (2) increasing the injection fuid velocity (v); (3) reducing the IFT (휎). Increasing the injection fuid velocity may cause the injection pressure to be greater than the fracture pressure of the reservoir, thereby, fracturing the reservoir rock. Meanwhile, increasing the displacing fuid viscosity using polymer solutions increases the capillary number by less than 100 times [42]. Practically, only the method of reducing IFT can be used to increase Nc by 1000 times. This is achieved with the aid of surfactants. When surfactant solutions are injected along with brine into oil reservoirs, the hydrophilic head reacts with water while the hydrophobic tail interacts with the components of the crude oil. As illustrated in Fig. 6, an adsorbed flm occurs as a result of the interaction between the oil and alkyl tail of the surfactant, hence, lowering the IFT at the oil/water interface. Reduction of IFT at the oil/water interface weakens the capillary forces withholding the trapped oil, thereby, causing oil droplets to fow with ease from the pore throats of the rock to form an oil bank downstream. Nc = (2) 휇 ⋅ v 휎 ⋅ cos 휃 , Fig. 5 Polymer retention mechanisms in porous medium [5] 178 International Nano Letters (2019) 9:171–202 1 3 Wettability alteration The propensity or inclination of a solid surface for a particular type of fuid in the presence of other immiscible fuids is termed wettability [60, 61]. In a reservoir rock system, the wettability of the rock surface dictates and controls the location, distribution and fow of fuids within the particular reservoir [62]. This petrophysical property is of particular importance because it infuences oil recovery parameters such as capillary pressure and relative permeability. The wettability of most oil reservoirs is categorized into oil-wet, water-wet and mixed wet state [63]. This property of reservoir rock system can be measured by either of the following methods: surface imaging test, zeta potential measurements, spontaneous imbibition and contact angle measurements. Most studies of wettability alteration measurements are carried out using contact angle, which is defned by the point where the interface of the oil and water meets at the rock surface. Surface with contact angle 휃>90° is considered oil-wet while 휃<90° is considered water-wet. Altering the wettability of a surface from oil-wet to water-wet diminishes the adhesive force of capillarity and increase the oil permeability of the reservoir, as depicted in Fig. 7. Thus, it can be deduced that oil recovery is more easily achieved in water-wet compared to oil-wet reservoir. The use of surfactant for wettability alteration has been exclusively studied for both conventional and unconventional reservoir rock system [59, 61, 64]. For unconventional (shale and tight) reservoirs characterized by low and/or ultra-low permeability, addition of surfactants at appropriate concentration into frac fuids were reported to improve the performance of hydraulic fracture treatment by altering the matrix wettability, and consequently the fuid fow behaviour [65, 66]. Accordingly, spontaneous imbibition occurs, hence, the aqueous phase penetrates into the matrix by overcoming the capillary forces trapping the oil in place, thereby, resulting in a higher oil recovery. Similarly, surfactants are used as active agents to recover oil from conventional sandstone and carbonate reservoirs [67–69]. The mechanism of wettability alteration of conventional rock pores by surfactant is termed a cleaning mechanism whereby the surfactant desorbs the oil-wet layer. Desorption of the oil-wet layer by surfactant alters the wettability of the surface and changes it to a more water-wet state. Carbonate reservoirs are preferentially treated with cationic surfactants while sandstone reservoirs are treated with anionic surfactants because of the likeness of their charge which makes them more efcient for the respective reservoir rock system [70]. In carbonate reservoirs, the negatively charged organic components of crude oil adsorb on the positively charged mineral surfaces of the rock pores. When cationic surfactants are added, ion-pair formation interactions occur between the monomer of the surfactant and anionic components of oil (mostly carboxylate) adsorbed on the rock surfaces from the crude oil [67, 71]. Thereafter, adsorbed material at the rock surface is desorbed from the rock. Subsequently, water imbibition occurs and oil is ejected out of the core material [72]. Desorption of the oleic phase from the surface of the rock changes the wettability of the rock to water-wet [71, 73]. Thus, more oil can be expelled, as illustrated in Fig. 8a. On the contrary, anionic surfactants are unable to desorb the carboxylate group inherent in the oleic phase from the pore surface due to the likeness/similarity of their Fig. 6 Adsorption of surfactant at oil/water interface [10] Fig. 7 Improved permeability due to wettability alteration of rock from oil-wet to water-wet. Adapted from [125] International Nano Letters (2019) 9:171–202 179 1 3 surface charges. Instead, they induce and create weak capillary forces through hydrophobic interaction between the hydrophobic tail of the surfactants and the oleic phase (see Fig. 8b) [74]. Albeit, the interaction also displaces the oil, it is not as efcient as the ion-pair interaction and changes oil-wet to neutral wet condition. Meanwhile, nonionic surfactants adsorb on rock surfaces by polarization of 휋 electrons and ion exchange [67]. Overall, cationic surfactants are more efcient wettability agents compared to other surfactant types. The mechanism of wettability alteration by surfactants of oil-wet carbonate surface is deemed suitable for explaining wettability alteration of oil-wet sandstone surfaces containing clay minerals where oil is adsorbed on the negatively charged sandstone surface by polar interactions, surface precipitation and acid/base interactions [75]. Surfactant types and their structure Laboratory testing and feld studies of surfactant EOR have appraised and assessed numerous surfactants for their suitability in oil recovery. They are majorly classifed into anionic surfactants, non-ionic surfactants, cationic surfactants and zwitterionic surfactants (see Fig. 9) depending on the nature of the hydrophilic head group. Table 2 depicts the structures of these classes of surfactants. More recently, due to the defciency of conventional surfactants in fooding operations, new sets of surfactants are being developed and tested for EOR applications. This includes polymeric surfactants, viscoelastic surfactants, Gemini surfactants, and biosurfactants. More details of the properties and efciency of this new class of surfactants have been reviewed by Rafa et al. [32], Kamal et al. [9], and Pal et al. [76]. Anionic surfactant Anionic surfactants are the most commonly used surfactants. This is largely due to the fact that most of the EOR works of surfactant fooding have focussed on sandstone reservoirs. The surface-active portion of this class of surfactant bears a negative charge such as carboxylate (COO−), sulphate (SO2− 4 ), or sulphonate (SO− 3 ), though in association with a cation usually an alkaline metal (Na+ or K+). The sulphonate class of anionic surfactants is stable in higher temperatures, but susceptible to high salinity and precipitates in the presence of divalent cations. On the other hand, the sulphate class has greater tolerance salinity (both monovalent and divalent cations), but decompose at high temperatures [76]. Cationic surfactant Cationic surfactants are surfactants whose hydrophilic head bears a positive charge, though in conjunction with a halide group. They dissociate in water to form an amphiphilic cation and an anion. This class of surfactants is easily attracted to negatively charged surfaces of clays and is very efcient in altering reservoir rock wettability. Cationic surfactants have been identifed to hold the key for unlocking the vast and abundant hydrocarbons trapped in carbonate reservoirs due to similitude of their surface charges. Nonetheless, they are more expensive than anionic surfactants because of the highpressure hydrogenation reaction required during their synthesis [77]. Non‑ionic surfactant Unlike cationic and anionic surfactants, non-ionic surfactants do not ionize in aqueous solution. The hydrophilic group consists of non-dissociable functional groups such as alcohol, phenol, ether, ester, or amide. Meanwhile, the lipophilic group consists of the alkyl or alkylbenzene group. Although the hydrophilic group lacks ionic charge, they are soluble in water because of their inherent polarity caused by the presence of hydrogen bond Fig. 8 Wettability alteration by a cationic surfactant [68], b anionic surfactant [74] Fig. 9 Structure of the diferent class of surfactants 180 International Nano Letters (2019) 9:171–202 1 3 Table 2 Surfactant types and classifcation [10, 59] Surfactant type Examples Structures Anionic Sodium dodecylbenzene sulfonate CH3(CH2)11C6H4SO− 3 Na+ Sodium dodecyl sulphate (SDS) CH3(CH2)11SO− 4 Na+ Sodium stearate CH3(CH2)16COO−Na+ N-Ethoxy sulfonate H(OCH2CH2)n–O–SO2–R Alcohol propoxy sulphate (APS) ROH–[CH2–CHO–CH3]x–SO− 3Na+ R=16–17, x=7 Alpha-Olefn sulfonate (AOS) R–CH=CH–(CH2)n–SO3Na R=C10–C20 n=10–20 Alkyl polyalkoxy alkyl sulfonate or alkyl aryl polyalkoxy alkyl sulfonate RO(R′O)n R″SO3 − M+ R=C8–C24 R′=ethyl or a mixture of ethyl and propyl R″=Ethyl, propyl, hydroxypropyl, or butyl n=integer from 1 to 20, preferably from 2 to 8 M+ =monovalent cation such as NH4+, Na+, K+ Branched alkyl benzene sulfonate Docusate sodium C20H37NaO7S Guerbet alkoxy sulphate CnH2n+1O–POx–EOy–SOo− 3 n=is an integer between 12 and 44 x=is an integer between 0 and 50 y=is an integer between 0 and 100 Sulfonated, ethoxylated alcohol or alkyl phenol RO(CH2)(CH2)xCH2CH2SO− 3 M+ M+ =monovalent cation such as NH4+, Na+, and K+ Alkyl alcohol propoxylated sulphate R–(OHCH2CH2CH2)nO SOo− 3 M+ M+ =monovalent cation such as NH4+, Na+, and K+ Nonionic Polyoxyethylene alcohol CnH2n+1(OCH2CH2)m OH, where n=8–18; m=3–15 Alkylphenol ethoxylate C19H19C6H4–(OCH2CH2)n OH n=5–10 NEODOL RO(CH2CH2O)x CH2COO−M+ R=C8–C18 x=1–15  M=alkali or alkaline earth metal NEODOL ethoxylate 91-8 RO–(CH2CH2O)n–H R=blend of C9, C10, and C11 alcohol n=integer from 1 to 20, an average number of 8 NEODOL 67 propoxylated sulphate (N67-7POS) RO–(OHCH2CH2CH2)n–O–SOo− 3 M+, where R=blend of C16 and C17 alcohols n=integer from 1 to 20 with an average number of 7 Synperonic PE/F68 HO–(C2H4O)m–(C3H6O)n–H, where n=integer from 1 to 20 and preferably 2 to 8 M+ =monovalent cation such as NH4+, Na+, and K+ Cationic Cetyl trimethyl ammonium bromide (CTAB) CH3(CH2)15N+(CH3)3Br − Laurylamine hydrochloride CH3(CH2)11NH3 +Cl− Dodecyl trimethyl ammonium bromide (DTAB) C12H25N+(CH3)3Br− Zwitterionic Dodecyl betaine C12H25N+(CH3)2CH2COO− Lauramidopropyl betaine C11H25CONH(CH2)3N+(CH3)2CH2COO− Cocoamido-2-hydroxypropyl sulfo betaine CnH2n+1CONH(CH2)3N+(CH3)2CH2CH(OH)CH2SO3 − International Nano Letters (2019) 9:171–202 181 1 3 and van der Waals interaction. As compared to ionic surfactants, non-ionic surfactants have a higher salinity tolerance, but a lower IFT reduction ability [78]. Zwitterionic surfactant Zwitterionic surfactants are characterized by the presence of anionic and cationic surface charges on their hydrophilic head. They exhibit both anionic and cationic properties upon dissociation. Besides, they possess good tolerance to high salinity and temperature conditions. Typical examples of this class of surfactants are the betaine and sulfo betaine [79]. Challenges of surfactant fooding Like polymers, the major challenge of surfactant fooding process is surfactant retention. Surfactant retention may be due to phase trapping, precipitation or adsorption. The dominant surfactant retention mechanism is the surfactant adsorption process. Surfactant adsorption on rock pores results in loss and decrease in surfactant concentration, thereby, reducing the quantity of surfactant molecules available for the IFT reduction of oil–water interface, and consequently reduces the economic feasibility of the EOR method [80]. The adsorption process occurs when the interface is energetically favoured by the surfactant in comparison to the bulk phase. Thus, the adsorption at the solid–liquid interface takes place by the transfer of the molecule of the surfactant to the solid–liquid interface from the bulk solution phase [81]. The interaction of the chemicals and rock surfaces by electrostatic interaction, van der Waals interaction, chemical and lateral interaction, hydrogen bonding, hydrophobic bonding and solvation of various species resulting in polarization of 휋 electrons are responsible for surfactant adsorption on rock pores. Surfactant adsorption is higher when opposite charges exist between the surfactant molecules and rock surfaces. Hence, it can be deduced that surfactant adsorption in reservoir is dependent on the nature of surfactant itself (i.e., its chemical structure) and the nature of the rock surface. Additionally, electrolyte concentration (salinity), temperature, pH, composition of reservoir fuids and the condition of solution are other factors that dictate surfactant adsorption process in reservoirs rocks. High-salinity conditions are found to result in high surfactant adsorption irrespective of surfactant concentration [82]. Contrariwise, surfactant adsorption is decreased with an increase in temperature due to the onset of higher kinetic energy. Meanwhile, the amount of surfactant adsorption at diferent pH depends on its resultant charge which will react with charges available at the surface. For instance, increasing the pH of a sandstone surface leads to the surface being negatively charged, and would lead to a reduction of anionic surfactant. Meanwhile, adsorption of anionic surfactant will increase if the pH is lowered. To prevent the chemical adsorption at the solid–liquid interface, it is important to bind the chemical molecules of the surfactant at the liquid–liquid or liquid–air interface. To this end, studies have suggested surfactant screening and selection by surface charge to be matched to specifc reservoir rock as a means of reducing surfactant adsorption in reservoirs. More recently, the use of low-cost sacrifcial agent (such as polyelectrolytes and ionic liquids) evolved, has been prodigiously researched, and is being exploited for reducing surfactant adsorption in reservoirs [8, 83]. Alkali fooding Alkali fooding is an EOR technique that utilizes an alkali (a basic compound, ionic salt of an alkali metal or alkaline earth metal) to improve oil recovery factor. The method is distinct from other EOR methods on the basis that the chemicals that aid the oil recovery are generated in situ during the EOR process by saponifcation reaction [84]. Saponifcation reaction is defned as the reaction between an organic acid and caustic alkali to form soap indicated by the reaction in Eq. (3). Figure 10 illustrates the chemical model for the alkali–oil chemistry in reservoir rock. The organic acid is obtained from the acidic component of the crude oil. The generated soap acts as an in situ surfactant to lower IFT and emulsify the crude oil, thereby, improving oil recovery [85]. Along with the aforementioned low IFT and emulsifcation processes, diferent mechanisms have been postulated to be responsible for higher oil recovery by alkali fooding. Other mechanisms posited for EOR by alkali fooding HA + OH (3) − ↔ A− + H2O. Fig. 10 Schematic of alkali fooding [36] 182 International Nano Letters (2019) 9:171–202 1 3 includes: oil-phase swelling, wettability alteration, and disruption of rigid flms [86]. The existence of divergent mechanisms is due to the dissimilar chemical character of the crude oil and the reservoir rock under distinct environments such as temperature, salinity, pH, and hardness concentration. The diferent crude oil in diferent reservoirs exhibit widely disparate behaviours when they come in contact with alkali. Depending on the mineralogy of the rock, the alkali interacts with the rock in numerous ways such as surface exchange and hydrolysis, congruent and incongruent dissolution reactions, and insoluble salt formation by reaction with hardness ions in the fuid and those exchanges from rock surface. Several alkalis have been screened for application in alkali fooding. These include sodium metaborate (NaBO2), sodium carbonate (Na2CO3), sodium hydroxide (NaOH), and sodium bicarbonate (NaHCO3). The selection of alkali to be used is dependent on the type of formation, clay and mineral content, and the presence of divalent cations. NaOH are less preferred because at elevated temperature, they interact strongly with the sandstone surface, thus, causing increased porosity and consequently sandstone weight loss. Moreover, caustic consumption resulting from the dissolution of the caustic alkali in silicate minerals pose detrimental factor during feld application [87]. Na2CO3 is the most preferred alkali due to its low-cost and better transport properties in porous media. Nonetheless, the presence of calcium and other divalent cations cause precipitation of alkalis such as Na2CO3 unless soft brine is used. NaBO2 have better tolerance for divalent ions and have been suggested as replacement for Na2CO3 [88]. Meanwhile, NaHCO3 is preferred in reservoirs containing clay minerals. Finally, due to precipitation of alkali in carbonate reservoirs due to the presence of anhydrite (CaSO4) and gypsum (CaSO4.2H2O), sandstone reservoirs are the preferred formation for alkali fooding. Foam fooding Due to the limitations of gas injection methods which includes viscous fngering and gravity override, foam, a dispersion of gas in liquid, such that the liquid phase is continuous and some part of the gas phase is made discontinuous by a thin liquid flm called lamellae emerged as a promising solution for improving oil recovery efciency [89]. Foam controls oil recovery by displaying two favourable mechanisms that are benefcial to the EOR process. Firstly, foams increase the apparent viscosity of the injectant, thereby, promoting a more favourable mobility ratio. Lastly, the bubbles of the foam expand in porous media, hence, exhibiting selective fuid diversion from thief zones to lower permeability regions or unswept zones in the reservoir [90]. This makes the foam fooding process more efcient than water fooding, gas injection and water-alternating-gas injection process. Hitherto, foams are classifed as a gas injection method. Examples of traditional foam fooding methods include CO2 foams, nitrogen foams, and air foams. Latterly, chemicals such as surfactants, protein and polymers have been used to synthesize stable foams with longer half-life [19, 82]. Challenges of foam fooding For efective foam applications in EOR, the foam used in the fooding operation for oil recovery is expected to remain stable and propagate in the reservoir in the presence of resident reservoir oil and brines, at the prevailing reservoir temperature and salinity conditions [35, 91]. Generally, conventional foams generated using surface-active agents (e.g., surfactant) help to lower surface tension and improve foam stability by their adsorption at the gas–liquid interface of the foam [92]. Nonetheless, chemical foams depend on the constant regeneration of foam lamellae for successful propagation in porous media [93, 94]. The major challenge associated with the use of surfactant-stabilized foam and polymer-enhanced foam is the stability of their lamellae especially in porous media as the foam contacts the resident reservoir brines and crude oil [95]. This is because their adsorption on the rock surfaces in the presence of electrolytes can be very high [96]. Hence, their foams are thermodynamically unstable, with high rate of coalescence and coarsening. The major mechanisms of foam lamellae destruction and ageing process are liquid drainage, coalescence, and coarsening [97, 98]. Binary combination of conventional chemical EOR Recently, binary combination of chemicals evolved and has been tested on pilot and feld scale to further improve oil recovery. This method of EOR developed from the need to exploit the synergy of the individual chemicals and to complement each other weakness during fooding process. The binary combination led to the formation of alkali–surfactant, alkali–polymer, surfactant–polymer, and alkali–surfactant–polymer fooding process. Alkali–surfactant (AS) fooding During AS fooding, slug of alkaline solution is frst injected and followed by slug of surfactant. The efciency of the process is higher than the individual alkaline or surfactant fooding process. As earlier stated, the alkali reacts with naphthenic contents of the crude oil to generate in situ soap. The addition of surfactant to the alkaline solution further reduces IFT and creates emulsions with higher interfacial International Nano Letters (2019) 9:171–202 183 1 3 resistance. Furthermore, the presence of alkaline decreases the adsorption of expensive surfactant chemicals on clay mineral contents (such as montmorillonite, kaolinite and illite) of the rock pores because the charges of the mineral surfaces becomes more negative. The lower adsorption of the surfactant increases the amount of surfactant available in the reservoir to recover residual and capillary trapped oil in rock pores, hence, a higher oil recovery [99]. Alkali–polymer (AP) fooding The shortcoming of alkaline fooding is that it lacks the required mobility control required to push oil in the reservoir due to a lower mobility of the displacing phase to the displaced phase. Simultaneous injection of polymer slug with alkali improves mobility control of injectant and complement the efciency of alkali fooding. Also, the presence of alkali lowers the adsorption of polymer on rock pores [100]. However, an optimum concentration of alkali and polymer required for formulation of AP slug must be determined. This is because the presence of high concentration of alkaline may cause hydrolysis of the polymer molecules and impair its viscosity. Jung et al. reported a 30% incremental recovery of heavy oil by AP food [101]. Surfactant–polymer (SP) fooding Depending on the ultimate aim of the fooding process, either chemical can be injected as the first slug during SP fooding. If the aim of the fooding process is to lower adsorption, polymer slugs are injected frst as sacrifcial agent and for conformance control. Conversely, polymer slug are injected behind surfactant slug when the aim of the fooding process is to avoid fngering of chase water in the surfactant slug. Whichever injection mode is adopted, there is strong tendency for high efciency of the mixture of both chemicals at their interface due to difusion and dispersion in the reservoir. Besides, inaccessible pore volume phenomenon may aid the mixing of the chemicals when polymer slug is injected behind the surfactant. The synergy of both chemicals leads to a higher oil recovery [102]. Alkali–surfactant–polymer (ASP) fooding ASP fooding technique involves the injection of alkali, surfactant and polymer solutions to achieve EOR. Due to the integrated synergy of the individual component of the injected slug, this method is widely regarded as the most promising chemical EOR process [103]. The combined chemicals improve both pore scale and volumetric sweep efciency. The frst slug comprises of alkali and surfactant which mobilizes residual oil trapped in the pore spaces. Subsequently, polymer slug is injected to improve the mobility ratio and consequently the volumetric sweep efciency [104]. Finally, a freshwater and drive water slug is injected to optimize the chemical recovery, as shown in Fig. 11. The synergy of alkali and surfactant reduces IFT to ultralow values [102]. Besides, there is competition for adsorption of both chemicals on rock pores which ultimately results in lower adsorption of the surfactant. An additional mechanism of this EOR process is the synergy between the injected synthetic surfactant and the in situ generated soap caused by the presence of alkali [100, 105]. The optimum salinity for the generated soap is very low. Due to this, the injected alkali is lower than the amount required for consumption and cannot be propagated in the reservoir. Meanwhile, the optimum salinity of surfactant is high. Thus, the addition of synthetic surfactant complement the defciency of the alkali such that when the soap and the surfactant mixes, the optimum salinity range in which IFT reaches its low values is increased and widened [76, 99, 105]. Finally, the polymer content improves the mobility of the injected chemicals and aid a higher conformance control and sweep efciency [104]. Like other EOR process, ASP fooding has its own challenges. This include surfactant precipitation and scaling issues, difculty in treatment of produced emulsions and pitfall of produced water disposal to conform with set limit. a. Surfactant precipitation and scaling issues Surfactant precipitation occurs as a result of the reaction between alkali and divalent metal cations present in formation brines. The precipitated material deposit scales on wellbore equipment, thereby, fouling it. For this reason, ASP is deemed unsuitable in carbonate rock formations [106]. b. Treatment of produced emulsions As the injected chemicals of ASP slug breakthrough in production well, the Fig. 11 Diagrammatic representation of ASP fooding [10] 184 International Nano Letters (2019) 9:171–202 1 3 strong synergetic interaction between the chemicals attracts them to the oil/water interface, thus, inducing a stable emulsion. Unlike conventional emulsion, the produced emulsions are thermodynamically stable and not easy to demulsify as they remain concentrated at the oil–water interfaces. The enhanced emulsion stability is caused by electrostatic and steric efects of the injected surfactants, soaps, and polymers. The presence of stable emulsions in the produced fuid from oil wells poses diffculty for the separation and processing in the separator [107]. c. ASP produced water disposal treatment The presence of stable emulsion in the produced water from ASP fooding process is a cause of concern during the treatment of produced water to meet disposal requirement. This is because the emulsifed water exhibits a high oily and suspended solids content, which is difcult to dispose due to the adsorption of injected chemicals on the surface of the oil droplets. The necessity to meet the specifed standard for disposal of produced water aboard makes the overall process strenuous [10, 107]. Recent trends in chemical EOR The new trends in chemical EOR includes the application of nanotechnology, the trial of new chemical substance such as ionic liquids, and the development of improved technology from previously known chemical EOR methods. Application of nanotechnology The application of nanotechnology has profered solutions to some of the issues ravaging the oil and gas industry ranging from petroleum exploration, drilling and completion, fow assurance problems, hydraulic fracturing and EOR. Nanoparticles have recently found application in chemical EOR due to their ability to react with amphiphilic and macromolecular components of EOR chemicals. They form polymeric nanofuids, nanosurfactants, and nano-stabilized foam when reacted with polymers, surfactants and foams, respectively. The newly formed suspension (or composite materials as the case maybe) exhibit sterling and fascinating properties diferent from the individual component of the material. In polymer molecules, the presence of nanoparticles improves rheological behaviour and prevents degradation of the polymer molecules. Nanoparticle-stabilized foams are found to have a longer half-life. Additionally, the lamellae bubbles are thicker, hence, thermodynamically stable. Nanosurfactants have ultra-low IFT due the irreversible adsorption of nanoparticles at the interface. Overall, nano-chemicals have lower adsorption during the various tests conducted in porous media. Hence, they have been deemed more suitable and tagged as the next revolution for the application of chemical EOR methods [14, 108, 109]. Nanofuid fooding Though most works are still in the laboratory and pilot scale, nanoparticles have been tested for their application in EOR. Diferent laboratory studies show that nanofuids (mixture of nanoparticles with aqueous solution) can recover trapped oil from reservoir efciently. During its use for EOR purposes, nanoparticles are either used as nanodispersion (nanoparticle in aqueous water, alcohols or brine) or as nanofuids (nanoparticle in chemical base fuids, e.g., surfactant or polymer) to enhance their fuid property and make them more efcient for EOR application purposes. Recently, the feld application of nanofuid fooding for EOR has been reported in Cupiagua Sur feld, TN feld, Castilla and Chichimene feld of Colombia with a higher oil recovery for all feld trials [28]. Mechanism of nanofuid fooding When applied for EOR purposes, nanofluids operate in similitude to surfactants and improve oil production through the mechanisms of wettability alteration, IFT reduction and emulsion stabilization. Wettability alteration Like surfactants, nanoparticles alter the wettability of porous media [110]. Wasan and Nikolov elucidated the mechanism of wettability alteration by nanofuids and termed it structural disjoining pressure, the ability of the fuids to spread on the rock surface due to an imbalance of the interfacial forces among the aqueous, oleic and solid surface [111]. Initially, the nanoparticles are ordered within the fuid resulting in the formation of a wedge flm between the solid and oil subFig. 12 Ordering of nanoparticle in the wedge flm resulting in structural disjoining pressure gradient at the wedge vertex [112] International Nano Letters (2019) 9:171–202 185 1 3 strate (see Fig. 12) [114]. Thereafter, due to the nanoparticle structuring in the wedge confnement, the flm tension (structural disjoining pressure) near the vertex is high. As the structural disjoining pressure increases, it causes the nanofuid to spread at the wedge tip, thus, enhancing the spreading behaviour of the nanofuid [112]. McElfresh et al. [113] attributed the energies that drive this mechanism in nanofuids to the inherent Brownian motion and electrostatic repulsion among the nanoparticles within the fuid gradient at the wedge vertex [114]. Onyekonwu et  al. studied the wettability alteration potential of three polysilicon nanoparticles (PSNP): lipophobic and hydrophilic PSNP (LHPN), hydrophobic and lipophilic PSNP (HLPN), and neutrally wet PSNP (NWPN), with the aim of improving oil recovery. LHPN changes the wettability of oil-wet to water-wet and made water-wet rocks strongly water-wet. Meanwhile, NWPN alters the wettability of the rock surface to a neutral state because of the presence of hydrophilic and hydrophobic moieties [115]. Hendraningrat et al. observed that the use of hydrophilic nanoparticles resulted in wettability alteration of Berea core plugs and as the concentration of nanoparticles increases, the contact angle of the aqueous phase decreases further, and consequently an increase in water wetness of the core plug [116]. IFT reduction In addition to its wettability alteration mechanism, nanoparticles can lower the IFT between oil and the displacing fuid. Using a glass micromodel, Torsater et al. observed a reduction in dynamic IFT in their experimental study of hydrophilic nanoparticles [117]. Likewise, Roustaei et al. conducted an experimental investigation of hydrophobic and lipophilic polysilicon (HLP) and naturally wet polysilicon (NWP) nanoparticles for EOR [118]. The result shows a decrease in oil–water IFT from 26.3 mN/m to 1.75 mN/m and 2.55 mN/m after application of HLP and NWP nanofuids, respectively. Applying spinning drop method, Li et al. observed that IFT decreased between synthetic oil and brine/nanofuid after injecting nanofuid onto several waterwet Berea sandstone core plugs [119]. The ability of nanoparticles to lower IFT means the frictional force between the water-phase and oil phase will decrease, capillary number will be greatly improved and consequently oil recovery. Emulsion stabilization Addition of nanoparticles to oil– water system infuences phase behaviour of the system, thereby, inducing viscous emulsion which are very stable. As compared to emulsions stabilized by surfactant molecules which can be dynamically adsorbed or desorbed from the interface, emulsions generated by solid nanoparticles have stronger tendency to irreversibly adsorb at the interface (see Fig. 13). The irreversible adsorption at the interface protects the emulsion droplet formed against focculation and coalescence, thus, inducing stability [30]. In porous media, due to their stable structure, nanoparticle-stabilized emulsions exhibit fow divergence by plugging pathways of fngers in waterfooded reservoir, hence, increasing vertical and areal sweep efciency of the reservoir [120]. Types of nanofuid fooding Polymeric nanofuids Polymeric nanofuid utilize the synergistic combination of nanoparticles and polymer macromolecules, hence, displaying sterling and fascinating properties for EOR purposes. Depending on the solution conditions, their combination interacts through several forces, namely electrostatic and van der Waals interaction, hydrogen bonding, hydrophobic interaction, steric repulsion, and electrosteric repulsion [121]. The newly formed novel materials exhibit improved thermal properties, salt-tolerant behaviour, improved rheological properties and high-performance characteristics that ease recovery of oil from the reservoir. The rheological properties of the polymer increase in the presence of nanoparticles. Besides, the nanoparticle stability also improved in the presence of the polymer solution [122]. Ion-shielding efect of the nanoparticle in polymeric nanofuid is responsible for their stability in high-salinity conditions [123]. Meanwhile, thermal vibrations of the nanoparticle in high temperature occurs which improves the solution conductivity [124]. Hence, the use of polymeric nanofuids are profered and deemed more suitable for applications in high-salinity and high-temperature reservoirs [25]. Table 3 lists the laboratory results for the application of polymeric nanofuids for EOR indicating their suitability for oilfeld applications. Fig. 13 Nanoparticle-stabilized emulsions [30] 186 International Nano Letters (2019) 9:171–202 1 3 Surfactant nanofuid The combination of nanoparticle and surfactant has also been prodigiously investigated for EOR applications. Their mixture modifes the properties of the reservoir by inducing wettability change and adsorb at the oil–water interface through the surface-active groups inherent in their component [109]. Hence, surfactant nanofuids, otherwise referred to as nanosurfactants, achieve ultra-low IFT and generate stable emulsions where precursor nanoparticles or surfactants separately do not [125]. Besides, adsorption interaction of the surfactant on the nanoparticles surface lowers the adsorption of surfactant on rock pores via competitive adsorption mechanism [126, 127]. Nonetheless, the relative concentration ratio between the nanoparticle and the surfactant is paramount and defnes the properties of the system. A lower concentration ratio between the surfactant and the nanoparticle implies that only a small portion of surfactant is available to coat the nanoparticle surface. On the other hand, large concentration ratio will results in a bilayer of surfactant forming on the nanoparticle surface [109, 125]. Table  4 summarizes the experimental results of the application of nanosurfactant for recovery of oil. Nanoparticle/nanoparticle–surfactant foam Foam stability in porous media largely depends on the stability of its lamellae [128]. Nanoparticles, either by their addition into the foaming surfactant solution or through their surface wettability modifcations has recently provided an alternative to generate stable foam at harsh reservoir conditions [129]. Nanoparticles performed similar roles in nanoparticlesstabilized foams and foams stabilized by nanoparticles–surfactant mixtures. Most of the limitations of surfactant-stabilized foams can be circumvented using nanoparticles as the stabilizing components of the foam. Nanoparticles are solids and the foams they stabilize are expected to be highly resistant to unfavourable reservoir conditions of high salinity and temperatures [130]. The stability of nanoparticlestabilized foam does not depend on the modifcation of the polymer chain or surfactant chemical structure like conventional chemical-stabilized foams [131]. Three major mechanisms of foam stabilization by nanoparticles have been identifed as: (1) particle detachment energy; (2) maximum capillary pressure of coalescence; (3) the kinetic of flm drainage. Nanoparticles can adsorb at Table 3 Laboratory results of oil recovery applications by polymeric nanofuid [30] *Heavy oil References NP type Polymer/copolymer type PNF conc. (ppm) Brine/conc. Temp (°C) Porous media type Incremental oil recovery (%) [161] SiO2 PEOMA 10,000 1.0 wt% NaCl 30 Berea sandstone 19.5 [162] SiO2 PAMAM 1500 10 wt% NaCl, 0.15 wt% MgCl2 0.10 wt% CaCl2 90 Berea sandstone 16.3 [163] SiO2 Prop-2-enamide/AM 8000 – 80 Quartz sand 21.0 [164] SiO2 AMPS 50,000 – 80 Quartz sand 23.22 [165] SiO2 PEG 10,000 – 80 Glass micromodel 20.0 [166] SiO2 MeDiC8AM 1500 12 wt% (NaCl and CaCl2) 82.3 Sandstone 20.0 [167] SiO2 AMC12S 1100 18 wt% 110 Sandstone 24.0 [168] SiO2 AA/AM 2000 2 wt% NaCl, 0.18 wt% CaCl2 65 Sandstone 20.1 [169] SiO2 PA–S 3000 5 wt% NaCl, 2 wt% CaCl2 25 – 12.77 [170] SiO2 AM/AA 1500 – – – 18.84 [171] SiO2 HPAM 1000 2.4 wt% (NaCl, CaCl2, MgCl2) 25 Glass micromodel 10.0 [22] SiO2 HPAM 800 3 wt% NaCl – Glass micromodel 10.0 [172] TiO2 HPAM – 2 wt% (NaCl, CaCl2, MgCl2·6H2O, Na2HCO3) – Sandstone 4.0* [173] MMT Clay HPAM 1000 10 wt% (NaCl, CaCl2, MgCl2) 90 Quartz sand 33.0 [12]. SiO2 Clay HPAM 1500 2.0 wt% (NaCl, CaCl2, MgCl2·6H2O) NS Sandstone 13.0 [174] SiO2 HPAM 600 6.0 wt% (NaCl, CaCl2, MgCl2·6H2O Na2SO4 Na2HCO3) 80 Quartz sand 10.54 International Nano Letters (2019) 9:171–202 187 1 3 the gas–liquid interface of foam with very strong adhesion energy that makes their attachment irreversible. This attachment energy has been reported to be many times larger than that of a surfactant molecule [132–134]. The relationship between the energy required to remove the particle from the interface Wr, (also known as adsorption or detachment energy), the radius of the particle, R, the interface surface tension 훾훼훽 and the particle contact angle at the interface, θ, is given as: Equation  (4) shows that, at favourable intermediate contact angles (between 60° and 90°), the detachment energy will be very large. The particles will be strongly Wr = 휋R (4) 2 훾훼훽 (1 ± cos 휃) 2. and irreversibly adsorbed on the gas–liquid interface making them to form more stable foam than the surfactants which possess less adsorption energy due to their smaller sizes and less energetic participation at the fuid–fuid interface [135–137]. However, very low detachment energy will be obtained at extremely low and high contact angles (i.e., ≤30° and ≥150°) which will make the particles to be either highly hydrophilic or highly hydrophobic, thus making them unable to generate and stabilize strong foams [94]. The stability of the nanoparticles-stabilized foams is improved by the steric barrier provided to foam thinning by the adsorption of nanoparticles on bubble surfaces which increases the maximum capillary pressure the foam lamellae can experience without rupturing (see Fig. 14). Table 4 Laboratory results of oil recovery applications by nanosurfactant Nanoparticle Surfactant NP conc. Surfactant conc. Base fuid Oil type Porous media type Mechanism of recovery RF References SiO2 SDS 0.1–0.5 wt% 0.2 wt% Deionized water Crude oil Quartz sand IFT, competitive adsorption 4.68% IO [126] SiO2 Alfoterra, Soloterra 0.1–0.8 wt% 0.005–0.2 wt% Brine Crude oil Dolomite, limestone IFT, WA 37–45% OOIP [175] SiO2 TX-100 0.1 wt% 0.1 wt% Brine Crude oil+kerosene Sandstone IFT, WA 8% IO [176] SiO2 CTAB 0.05–0.5 wt% 0.1 wt% Brine Heavy oil Micromodel ES 17.4–38% OOIP [177] SiO2 SDS 0.25 wt% 1 wt% Brine Heavy oil Mircomodel IFT, ES 5% IO [178] SiO2 Non-ionic Tween 20 2–4 wt% 0.74 wt% Deionized water Heavy oil Micromodel IFT, ES 18–39% [179] SiO2 CTAB 0–5 wt% 0.09 mM Distilled water Heptane – IFT – [180] SiO2 Lecithin NaCAS Tween 60 – 0.01–1.4 wt% – Vegetable oil – IFT, WA – [181] Hydrophilic and hydrophobic SiO2 SDS 0.1 wt% 0.01–0.6 wt% Deionized water – Sandstone IFT, adsorption reduction – [182] Non-ferrous metal Sulphanole 0.001 wt% 0.0078–0.05 wt% – Heavy oil – IFT, WA 12–22% IO [183] Al2O3 PRNS 0.001–1 wt% Distilled water Heavy oil Sandstone WA 33% IO [184] Fumed SiO2 Hydrophobic SiO2 Ziziphus spinachristi 0.05–0.2 wt% 0.1–8 wt% Deionized water – Shale sandstone Adsorption reduction – [185] ZrO2 SDS, CTAB 0.01 wt% 0.1–0.4 wt% Distilled water Heavy oil Micromodel IFT, WA – [186] ZrO2, NiO TX-100, CTAB 0.004–0.05 wt% 0.1–3.2 wt% Deionized water – Limestone WA – [129] SiO2 SDS, PAM 0.5–2.0 wt% 0.14 wt% Deionized water Medium oil Sandstone IFT, WA 60% OOIP [187] ZrO2 Non-ionic Tween and Span 0.05–0.1 wt% – Distilled water Heavy oil Carbonate WA – [188] 188 International Nano Letters (2019) 9:171–202 1 3 Foam stability is enhanced by a three-dimensional network structure formed by the stratifcation of the nonadsorbing nanoparticles in the intervening thin flm separating the dispersed phase. Sun et al. studied the infuence of nanoparticles on generation, propagation and stability of SiO2/SDS-stabilized foam in micromodels and sandpack porous media [134]. From the results of their studies, the mechanism of SiO2/SDS foam stabilization by silica nanoparticles in the presence of oil is explained with Fig. 15. In the case of SDS-stabilized foam, the shape of the oil droplet could not be changed by the foam because the microforce acting on the oil droplet was small. This subsequently leads to bubble ruptures and coalescence leaving substantial amount of oil trapped in the porous media. In the case of SiO2/SDS foam, large amount of oil was displaced by the foam due to the higher microforce acting on the oil droplet. The higher microforce was attributed to the enhanced viscoelasticity of the bubble surface by the attached nanoparticles. Table 5 summarizes laboratory and experimental results of nanoparticles-stabilized and nanoparticle-surfactant-stabilized foams. Smart nano‑waterfooding The injection of nanoparticles dispersed in water, brine, and/or alcohol (nanodispersion) is referred to as smart nano-waterfooding [138]. This process relies on the large surface area and other inherent properties of the injected nanoparticle to boost oil recovery. For example, SiO2 nanoparticles is very efcient for IFT reduction at the oil–water interface. Meanwhile, nanoparticles such as aluminium oxide (Al2O3), copper oxide (CuO), iron oxide (Fe2O3), nickel oxide (NiO) and magnesium oxide (MgO) are efcient for reducing viscosity of the oleic phase in the porous media. Additionally, most of these nanoparticles can alter wettability of the rock surface and/or increase the viscosity of the injectant when injected with waterfood, hence, their ability to improve oil recovery (see Table 6). Ionic liquids application for EOR Due to high cost and environmental issues associated with the use of conventional chemical EOR, ionic liquids, a molten salt has gained tremendous attention for applications in EOR due to their green nature. Ionic liquids typically consist of organic cations and organic or inorganic anions and are classifed accordingly [139]. They exhibit several useful features such as good solubility, high ionic conductivity, reusability, and possess good thermal stability (see Tables 7, 8) [140]. Depending on the anions, cations and alkyl group composition of ionic liquids, their properties vary and their efciency/efectiveness are altered accordingly. For example, the viscosity incremental factor of ionic liquids during their use as injectants depends on the length of the alkyl group present. Other mechanism of ionic liquid application includes wettability alteration and IFT reduction due to their surface-active nature and micelle formation property [141, 142]. As compared to surfactants, laboratory works shows ionic liquids are better alternatives as they reduce IFT at high-salinity and high-temperature conditions [143–145]. Besides, ionic liquids have a better ability to self-organize during their aggregation behaviour at the interface. Moreover, ionic liquids show better capacity to stabilize emulsions. However, the shortcoming of the novel application of this chemical for EOR is that when its constituent contains halogen-anions, they cross the limit of greenness. Degradation of such ionic liquids produces hydrogen Fig. 14 Foams stabilized by nanoparticles [89] Fig. 15 Mechanisms of oil droplet mobilization by a SDS foam, and b SiO2–SDS foam [134] International Nano Letters (2019) 9:171–202 189 1 3 Table 5 Laboratory and experimental investigation of nanoparticle/nanoparticle-surfactant-stabilized foams References NP type NP size (nm) NP conc. Surfactant Temperature (°C) Pressure Salinity Foam generator Oil recovery [189] SiO2, Al O2 3, CuO, TiO2 10–40 0.002–0.1 wt% – 27 – NaCl (0.3 wt%) Sandpack 5.1–17.4% OOIPa [190] PEG-coated SiO2 5 0.01–0.1 wt% – 21.1–90 1350–1400 psia NaCl (2–4 wt%) Glass beads pack, capillary tube – [191] SiO2 100–150 0–5 wt% – 25, 60 1200–2000 psia NaCl (0.5, 2.0, 5.0%) Sapphire observation tube – [192] AlOOH 10–100 1 wt% SC (0–100 mM) 60 6 mPa NaCl (10– 600 mM), CaCl2 (10–200 mM) Sandpack ~ 20% OOIPa [193] SiO2 17 0.01–0.5 wt% – 25 1200 psig, 1500 psig NaCl (2.0%) Berea sandstone core – [136] SiO2 100–200 0.05–3.0% w/v PEG, Tergitol 15-S20, DCDMS 35, 50 1200–3000 psia – Glassbead pack – [194] APTES–SiO2 20–30 0.01 wt% SDS (0.4 wt%) 25 14.7 psi – Glassbead pack 18% OOIPa [195] SiO2 20 0.25–1.0 wt% – 25 1500 psig NaCl Glassbead pack, capillary tube, sapphire tube – [196] PECNP – 1.0 wt% Surfonic N120 40 1300 psi, 1800 psi KCl (2.0 wt%) Indiana limestone 10.71% OOIPb [197] SiO2 5, 10 0.01–1.0 wt% PEG, proprietary coated (EOR5XS, EOR-12) 50–90 2000 psia, 2800psia NaCl (0–4 wt%) Glassbead pack, biose sandstone, Berea sandstone, Indiana limestone – [198] TTFA 80 0.5 wt% Cationic, anionic and non-ionic surfactant (0.2 wt%) 25 1300 psi (backpressure) NaCl (1.0 wt%) Berea sandstone – [94] PEG-coated SiO2 10 (20) 0.5 wt% AOS (0–0.5 wt%) 25 100 psi (backpressure) NaCl (1–10 wt%), API Brine Berea sandstone 10% OOIPa [199] SiO2, Al O2 3, CuO, TiO2 10–40 0.1–1.0 wt% AOS (O.5 wt%) Room temperature – NaCl (2 wt%) Sandpack models 5–14% OOIPa [160] FA 100–200 < 0.05 wt% AOS (0.0315 wt%) – – NaCl (1.0–5.0 wt%), CaCl2 (0–9.5 wt%) Bentheimer sandstone – [200] SiO2 5, 12, 25, 80 0.5–10 wt% – 70 2200 psi NaCl (8.0 wt%), CaCl2 (2.0 wt%) Biose sandstone, Sandpack – [201] Al O2 3–coated SiO2 20 1–5 wt% Triton CG-110 AOS, PG (0.1–0.5 wt% Room temperature 100 psi (backpressure) – Berea sandstone 14.8–20.6% OOIPa [202] MWCNT 10 0.01 wt% Tergitol 15-s-40, AOS 25 – NaCl (2.4 wt%), CaCl2 (0.6 wt%) Ottawa sandpack – 190 International Nano Letters (2019) 9:171–202 1 3 fluoride (HF) and hydrogen chloride (HCl) which are harmful to the environment. Additionally, high adsorp – tion of the ionic liquids was reported during adsorption studies on kaolinite clay at high salinity [146]. Hence, more studies on ionic liquids are required to overcome these limitations for feld applications. Alkaline–cosolvent–polymer (ACP) as a new EOR technology Due to the limitations of well researched and previously applied chemical EOR methods, researchers have consist – ently and are constantly researching into new and viable chemical EOR techniques capable of ensuring higher oil recovery with no downside. Such limitations include but not limited to: (1) alkaline concentration that results in ultralow IFT is often too low for practical purposes and shows poor phase behaviour; (2) The use of AP foods generates highly viscous macroemulsions which results in high pressure gra – dient and phase trapping; (3) ASP formulations fnd it diffcult to pass stringent aqueous stability tests. More recently, ACP fooding emerged as a new chemical EOR with great prospect and potential compared to conventional EOR meth – ods [147]. ACP foods combine the synergy of low concen – tration of inexpensive light cosolvents to AP solutions. The synergy of the chemicals improves efciency of oil recovery in two important ways. Firstly, the addition of cosolvents results in the formation of low-viscosity microemulsion as compared to the undue highly viscous microemulsions of ASP fooding. Lastly, the presence of light cosolvent in the ternary combination greatly improves the phase behaviour in such a way that they can be tailored for a wide range of application. With availability of polymer for mobility control, ACP fooding performs in similitude to ASP while being simpler and more robust [148]. Other challenges of chemical EOR Apart from the previously discussed issues of retention of chemical (surfactant and polymer) molecules which poses severe threat for the application of chemical methods of EOR, other challenges encountered by the application of chemical EOR is the expensiveness of the chemicals used during oil recovery and formation damage of subsurface by chemicals. Formation damage Notwithstanding the highly coveted oil recovery during vari – ous application of chemical EOR methods, an important lim – itation of this EOR method is the formation damage issues a induced from the retention or reaction of the chemicals in Incremental oil recovery over waterfood bIncremental oil recovery over surfactant-stabilized foam Table 5 (continued) References NP type NP size (nm) NP conc. Surfactant Temperature (°C) Pressure Salinity Foam generator Oil recovery [203] PEG-coated SiO2 5 (10) 0.3 wt% AOS (0.5 wt% 55, 75 110 psi (backpressure) NaCl (1–8 wt%) Heterogeneous sandpack 34.4% OOIPa 9% OOIPb [89] SiO2 Al2O3 12–20 0.05–5.0 wt% SDS (0.03 wt%) 25 – NaCl (0.5 wt%) Hele-Shaw cell – [204] SiO2 Al O2 3 15–20 1.0 wt% SDS (0.01–1.0 wt%) 25 – NaCl (0.25–6.0 wt%), CaCl2 (0.125–5.0 wt%), AlCl3 (0.025–0.1 wt%) Hele-Shaw cell – [205] PEG-SiO2, GLYMO-SiO2 12, 20 0.5 wt% AOS 25, 60, 80 110 psi (backpressure) NaCl (8 wt%), CaCl2 (2 wt%) Sandpack 29.0–43.3% OOIPa International Nano Letters (2019) 9:171–202 191 1 3 Table 6 Summary of oil recovery by smart nano-waterfooding a Recovery depends on the type of PSPN and oil type References NP type NP size (nm) NP conc Base fuid Salinity Temp. Oil type/ viscosity Rock type Oil recovery [206] SiO2 Al2O3 TiO2 10–40 0.005 wt% Deionized water Brine 1 (2 wt% NaCl, 0.2 wt% KCl, 0.2 wt% CaCl2, 0.1 wt% MgCl2) Brine 2 (3wt% NaCl) 26, 40, 50, 60 °C 21.7 cP Limestone – [115] LHPN, NWPN, HLPN 10–60 0.2–0.3 wt% Ethanol and water NaCl (3 wt%) Ambient Intermediate oil (28.3° API), light oil (41.1° API) Sandstone 0.75–36.67%a [207] HLPN – 0.1–0.4 wt% Ethanol NaCl (3 wt%) Ambient 33° API Sandstone 19.31% [116] SiO2 7 0.01, 0.05, 0.1 wt% Brine NaCl (3 wt%) Ambient 5.1 mPas Sandstone 0–14.29% [208] TiO2 – 0.01 wt%, 1 wt% Brine NaCl (0.5–1.0 wt%) – 41.21 cP Sandstone ~31% [209] Hydrophobic fumed SiO2 12 0.1–0.4 wt% Ethanol NaCl (5 wt%) Ambient 33.53° API 27.43° API Sandstone 25.43% 14.55% [210] Al2O3, TiO2, SiO2 17–40 0.05 wt% PVP NaCl (3.0 wt%) 25, 50 80 °C 5.1 cP Sandstone 19–25% [211] SiO2, IIT 20 10 vol.% DIW NaCl, KCl, MgCl2·6H2O, CaCl2, Na2SO4, NaHCO3 (2.0 wt%) 25 °C, 55 °C 24.58 cP Sandstone 50–55% [212] SiO2, Al2O3 87 0.1–1.0 wt% Brine NaCl (7.0 wt%) 25, 40 60 °C 35° API Sandstone SiO2 ( 5.14–13.88% Al2O3 (− 8.18 to − 4.65%) [213] Fe2O3, Al2O3, SiO2 – 0.01 wt% Brine Brine A (3.0 wt%) Brine B (1.5 NaCl, 1.0 CaCl2, 0.5 MgCl2) – 5.12 cP Sandstone 0.9–9.49 wt% [214] SiO2 7 0.01, 0.05, 0.1 wt% Brine NaCl (3.0 wt%) – 5.1 cP Sandstone 4.26–5.32% [215] SiO2 7 0.05–0.5 wt% Brine NaCl (3.0 wt%) – 15.3 cP Sandstone 5.0–15% [216] SiO2 20–70 0.1–0.6 wt% Brine NaCl (5.0 wt%) Ambient 33° API Carbonate 9–12% 16–17% (24 h ageing) [217] SiO2 14 0.1–5.0 wt% Distilled water – – 19° API Micromodel 8.7–26% [218] SiO2 5–60 0.01–3 wt% Brine NaCl (6.5 wt%) – 27.3° API Sandstone 9.0–19% 192 International Nano Letters (2019) 9:171–202 1 3 the reservoir rock system. Formation damage issues in the reservoir have the propensity to disrupt oil recovery performance, and cause additional technical and cost challenges to oilfelds operations and facilities [149]. For example, oilin-water emulsions or water-in-oil emulsions generated from the application of surfactant have been reported to cause severe pore blockage in low permeability reservoirs despite their mobility control potentials. Moreover, the precipitation, phase trapping and adsorption of surfactant molecules on rock pores during their use in reservoirs with hardness brines also results in blockage of pore throat system [149, 150]. Similarly, cases of hydrodynamic retention, mechanical entrapment, adsorption and inaccessible pore volume resulting from the focculation of polymers at high salinity cause the polymer molecules to accumulate and plug the surface of rock grains [151]. When these situations occur in rock pores with smaller diameter, it is referred to as particle fltration phenomenon. Meanwhile, alkali chemicals used during alkaline fooding have the capacity to dissolve clays and other minerals. During the dissolution process, fnes migration and damage emanate from the process which may damage reservoir permeability. Additionally, scale precipitation resulting from the incompatibility of alkali and formation water may deposit on the pore walls of reservoir rock, thereby, causing reduction in permeability or permanent loss of the reservoir [152]. Cost of chemical EOR process Generally, chemicals used for this EOR method are low. However, the large-scale feld implementation of chemical EOR leads to an astronomical rise in the cost of chemicals required for the process, and consequently an increase in the overall cost of the EOR process. Meanwhile, the choice of an EOR process is based on both efciency at recovering hydrocarbon and cost-efectiveness. The defciency of the application of this EOR method is that their selectivity and feld implementation is reliant on oil price regime. They are only economical and proftable during higher oil prices. For example, in the year 2015, when oil price crashed to ~ $40/ bbl, most oil felds applying chemical EOR were shut down to prevent losses. In Daqing oil feld, to ensure continued ASP fooding process is economical in some of its felds, weak alkali was substituted for strong alkali to lower the cost of the chemical EOR process [153]. Technical solutions to challenges of chemical EOR • Adsorption inhibitors To overcome the incessant adsorption of chemicals on rock pores during their use in chemical EOR, the use of adsorption inhibitor otherwise known as sacrifcial agent has gained remarkable attention and has been recommended for use during feld applications of chemical EOR especially in high-temperature and high-salinity reservoir [83]. The mechanism posited for the efciency of sacrifcial agents during their use in chemical EOR is that the sacrifcial agent form complexes with monovalent, divalent and polyvalent cations present in the hardness brine, thus, there is less cations for the chemicals to interact with in the formation fuids. Secondly, there is competition for adsorption sites of the rock pores between the chemicals and sacrifcial agent. Meanwhile, the sacrifcial agent gets preferentially adsorbed on the rock surface due to their high surface coverage and low desorption. Finally, the sacrifcial agent due to their high surface coverage blocks the access of the injected chemicals to other adsorption sites. The overall process increases the amount of chemicals present in the injected slug to efectively recover the residual and bypassed oil, hence, an incremental oil recovery. The most important factor to be considered during the selection of sacrifcial agents is that they must be very cheap. Typical examples of sacrifcial agents that have been tested and proven to be efective are polyacrylate and lignosulfonates [83, 154, 155]. Lignosulfonates are particularly economically attractive because they are obtained as by-products from pulp industry. • Conditioning the reservoir The presence of constituent hardness brines attacks and diminishes the functionality of injected chemicals for EOR process. For example, injecting chemicals in Arab-D formation of Ghawar feld in Saudi Arabia with total dissolved solids (TDS) ~ 200,000 mg/l will lead to high retention of the chemicals and make the EOR process unfeasible. To overcome this, researchers have identifed the process of conditioning the reservoir prior to injecting the chemicals for EOR. The conditioning process usually involves injection of Table 7 Typical properties of modern ionic liquids (sourced from [219]) A salt Cation or anion quite large Freezing point Preferably below 100 °C Liquidus range Often>200 °C Thermal stability Usually high Viscosity Normally<100 cP, workable Dielectric constant Implied<30 Polarity Moderate Specifc conductivity < 10 S cm2 mol−1 Vapour pressure Usually negligible Solvent and/or catalyst Excellent for many organic reactions Electrochemical window > 2 V, even 4.5 V, except for bronsted acidic systems International Nano Letters (2019) 9:171–202 193 1 3 a slug of water (prefush) with specifc characteristics and properties. The prefush is targeted at the hardness brines and screens or eliminates them from the reservoir prior to chemical EOR. Nonetheless, there is the need for proper design process when using prefush to determine the adequate and efective prefush for conditioning the reservoir. Major factors taken into consideration during the design process are the TDS of the feld, composition of feld brine, chemical concentration, chemical slug size, prefush concentration and prefush slug size [156, 157]. • Scale inhibitors Scales are common problems during the use of alkali fooding or ASP fooding. Scales form when the alkali present in the injectant reacts with divalent cations such as Ca2+ and Mg2+ present in the formation fuids. The deposition of scales blocks injection or production lines, thereby, lowering oil recovery process. In the reservoir, they reduce formation porosity and permeability by clogging rock pores. The use of scale inhibitors delay, reduce or prevent the formation of scales. Scale inhibitors work by either preventing the formation of scales or suppressing the activity of an already formed scale. When used as scale suppressant, they absorb onto the crystal surface of the already formed scale, thereby, preventing further growth of tiny crystals that precipiTable 8 Typical examples chemical EOR feld projects Country Field Formation Chemical EOR method Chemical type Incremental oil recovery USA Cottonwood Creek Carbonate Surfactant Polyoxyethylene alcohol – Bob Slaughter Surfactant Petroleum sulfonate – Yates feld Carbonate Surfactant Ethoxy sulphate 30 bbl/day Tanner Sandstone Surfactant ASP – Sho-Vel-Tum – Surfactant ASP – Cambridge, Minnelusa Sandstone Surfactant Polymer ASP PAM – West Kiehl – ASP – Albrecht Sandstone Polymer HPAM – West Cat Canyon Sandstone Polymer HPAM 66.7% over WF Canada Taber South – ASP – Taber Gauconitic – ASP – Sufeld Caen – Polymer ASP HAPAM – Seal – Polymer HPAM 5–6% Mooney – Polymer HPAM 12–25% Pelican Lake – Polymer HPAM 5–10% China Daqing Sandstone ASP 19.4–28% OOIP Gudong Sandstone ASP – Karamay Sandstone ASP – Shengli Carbonate ASP 16–28% Bohai Bay Sandstone Polymer HAPAM 13.5–20% OOIP India Viraj Sandstone Surfactant Polymer Petroleum sulfonate HPAM – Jhalora Sandstone ASP – Sanand Sandstone Polymer PAM – Indonesia Minas Sandstone Surfactant Petroleum sulfonate – Baturaja Carbonate Surfactant – Germany Eddesse-Nord – Polymer Xanthan – Argentina El Corobo – Polymer HPAM – Austria Matzen – Polymer HPAM – Russia Romashkino – Polymer HEC – Oman Marmul Sandstone Polymer HPAM 12% 194 International Nano Letters (2019) 9:171–202 1 3 tates out of the water. Besides, they coat the surface of the already formed scale crystals, hence, preventing them from adhering to the surface of pipes [106]. • Formulation of cost-efective EOR chemicals As a result of the expensiveness of EOR chemicals, research and development should focus on the formulation of cheap and efcient EOR chemicals from waste and by-products. New efcient biodegradable surfactants are been developed from waste cooking oil, unused coconut oil and palm oil fruit bunch [158, 159]. Additionally, nanoparticles to be used as nanofuid EOR chemicals are been generated from fyash, a waste product of coal fring plants [160]. Finally, the possibility of synthesizing graphene and carbon nanotubes from palm kernel shell, a waste product of palm oil refning is hereby proposed for future research. Field projects of chemical EOR Chemical EOR project has been implemented in various felds across the world. China has the largest feld application of chemical EOR with a reported incremental 300,000 bbl/day of oil. Other countries with high implementation of chemical EOR are USA and Canada. Polymer fooding and ASP fooding have been the most widely used chemicals for feld application and most of the oilfelds have been sandstone formations. Table 2 summarizes some chemical EOR feld projects in various countries across the world. Conclusion and recommendation The article presents an overview of chemical EOR and their applications for ensuring a sustainable energy future. The mechanism of their applications and recent progress have been explored and analysed. The challenges of their application have also been discussed. Field application of conventional chemical EOR have been reported to yield higher oil recovery. Meanwhile, the newly improved nano-chemicals with sterling properties have been limited to laboratory and pilot scale except for a few recently reported feld trials in China, Colombia and Ghawar feld of Saudi Arabia. This could be attributed to the averseness of oil companies to new technologies and a few uncertainties. These few uncertainties include non-availability of the cost implication of addition of nanoparticles to previously applied conventional chemicals, instability in oil prices, and inadequate data on health and environmental impact of application of nanoparticles. Hence, future research on chemical EOR should address the following areas: • Cost analysis of nanoparticles and other chemicals Previous researches have focussed on the injection of nanoparticles and associated chemicals and the resultant oil recovery mechanisms and quantity. The cost implication of nanoparticles in the laboratory have been adjudged to be less consequential due to its use in small quantity. However, the feld application of these chemicals will require larger quantities and longer times to the tune of years depending on the economic life of the feld. Thus, more researches and economic models preferably by petroleum economists that depicts the true economic implication of these novel chemicals at diferent and feasible oil regimes should be investigated. • Adsorption and retention behaviour of the novel nanochemicals The focal point of attention for most studies on mechanisms of most nano-chemicals has been on IFT, rheology, wettability alteration, and emulsion stabilization. Very few studies are available on the adsorption behaviour of the nano-chemicals during EOR application. Specifcally, the adsorption and retention behaviour of ionic liquids is lacking in literature. An adequate understanding of this mechanism is required due to its impact on the cost implication of the chemical EOR method. • Toxicity of nanoparticles Presently, there is inadequate research and insufcient information on the health safety and environmental implications of the use of nanoparticles. More research on the toxicity of these chemicals and their impact on humans and the environment is required for further research. • Modelling for feld implementation Though many laboratory studies for the application of nano-chemicals have been presented, an accurate modelling of the behaviour of this chemical is outstanding. This is required to serve as a guideline for design and feld implementation of the various nano-chemicals for oil recovery. • CO2 sequestration potential Most of the nano-chemicals yielded wettability alteration to a more water-wet condition during their laboratory studies. Ability of the nano-chemicals to tether the reservoir to a more waterwet condition is a good omen and indicator of the nanochemicals potential for carbon capture and sequestration (CCS). Hence, the opportunities of utilizing this nanochemicals for CCS should be properly investigated. • Separation of produced water containing nanoparticles and other chemicals Previously, the development of membranes for the separation of produced water have been tethered towards the separation of produced water, oily components and conventional chemicals. With the new introduction of nano-chemicals and other chemicals such as ionic fuid, the dynamics of the constituents of produced water will change and the previously developed International Nano Letters (2019) 9:171–202 195 1 3 membranes may not be efcient. Thus, new membranes capable of efectively and efciently separating the new constituents of the produced water will be required. • Opportunities for recycling After production, the opportunities of recycling the produced nano-chemicals should be considered. Additional experiments on reintroduction of previously used chemicals should be tested to determine their efciency. Finally, a comparative analysis of the cost implication and efciency of introducing new chemicals and reused chemicals should be made. Acknowledgements The authors would like to thank the Ministry of Higher Education, Malaysia, and Universiti Teknologi Malaysia for supporting this research through Research Management Grant Vot. nos. Q.J30000.2546.14H50 and R.J130000.7846.4F946. Open Access This article is distributed under the terms of the Creative Commons Attribution 4.0 International License (http://creativeco mmons.org/licenses/by/4.0/), which permits unrestricted use, distribution, and reproduction in any medium, provided you give appropriate credit to the original author(s) and the source, provide a link to the Creative Commons license, and indicate if changes were made. References 1. Afolabi, F., Ojo, T., Udeagbara, S., Gbadamosi, A.: Bitumen extraction from tar sands using solvent techniques. Int. J. Sci. Eng. Res. 8, 783–790 (2017) 2. Ogiriki, S.O., Agunloye, M.A., Gbadamosi, A.O., Olafuyi, A.O.: Exploitation of Bitumen from Nigerian tar sand using hot-water/steam stimulation process. Pet. Coal 58, 407–413 (2016). https://doi.org/10.1021/ac010415i 3. Agi, A., Junin, R., Syamsul, M.F., Chong, A.S., Gbadamosi, A.: Intermittent and short duration ultrasound in a simulated porous medium. Petroleum (2018). https://doi.org/10.1016/j. petlm.2018.03.012 4. Gbadamosi, A.O., Kiwalabye, J., Junin, R., Augustine, A.: A review of gas enhanced oil recovery schemes used in the North Sea. J. Pet. Explor. Prod. Technol. 5, 1–15 (2018). https://doi. org/10.1007/s13202-018-0451-6 5. Sorbie, K.S.: Polymer Improved Oil Recovery. Blackie and Son Ltd, London (1991) 6. Gbadamosi, A.O., Junin, R., Manan, M.A., Yekeen, N., Augustine, A.: Hybrid suspension of polymer and nanoparticles for enhanced oil recovery. Polym. Bull. (2019). https://doi. org/10.1007/s00289-019-02713-2 7. Agi, A., Junin, R., Shirazi, R., Afeez, G., Yekeen, N.: Comparative study of ultrasound assisted water and surfactant fooding. J. King Saud. Univ. Eng. Sci. (2018). https://doi. org/10.1016/j.jksues.2018.01.002 8. Hanamertani, A.S., Pilus, R.M., Idris, A.K., Irawan, S., Tan, I.M.: Ionic liquids as a potential additive for reducing surfactant adsorption onto crushed Berea sandstone. J. Pet. Sci. Eng. 162, 480–490 (2018). https://doi.org/10.1016/j.petro l.2017.09.077 9. Kamal, M.S., Hussein, I.A., Sultan, A.S.: Review on surfactant fooding: phase behavior, retention, IFT, and feld applications. Energy Fuels 31, 7701–7720 (2017). https://doi.org/10.1021/acs. energyfuels.7b00353 10. Olajire, A.A.: Review of ASP EOR (alkaline surfactant polymer enhanced oil recovery) technology in the petroleum industry: prospects and challenges. Energy 77, 963–982 (2014). https:// doi.org/10.1016/j.energy.2014.09.005 11. Thomas, S.: Enhanced oil recovery—an overview. Oil. Gas. Sci. Technol. Rev. l’IFP 63, 9–19 (2007). https://doi.org/10.2516/ ogst:2007060 12. Khalilinezhad, S.S., Cheraghian, G., Karambeigi, M.S., Tabatabaee, H., Roayaei, E.: Characterizing the role of clay and silica nanoparticles in enhanced heavy oil recovery during polymer fooding. Arab. J. Sci. Eng. 41, 2731–2750 (2016). https://doi. org/10.1007/s13369-016-2183-6 13. Levitt, D., Pope, G.A.: Selection and screening of polymers for enhanced-oil recovery. In: Present. SPE Symp. Improv. Oil Recover. 20–23 April. Tulsa, Oklahoma, USA, Society of Petroleum Engineers, pp. 1–18 (2008). https://doi.org/10.2118/11384 5-ms 14. Sun, X., Zhang, Y., Chen, G., Gai, Z.: Application of nanoparticles in enhanced oil recovery: a critical review of recent progress. Energies 10, 345 (2017). https://doi.org/10.3390/en10030345 15. Samanta, A., Bera, A., Ojha, K., Mandal, A.: Comparative studies on enhanced oil recovery by alkali–surfactant and polymer fooding. J. Pet. Explor. Prod. Technol. 2, 67–74 (2012). https:// doi.org/10.1007/s13202-012-0021-2 16. Zaitoun, A., Makakou, P., Blin, N., Al-Maamari, R.S., AlHashmi, A.-A.R., Abdel-Goad, M.: Shear stability of EOR polymers. SPE-141113-PA. SPE J. 17, 335–339 (2012). https://doi. org/10.2118/141113-pa 17. Kumar, N., Gaur, T., Mandal, A.: Characterization of SPN pickering emulsions for application in enhanced oil recovery. J. Ind. Eng. Chem. 54, 304–315 (2017). https://doi.org/10.1016/j. jiec.2017.06.005 18. Bera, A., Kumar, T., Ojha, K., Mandal, A.: Adsorption of surfactants on sand surface in enhanced oil recovery: isotherms, kinetics and thermodynamic studies. Appl. Surf. Sci. 284, 87–99 (2013). https://doi.org/10.1016/j.apsusc.2013.07.029 19. Samin, A.M., Manan, M.A., Idris, A.K., Yekeen, N., Said, M., Alghol, A.: Protein foam application for enhanced oil recovery. J. Dispers. Sci. Technol. 38, 604–609 (2017). https://doi. org/10.1080/01932691.2016.1185014 20. Ko, S., Huh, C.: Use of nanoparticles for oil production applications. J. Pet. Sci. Eng. 172, 97–114 (2019). https://doi. org/10.1016/j.petrol.2018.09.051 21. Krishnamoorti, R.: Extracting the benefts of nanotechnology for the oil industry. J. Pet. Technol. 58, 24–25 (2006). https://doi. org/10.2118/1106-0024-JPT 22. Yousefvand, H., Jafari, A.: Enhanced oil recovery using polymer/nanosilica. Proc. Mater Sci. 11, 565–570 (2015). https://doi. org/10.1016/j.mspro.2015.11.068 23. Khoja, A.H., Tahir, M., Amin, N.A.S.: Cold plasma dielectric barrier discharge reactor for dry reforming of methane over Ni/γ–Al2O3–MgO nanocomposite. Fuel Process. Technol. 178, 166–179 (2018). https://doi.org/10.1016/j.fuproc.2018.05.030 24. Gbadamosi AO, Junin R, Oseh JO, Agi A, Yekeen N, Abdalla Y, et al.: Improving hole cleaning efciency using nanosilica in water-based drilling mud. In: Present. SPE Niger. Annual International Conference on Exhibition. 6–8 August, Lagos, Niger., Lagos, Nigeria: Society of Petroleum Engineers, p. 16 (2018). https://doi.org/10.2118/193401-ms 25. Gbadamosi, A.O., Junin, R., Abdalla, Y., Agi, A., Oseh, J.O.: Experimental investigation of the efects of silica nanoparticle on hole cleaning efciency of water-based drilling mud. J. Pet. Sci. Eng. 172, 1226–1234 (2019). https://doi.org/10.1016/j.petro l.2018.09.097 196 International Nano Letters (2019) 9:171–202 1 3 26. Bera, A., Belhaj, H.: Application of nanotechnology by means of nanoparticles and nanodispersions in oil recovery—a comprehensive review. J. Nat. Gas Sci. Eng. 34, 1284–1309 (2016). https://doi.org/10.1016/j.jngse.2016.08.023 27. Agi, A., Junin, R., Gbadamosi, A.: Mechanism governing nanoparticle fow behaviour in porous media: insight for enhanced oil recovery applications. Int. Nano Lett. 8, 1–29 (2018). https://doi. org/10.1007/s40089-018-0237-3 28. Franco, C.A., Zabala, R., Cortés, F.B.: Nanotechnology applied to the enhancement of oil and gas productivity and recovery of Colombian felds. J. Pet. Sci. Eng. 157, 39–55 (2017). https://doi. org/10.1016/j.petrol.2017.07.004 29. Nikolov, A., Wu, P., Wasan, D.: Structure and stability of nanofuid flms wetting solids: an overview. Adv. Colloid Interface Sci. 264, 1–10 (2019). https://doi.org/10.1016/j.cis.2018.12.001 30. Gbadamosi, A.O., Junin, R., Manan, M.A., Yekeen, N., Agi, A., Oseh, J.O.: Recent advances and prospects in polymeric nanofuids application for enhanced oil recovery. J. Ind. Eng. Chem. (2018). https://doi.org/10.1016/j.jiec.2018.05.020 31. Yekeen, N., Manan, M.A., Idris, A.K., Padmanabhan, E., Junin, R., Samin, A.M., et al.: A comprehensive review of experimental studies of nanoparticles-stabilized foam for enhanced oil recovery. J. Pet. Sci. Eng. 164, 43–74 (2018). https://doi.org/10.1016/j. petrol.2018.01.035 32. Rafa, P., Broekhuis, A.A., Picchioni, F.: Polymeric surfactants for enhanced oil recovery: a review. J. Pet. Sci. Eng. 145, 723– 733 (2016). https://doi.org/10.1016/j.petrol.2016.07.007 33. Cheraghian, G., Hendraningrat, L.: A review on applications of nanotechnology in the enhanced oil recovery part A: efects of nanoparticles on interfacial tension. Int. Nano Lett. 6, 129–138 (2016). https://doi.org/10.1007/s40089-015-0173-4 34. Liu, Q., Dong, M., Ma, S., Tu, Y.: Surfactant enhanced alkaline fooding for Western Canadian heavy oil recovery. Colloids Surf. A Physicochem. Eng. Asp 293, 63–71 (2007). https://doi. org/10.1016/j.colsurfa.2006.07.013 35. Bashir, A., Sharif Haddad, A., Rafati, R.: Experimental investigation of nanoparticles/polymer enhanced CO2-foam in the presence of hydrocarbon at high-temperature conditions. In: SPE Int. Heavy Oil Conf. Exhib. 10–12 December, pp. 1–13. Society of Petroleum Engineers, Kuwait City (2018). https://doi. org/10.2118/193802-ms 36. Mandal, A.: Chemical food enhanced oil recovery: a review. Int. J Oil Gas Coal Technol. 9, 241–264 (2015) 37. Mandal, A., Samanta, A., Ojha, K.: Mobility control and enhanced oil recovery using partially hydrolysed polyacrylamide (PHPA). Int. J. Oil Gas Coal Technol. 6, 245–258 (2013). https ://doi.org/10.1504/IJOGCT.2013.052236 38. Wei, B.: Advances in polymer fooding. In: El-Amin, M.F. (ed.) Viscoelastic and Viscoplastic Materials. IntechOpen. https://doi. org/10.5772/64069. https://www.intechopen.com/books/visco elastic-and-viscoplastic-materials/advances-in-polymer-fooding 39. Sheng, J.J.: Polymer flooding—fundamentals and field cases. Enhanc. Oil Recover. F. Case Stud. (2013). https://doi. org/10.1016/b978-0-12-386545-8.00003-8 40. Delshad, M., Kim, D.H., Magbagbeola, O.A., Huh, C., Pope, G.A., Tarahhom, F.: Mechanistic interpretation and utilization of viscoelastic behavior of polymer solutions for improved polymerfood efciency. In: Present. SPE Symp. Improv. Oil Recover. 20–23 April. Tulsa, Oklahoma, USA, Society of Petroleum Engineers, pp. 1–15 (2008). https://doi.org/10.2118/113620-ms 41. Mishra, S., Bera, A., Mandal, A., Mishra, S., Bera, A., Mandal, A.: Efect of polymer adsorption on permeability reduction in enhanced oil recovery. J. Pet. Eng. 2014, 1–9 (2014). https://doi. org/10.1155/2014/395857 42. Wei, B., Romero-Zerón, L., Rodrigue, D.: Oil displacement mechanisms of viscoelastic polymers in enhanced oil recovery (EOR): a review. J. Pet. Explor. Prod. Technol. 4, 113–121 (2014). https://doi.org/10.1007/s13202-013-0087-5 43. Veerabhadrappa, S.K., Trivedi, J.J., Kuru, E.: Visual confrmation of the elasticity dependence of unstable secondary polymer foods. Ind. Eng. Chem. Res. 52, 6234–6241 (2013). https://doi. org/10.1021/ie303241b 44. Urbissinova, T.S., Trivedi, J., Kuru, E.: Efect of elasticity during viscoelastic polymer fooding: a possible mechanism of increasing the sweep efciency. SPE-133471-PA. J. Can. Pet. Technol. 49, 49–56 (2010). https://doi.org/10.2118/133471-pa 45. Veerabhadrappa, S.K.: Study of efects of polymer elasticity on enhanced oil recovery by core fooding and visualization experiments (thesis). A Master’s thesis submitted to the Department of Civil and Environmental Engineering, University of Alberta (2013) 46. Taylor, K.C., Nasr-El-Din, H.A.: Water-soluble hydrophobically associating polymers for improved oil recovery: a literature review. J. Pet. Sci. Eng. 19, 265–280 (1998). https://doi. org/10.1016/S0920-4105(97)00048-X 47. Kamal, M.S., Sultan, A.S., Al-Mubaiyedh, U.A., Hussein, I.A.: Review on polymer fooding: rheology, adsorption, stability, and feld applications of various polymer systems. Polym. Rev. 55, 491–530 (2015). https://doi.org/10.1080/15583724.2014.98282 1 48. Pu, W., Shen, C., Wei, B., Yang, Y., Li, Y.: A comprehensive review of polysaccharide biopolymers for enhanced oil recovery (EOR) from fask to feld. J. Ind. Eng. Chem. 61, 1–11 (2018). https://doi.org/10.1016/j.jiec.2017.12.034 49. Wever, D.A.Z., Picchioni, F., Broekhuis, A.A.: Polymers for enhanced oil recovery: a paradigm for structure–property relationship in aqueous solution. Prog. Polym. Sci. 36, 1558–1628 (2011). https://doi.org/10.1016/j.progpolymsci.2011.05.006 50. Gao, C.: Viscosity of partially hydrolyzed polyacrylamide under shearing and heat. J. Pet. Explor. Prod. Technol. 3, 203–206 (2013). https://doi.org/10.1007/s13202-013-0051-4 51. Chauveteau, G., Zaitoun, A.: basic rheological behavior of xanthan polysaccharide solutions in porous media: efect of pore size and polymer concentration. In: Proceedings of the First European Symposium on Enhanced Oil Recovery, Bournemouth, England, Soc. Pet. Eng. Richardson, TX, pp. 197–212 (1981) 52. Needham, R.B., Doe, P.H.: Polymer fooding review. J. Pet. Technol. 39, 1503–1507 (1987). https://doi.org/10.2118/17140-PA 53. Kennedy, J.R.M., Kent, K.E., Brown, J.R.: Rheology of dispersions of xanthan gum, locust bean gum and mixed biopolymer gel with silicon dioxide nanoparticles. Mater. Sci. Eng., C 48, 347–353 (2015). https://doi.org/10.1016/j.msec.2014.12.040 54. Sheng, J.J.: Chapter 5—polymer fooding. Mod. Chem. Enhanc. Oil Recover. 5, 101–206 (2011). https://doi.org/10.1016/b978-1- 85617-745-0.00005-x 55. Choppe, E., Puaud, F., Nicolai, T., Benyahia, L.: Rheology of xanthan solutions as a function of temperature, concentration and ionic strength. Carbohydr. Polym. 82, 1228–1235 (2010). https ://doi.org/10.1016/j.carbpol.2010.06.056 56. Xin, X., Yu, G., Chen, Z., Wu, K., Dong, X., Zhu, Z.: Efect of polymer degradation on polymer fooding in heterogeneous reservoirs. Polymers (Basel) 10, 1–25 (2018). https://doi. org/10.3390/polym10080857 57. Agi, A., Junin, R., Gbonhinbor, J., Onyekonwu, M.: Natural polymer fow behaviour in porous media for enhanced oil recovery applications: a review. J. Pet. Explor. Prod. Technol. (2018). https ://doi.org/10.1007/s13202-018-0434-7 58. Abbas, A.H., Sulaiman, W.R.W., Jaafar, M.Z., Gbadamosi, A.O., Ebrahimi, S.S., Elrufai, A.: Numerical study for continuous International Nano Letters (2019) 9:171–202 197 1 3 surfactant fooding considering adsorption in heterogeneous reservoir. J. King. Saud. Univ. Eng. Sci. 5, 1–9 (2018). https:// doi.org/10.1016/j.jksues.2018.06.001 59. Negin, C., Ali, S., Xie, Q.: Most common surfactants employed in chemical enhanced oil recovery. Petroleum 3, 197–211 (2017). https://doi.org/10.1016/j.petlm.2016.11.007 60. Cheraghian, G.: Efects of nanoparticles on wettability: a review on applications of nanotechnology in the enhanced oil recovery. Int. J Nano Dimens. 6, 443–452 (2015). https://doi.org/10.7508/ ijnd.2015.05.001 61. Mohammed, M., Babadagli, T.: Wettability alteration: a comprehensive review of materials/methods and testing the selected ones on heavy-oil containing oil-wet systems. Adv. Colloid Interface Sci. 220, 54–77 (2015). https://doi.org/10.1016/j.cis.2015.02.006 62. Alhammadi, A.M., AlRatrout, A., Singh, K., Bijeljic, B., Blunt, M.J.: In situ characterization of mixed-wettability in a reservoir rock at subsurface conditions. Sci. Rep. 7, 10753 (2017). https:// doi.org/10.1038/s41598-017-10992-w 63. Christensen, M., Tanino, Y.: Waterfood oil recovery from mixedwet limestone: dependence upon the contact angle. Energy Fuels 31, 1529–1535 (2017). https://doi.org/10.1021/acs.energyfuel s.6b03249 64. Alvarez, J.O., Schechter, D.S.: Wettability alteration and spontaneous imbibition in unconventional liquid reservoirs by surfactant additives. SPE J. 20, 107–117 (2017). https://doi. org/10.2118/177057-PA 65. Mirchi, V., Saraji, S., Goual, L., Piri, M.: Dynamic interfacial tension and wettability of shale in the presence of surfactants at reservoir conditions. Fuel 148, 127–138 (2015). https://doi. org/10.1016/j.fuel.2015.01.077 66. Kathel, P., Mohanty, K.K.: Wettability alteration in a tight oil reservoir. Energy Fuels 27, 6460–6468 (2013). https://doi. org/10.1021/ef4012752 67. Jarrahian, K., Seiedi, O., Sheykhan, M., Sefti, M.V., Ayatollahi, S.: Wettability alteration of carbonate rocks by surfactants: a mechanistic study. Colloids. Surf. A Physicochem. Eng. Asp 410, 1–10 (2012). https://doi.org/10.1016/j.colsurfa.2012.06.007 68. Salehi, M., Johnson, S.J., Liang, J.-T.: Mechanistic study of wettability alteration using surfactants with applications in naturally fractured reservoirs. Langmuir 24, 14099–14107 (2008). https:// doi.org/10.1021/la802464u 69. Salehi, M., Johnson, S.J., Liang, J.-T.: Enhanced wettability alteration by surfactants with multiple hydrophilic moieties. J. Surf. Deterg. 13, 243–246 (2010). https://doi.org/10.1007/s1174 3-010-1193-8 70. Esmaeilzadeh, P., Bahramian, A., Fakhroueian, Z.: Adsorption of anionic, cationic and nonionic surfactants on carbonate rock in presence of ZrO2 nanoparticles. Phys. Proc. 22, 63–67 (2011). https://doi.org/10.1016/j.phpro.2011.11.009 71. Standnes, D.C., Austad, T.: Wettability alteration in carbonates: interaction between cationic surfactant and carboxylates as a key factor in wettability alteration from oil-wet to water-wet conditions. Colloids Surf. A Physicochem. Eng. Asp 216, 243–259 (2003). https://doi.org/10.1016/S0927-7757(02)00580-0 72. Strand, S., Standnes, D.C., Austad, T.: Spontaneous imbibition of aqueous surfactant solutions into neutral to oil-wet carbonate cores: efects of brine salinity and composition. Energy Fuels 17, 1133–1144 (2003). https://doi.org/10.1021/ef030051s 73. Standnes, D.C., Nogaret, L.A.D., Chen, H.-L., Austad, T.: An evaluation of spontaneous imbibition of water into oil-wet carbonate reservoir cores using a nonionic and a cationic surfactant. Energy Fuels 16, 1557–1564 (2002). https://doi.org/10.1021/ ef0201127 74. Hou, B., Wang, Y., Huang, Y.: Mechanistic study of wettability alteration of oil-wet sandstone surface using diferent surfactants. Appl. Surf. Sci. 330, 56–64 (2015). https://doi.org/10.1016/j. apsusc.2014.12.185 75. Hou, B., Wang, Y., Cao, X., Zhang, J., Song, X., Ding, M., et al.: Surfactant-induced wettability alteration of oil-wet sandstone surface: mechanisms and its efect on oil recovery. J. Surf. Deterg. 19, 315–324 (2016). https://doi.org/10.1007/s1174 3-015-1770-y 76. Pal, S., Mushtaq, M., Banat, F., Al Sumaiti, A.M.: Review of surfactant-assisted chemical enhanced oil recovery for carbonate reservoirs: challenges and future perspectives. Pet. Sci. 15, 77–102 (2018). https://doi.org/10.1007/s12182-017-0198-6 77. Kumar, S., Panigrahi, P., Saw, R.K., Mandal, A.: Interfacial interaction of cationic surfactants and its efect on wettability alteration of oil-wet carbonate rock. Energy Fuels 30, 2846–2857 (2016). https://doi.org/10.1021/acs.energyfuels.6b00152 78. Ahmadi, M.A., Zendehboudi, S., Shafei, A., James, L.: Nonionic surfactant for enhanced oil recovery from carbonates: adsorption kinetics and equilibrium. Ind. Eng. Chem. Res. 51, 9894–9905 (2012). https://doi.org/10.1021/ie300269c 79. Kumar, A., Mandal, A.: Synthesis and physiochemical characterization of zwitterionic surfactant for application in enhanced oil recovery. J. Mol. Liq. 243, 61–71 (2017). https://doi. org/10.1016/j.molliq.2017.08.032 80. Amirianshoja, T., Junin, R., Idris, A.K., Rahmani, O.: A comparative study of surfactant adsorption by clay minerals. J. Pet. Sci. Eng. 101, 21–27 (2013). https://doi.org/10.1016/j.petro l.2012.10.002 81. Muherei, M.A., Junin, R., Merdhah, A.B.: Adsorption of sodium dodecyl sulfate, Triton X100 and their mixtures to shale and sandstone: a comparative study. J. Pet. Sci. Eng. 67, 149–154 (2009). https://doi.org/10.1016/j.petrol.2009.05.006 82. Yekeen, N., Manan, M.A., Idris, A.K., Samin, A.M.: Infuence of surfactant and electrolyte concentrations on surfactant Adsorption and foaming characteristics. J. Pet. Sci. Eng. 149, 612–622 (2017). https://doi.org/10.1016/j.petrol.2016.11.018 83. ShamsiJazeyi, H., Verduzco, R., Hirasaki, G.J.: Reducing adsorption of anionic surfactant for enhanced oil recovery: Part I. Competitive adsorption mechanism. Colloids Surf. A Physicochem. Eng. Asp 453, 162–167 (2014). https://doi. org/10.1016/j.colsurfa.2013.10.042 84. Gong, H., Li, Y., Dong, M., Ma, S., Liu, W.: Efect of wettability alteration on enhanced heavy oil recovery by alkaline fooding. Colloids Surf. A Physicochem. Eng. Asp 488, 28–35 (2016). https://doi.org/10.1016/j.colsurfa.2015.09.042 85. Pei, H., Zhang, G., Ge, J., Jin, L., Ma, C.: Potential of alkaline fooding to enhance heavy oil recovery through waterin-oil emulsifcation. Fuel 104, 284–293 (2013). https://doi. org/10.1016/j.fuel.2012.08.024 86. Sheng, J.J.: A comprehensive review of alkaline–surfactant– polymer (ASP) fooding. Asia Pac. J. Chem. Eng. 9, 471–489 (2014). https://doi.org/10.1002/apj 87. Sydansk, R.D.: Elevated-temperature caustic/sandstone interaction: implications for improving oil recovery (includes associated papers 11348 and 11548). Soc. Pet. Eng. J. 22, 453–462 (1982). https://doi.org/10.2118/9810-PA 88. Zhang, J., Nguyen, Q.P., Flaaten, A., Pope, G.A.: Mechanisms of enhanced natural imbibition with novel chemicals. Soc. Pet. Eng. J. 12, 912–920 (2009). https://doi.org/10.2118/11345 3-PA 89. Yekeen, N., Idris, A.K., Manan, M., Samin, A.M., Risal, A.R., Kun, T.X.: Bulk and bubble-scale experimental studies of infuence of nanoparticles on foam stability. Chin. J. Chem. Eng. 25, 347–357 (2017). https://doi.org/10.1016/j.cjche.2016.08.012 90. Rafati, R., Haddad, A.S., Hamidi, H.: Experimental study on stability and rheological properties of aqueous foam in the presence of reservoir natural solid particles. Colloids Surf. 198 International Nano Letters (2019) 9:171–202 1 3 A Physicochem. Eng. Asp 509, 19–31 (2016). https://doi. org/10.1016/j.colsurfa.2016.08.087 91. Rafati, R., Oludara, O.K., Haddad, A.S., Hamidi, H.: Experimental investigation of emulsifed oil dispersion on bulk foam stability. Colloids Surf. A Physicochem. Eng. Asp 554, 110–121 (2018). https://doi.org/10.1016/j.colsurfa.2018.06.043 92. Ahmadi, M.A., Shadizadeh, S.R., Salari, Z.: Dependency of critical micellization concentration of an anionic surfactant on temperature and potassium chloride salt. Pet. Sci. Technol. 32, 1913– 1920 (2014). https://doi.org/10.1080/10916466.2011.653700 93. Rossen, W.R.: A critical review of Roof snap-of as a mechanism of steady-state foam generation in homogeneous porous media. Colloids Surf. A Physicochem. Eng. Asp 225, 1–24 (2003). https ://doi.org/10.1016/S0927-7757(03)00309-1 94. Singh, R., Mohanty, K.K.: Synergy between nanoparticles and surfactants in stabilizing foams for oil recovery. Energy Fuels 29, 467–479 (2015). https://doi.org/10.1021/ef5015007 95. Zhu, T., Ogbe, D.O., Khataniar, S.: Improving the foam performance for mobility control and improved sweep efciency in gas fooding. Ind. Eng. Chem. Res. 43, 4413–4421 (2004). https:// doi.org/10.1021/ie034021o 96. Yusuf, S.M., Manan, M.A., Jaafar, M.Z.: Aqueous foams stabilized by hydrophilic silica nanoparticles via in-situ physisorption of nonionic TX100 surfactant. Iran. J. Energy Environ. 4(1), 8–16 (2013). https://doi.org/10.5829/idosi.ijee.2013.04.01.41132 97. Krzan, M., Caps, H., Vandewalle, N.: High stability of the bovine serum albumin foams evidenced in Hele–Shaw cell. Colloids Surf. A Physicochem. Eng. Asp 438, 112–118 (2013). https:// doi.org/10.1016/j.colsurfa.2013.01.012 98. Fameau, A.-L., Salonen, A.: Effect of particles and aggregated structures on the foam stability and aging. Comptes. Rendus. Phys. 15, 748–760 (2014). https://doi.org/10.1016/j. crhy.2014.09.009 99. Hirasaki, G., Miller, C.A., Puerto, M.: Recent advances in surfactant EOR. Soc. Pet. Eng. J. 16, 889–907 (2011). https://doi. org/10.2118/115386-pa 100. Sheng, J.J.: Critical review of alkaline–polymer fooding. J. Pet. Explor. Prod. Technol. 7, 147–153 (2017). https://doi. org/10.1007/s13202-016-0239-5 101. Chul, J.J., Ke, Z., Hyun, C.B., Jin, C.H.: Rheology and polymer fooding characteristics of partially hydrolyzed polyacrylamide for enhanced heavy oil recovery. J. Appl. Polym. Sci. 127, 4833– 4839 (2012). https://doi.org/10.1002/app.38070 102. Samanta, A., Ojha, K., Sarkar, A., Mandal, A.: Surfactant and surfactant–polymer fooding for enhanced oil recovery. Adv. Pet. Explor. Dev. 2, 13–18 (2011) 103. Pogaku, R., Mohd Fuat, N.H., Sakar, S., Cha, Z.W., Musa, N., Awang Tajudin, D.N.A., et al.: Polymer fooding and its combinations with other chemical injection methods in enhanced oil recovery. Polym. Bull. 74, 1–22 (2017). https://doi.org/10.1007/ s00289-017-2106-z 104. Dang, C., Nghiem, L., Nguyen, N., Yang, C., Chen, Z., Bae, W.: Modeling and optimization of alkaline–surfactant–polymer fooding and hybrid enhanced oil recovery processes. J. Pet. Sci. Eng. 169, 578–601 (2018). https://doi.org/10.1016/j.petro l.2018.06.017 105. Pal, N., Saxena, N., Mandal, A.: Characterization of alkali– surfactant–polymer slugs using synthesized gemini surfactant for potential application in enhanced oil recovery. J. Pet. Sci. Eng. 168, 283–300 (2018). https://doi.org/10.1016/j.petro l.2018.05.026 106. Qing, J., Zhou, B., Zhang, R., Chen, Z., Zhou, Y.: Development and application of a silicate scale inhibitor for asp fooding production scale. In: International Symposium Oilf. Scale, 30–31 January, Aberdeen, United Kingdom, Society of Petroleum Engineers, pp. 1–4 (2002). https://doi.org/10.2118/74675-ms 107. Nguyen, D.T., Sadeghi, N.: Stable emulsion and demulsifcation in chemical EOR fooding: challenges and best practices. In: SPE EOR Conf Oil Gas West Asia, 16–18 April Muscat, Oman (2012). https://doi.org/10.2118/154044-ms 108. Fakoya, M.F., Shah, S.N.: Emergence of nanotechnology in the oil and gas industry: emphasis on the application of silica nanoparticles. Petroleum (2017). https://doi.org/10.1016/j.petlm .2017.03.001 109. Almahfood, M., Bai, B.: The synergistic efects of nanoparticlesurfactant nanofuids in EOR applications. J. Pet. Sci. Eng. 171, 196–210 (2018). https://doi.org/10.1016/j.petrol.2018.07.030 110. Mahsa, B.S.: Enhancing hydrocarbon productivity via wettability alteration: a review on the application of nanoparticles. Rev. Chem. Eng. (2018). https://doi.org/10.1515/revce-2017-0105 111. Wasan, D.T., Nikolov, A.D.: Spreading of nanofuids on solids. Nature 423, 156–159 (2003) 112. Kondiparty, K., Nikolov, A., Wu, S., Wasan, D.: Wetting and spreading of nanofuids on solid surfaces driven by the structural disjoining pressure: statics analysis and experiments. Langmuir 27, 3324–3335 (2011). https://doi.org/10.1021/la104204b 113. Mcelfresh, P.M., Holcomb, D.L., Ector, D.: Application of nanofuid technology to improve recovery in oil and gas wells. In: SPE Int. Oilf. Nanotechnol. Conf. Exhib., Noordwijk, The Netherlands: Society of Petroleum Engineers, pp. 1–6 (2012). https:// doi.org/10.2118/154827-ms 114. Wasan, D., Nikolov, A., Kondiparty, K.: The wetting and spreading of nanofuids on solids: role of the structural disjoining pressure. Curr. Opin. Colloid Interface Sci. 16, 344–349 (2011). https ://doi.org/10.1016/j.cocis.2011.02.001 115. Onyekonwu, M.O., Ogolo, N.A.: Investigating the use of nanoparticles in enhancing oil recovery. In: Niger. Annu. Int. Conf. Exhib. 31 July–7 August, Tinapa, Calabar, Niger. Society of Petroleum Engineers, pp. 1–14 (2010). https://doi. org/10.2118/140744-ms 116. Hendraningrat, L., Li, S., Torsæter, O.: A corefood investigation of nanofuid enhanced oil recovery. J. Pet. Sci. Eng. 111, 128–138 (2013). https://doi.org/10.1016/j.petrol.2013.07.003 117. Torsater, O., Engeset, B., Hendraningrat, L., Suwarno, S.: Improved oil recovery by nanofuids fooding: an experimental study. In: Present. SPE Kuwait Int. Pet. Conf. Exhib. 10–12 December, Kuwait City, Kuwait, Society of Petroleum Engineers, pp. 1–9 (2012). https://doi.org/10.2118/163335-ms 118. Roustaei, A., Moghadasi, J., Bagherzadeh, H., Shahrabadi, A.: An experimental investigation of polysilicon nanoparticles’ recovery efficiencies through changes in interfacial tension and wettability alteration. In: Present. SPE Int. Oilf. Nanotechnol. Conf. Exhib. 12–14 June, Noordwijk, The Netherlands, Society of Petroleum Engineers, pp. 1–7 (2012). https://doi. org/10.2118/156976-ms 119. Li, S., Torsæter, O.: An experimental investigation of EOR mechanisms for nanoparticles fuid in glass micromodel. In: Int. Symp. Soc. Core Anal. (Avignon/Fr.), pp. 1–12 (2014). https:// doi.org/10.13140/rg.2.1.4181.3604 120. Chevalier, Y., Bolzinger, M.-A.: Emulsions stabilized with solid nanoparticles: pickering emulsions. Colloids Surf. A Physicochem. Eng. Asp 439, 23–34 (2013). https://doi.org/10.1016/j. colsurfa.2013.02.054 121. Kumar, S., Ray, D., Aswal, V.K., Kohlbrecher, J.: Structure and interaction in the polymer-dependent reentrant phase behavior of a charged nanoparticle solution. Phys. Rev. E. Stat. Nonlinear Soft Matter Phys 90, 1–10 (2014). https://doi.org/10.1103/PhysR evE.90.042316 122. Hu, Z., Haruna, M., Gao, H., Nourafkan, E., Wen, D.: Rheological properties of partially hydrolyzed polyacrylamide seeded by nanoparticles. Ind. Eng. Chem. Res. 56, 3456–3463 (2017). https ://doi.org/10.1021/acs.iecr.6b05036 International Nano Letters (2019) 9:171–202 199 1 3 123. Maghzi, A., Kharrat, R., Mohebbi, A., Ghazanfari, M.H.: The impact of silica nanoparticles on the performance of polymer solution in presence of salts in polymer fooding for heavy oil recovery. Fuel 123, 123–132 (2014). https://doi.org/10.1016/j. fuel.2014.01.017 124. Mallakpour, S., Khadem, E.: Recent development in the synthesis of polymer nanocomposites based on nano-alumina. Prog. Polym. Sci. 51, 74–93 (2015). https://doi.org/10.1016/j.progp olymsci.2015.07.004 125. ShamsiJazeyi, H., Miller, C.A., Wong, M.S., Tour, J.M., Verduzco, R.: Polymer-coated nanoparticles for enhanced oil recovery. J. Appl. Polym. Sci. 131, 1–13 (2014). https://doi. org/10.1002/app.40576 126. Wu, Y., Chen, W., Dai, C., Huang, Y., Li, H., Zhao, M., et al.: Reducing surfactant adsorption on rock by silica nanoparticles for enhanced oil recovery. J. Pet. Sci. Eng. 153, 283–287 (2017). https://doi.org/10.1016/j.petrol.2017.04.015 127. Suresh, R., Kuznetsov, O., Agrawal, D., Darugar, Q., Khabashesku, V.: Reduction of surfactant adsorption in porous media using silica nanoparticles. In: Present. Ofshore Technol. Conf. 30 April–3 May, Houston, Texas, USA, pp. 1–9 (2018) 128. Farajzadeh, R., Andrianov, A., Krastev, R., Hirasaki, G., Rossen, W.R.: Foam–oil interaction in porous media: implications for foam assisted enhanced oil recovery. In: SPE EOR Conf. Oil Gas West Asia, 16–18 April. Muscat, Oman, Muscat, Oman: Society of Petroleum Engineers, pp. 1–20 (2012). https://doi. org/10.2118/154197-ms 129. Nwidee, L.N., Lebedev, M., Barifcani, A., Sarmadivaleh, M., Iglauer, S.: Wettability alteration of oil-wet limestone using surfactant-nanoparticle formulation. J. Colloid Interface Sci. 504, 334–345 (2017). https://doi.org/10.1016/j.jcis.2017.04.078 130. Zhang, T., Roberts, M., Bryant, S.L., Huh, C.: Foams and emulsions stabilized with nanoparticles for potential conformance control applications. In: Present. SPE Int. Symp. Oilf. Chem. 20–22 April. Woodlands. Texas, Society of Petroleum Engineers, pp. 1–17 (2009). https://doi.org/10.2118/121744-ms 131. Mohd, T.A.T., Shukor, M.A.A., Ghazali, N.A., Alias, N., Yahya, E., Azizi, A., et al.: Relationship between foamability and nanoparticle concentration of carbon dioxide (CO2) foam for enhanced oil recovery (EOR). Appl. Mech. Mater. 548–549, 67–71 (2014). https://doi.org/10.4028/www.scientifc.net/AMM.548-549.67 132. Binks, B.P., Horozov, T.S.: Aqueous foams stabilized solely by silica nanoparticles. Angew. Chem. Int. Ed. 44, 3722–3725 (2005). https://doi.org/10.1002/anie.200462470 133. Zhang, S., Lan, Q., Liu, Q., Xu, J., Sun, D.: Aqueous foams stabilized by laponite and CTAB. Colloids Surf. A Physicochem. Eng. Asp 317, 406–413 (2008). https://doi.org/10.1016/j.colsu rfa.2007.11.010 134. Sun, Q., Li, Z., Li, S., Jiang, L., Wang, J., Wang, P.: Utilization of surfactant-stabilized foam for enhanced oil recovery by adding nanoparticles. Energy Fuels 28, 2384–2394 (2014). https://doi. org/10.1021/ef402453b 135. Binks, B.P.: Particles as surfactants—similarities and diferences. Curr. Opin. Colloid Interface Sci. 7, 21–41 (2002). https://doi. org/10.1016/S1359-0294(02)00008-0 136. Worthen, A., Bagaria, H., Chen, Y., Bryant, S.L., Huh, C., Johnston, K.P.: Nanoparticle stabilized carbon dioxide in water foams for enhanced oil recovery. In: Present. SPE Improv. Oil Recover. Symp. 14–18 April. Tulsa, Oklahoma, USA, Tulsa, Oklahoma, USA: Society of Petroleum Engineers, pp. 1–7 (2012). https:// doi.org/10.2118/154285-ms 137. Heydarian, A., Kharrat, R., Heydarian, S., Hashemi, A.: Impact of nano-particles on static performance of surfactant foams. J Am Sci 9, 444–449 (2013) 138. Afolabi, R.O.: Enhanced oil recovery for emergent energy demand: challenges and prospects for a nanotechnology paradigm shift. Int. Nano. Lett. (2018). https://doi.org/10.1007/ s40089-018-0248-0 139. He, Z., Alexandridis, P.: Ionic liquid and nanoparticle hybrid systems: emerging applications. Adv. Colloid Interface Sci. 244, 54–70 (2017). https://doi.org/10.1016/j.cis.2016.08.004 140. Chen, S.-L., Chua, G.-L., Ji, S.-J., Loh, T.-P.: Ionic liquid: a green solvent for organic transformations II. Ion. Liq. Org. Synth. (2007). https://doi.org/10.1021/bk-2007-0950.ch014 141. Mohammed, M.A., Babadagli, T.: Experimental investigation of wettability alteration in oil-wet reservoirs containing heavy oil. SPE Reserv. Eval. Eng. 19, 633–644 (2016). https://doi. org/10.2118/170034-PA 142. Bera, A., Belhaj, H.: Ionic liquids as alternatives of surfactants in enhanced oil recovery—a state-of-the-art review. J. Mol. Liq. 224, 177–188 (2016). https://doi.org/10.1016/j.molli q.2016.09.105 143. Hezave, A.Z., Dorostkar, S., Ayatollahi, S., Nabipour, M., Hemmateenejad, B.: Dynamic interfacial tension behavior between heavy crude oil and ionic liquid solution (1-dodecyl-3-methylimidazolium chloride ([C12mim][Cl]+ distilled or saline water/ heavy crude oil)) as a new surfactant. J. Mol. Liq. 187, 83–89 (2013). https://doi.org/10.1016/j.molliq.2013.05.007 144. Hezave, A.Z., Dorostkar, S., Ayatollahi, S., Nabipour, M., Hemmateenejad, B.: Efect of diferent families (imidazolium and pyridinium) of ionic liquids-based surfactants on interfacial tension of water/crude oil system. Fluid Phase Equilib. 360, 139–145 (2013). https://doi.org/10.1016/j.fuid .2013.09.025 145. Pillai, P., Kumar, A., Mandal, A.: Mechanistic studies of enhanced oil recovery by imidazolium-based ionic liquids as novel surfactants. J. Ind. Eng. Chem. 63, 262–274 (2018). https ://doi.org/10.1016/j.jiec.2018.02.024 146. Bin Dahbag, M., AlQuraishi, A., Benzagouta, M.: Efciency of ionic liquids for chemical enhanced oil recovery. J. Pet. Explor. Prod. Technol. 5, 353–361 (2015). https://doi.org/10.1007/s1320 2-014-0147-5 147. Aitkulov, A., Luo, H., Lu, J., Mohanty, K.K.: Alkali–cosolvent– polymer fooding for viscous oil recovery: 2D evaluation. Energy Fuels 31, 7015–7025 (2017). https://doi.org/10.1021/acs.energ yfuels.7b00790 148. Fortenberry, R., Kim, D.H., Nizamidin, N., Adkins, S., Arachchilage, G.W.P.P., Koh, H.S., et al.: Use of cosolvents to improve alkaline/polymer fooding. SPE J. 20, 255–266 (2015). https:// doi.org/10.2118/166478-PA 149. Yuan, B., Wood, D.A.: Chapter one—overview of formation damage during improved and enhanced oil recovery. In: Yuan, B., Wood, D.A. (eds.) Form Damage Dur Improv Oil Recover, pp. 1–20. Gulf Professional Publishing, Houston (2018). https:// doi.org/10.1016/B978-0-12-813782-6.00001-4 150. Yuan, B., Wood, D.A.: A comprehensive review of formation damage during enhanced oil recovery. J. Pet. Sci. Eng. 167, 287–299 (2018). https://doi.org/10.1016/j.petrol.2018.04.018 151. Civan, F.: Chapter 1—overview of formation damage. In: Civan, F. (ed.) Reserv Form Damage, 3rd edn, pp. 1–6. Gulf Professional Publishing, Boston (2016). https://doi.org/10.1016/B978- 0-12-801898-9.00001-1 152. Dai, C.: Chapter seven—formation damage during chemical fooding. In: Yuan, B., Wood, D.A. (eds.) Form Damage Dur Improv Oil Recover, pp. 275–304. Gulf Professional Publishing, Boston (2018). https://doi.org/10.1016/B978-0-12-81378 2-6.00007-5 153. Guo, H., Li, Y., Wang, F., Yu, Z., Chen, Z., Wang, Y., et al.: ASP fooding: theory and practice progress in China. J Chem (2017). https://doi.org/10.1155/2017/8509563 200 International Nano Letters (2019) 9:171–202 1 3 154. Kalfoglou, G.: Lignosulfonates as sacrifcial agents in oil recovery processes. US Patent No. 4006779. https://www.osti.gov/ biblio/7119809 (1977) 155. Novosad, J.: Laboratory evaluation of lignosulfonates as sacrifcial adsorbates in surfactant fooding. J. Can. Pet. Technol. 23, 1–6 (1984). https://doi.org/10.2118/84-03-01 156. Algharaib, M., Alajmi, A., Gharbi, R.: Improving polymer food performance in high salinity reservoirs. J. Pet. Sci. Eng. 115, 17–23 (2014). https://doi.org/10.1016/j.petrol.2014.02.003 157. Algharaib, M.K., Abedi, M.A.: Optimization of polymer food performance by prefush injection—numerical investigation. In: SPE Kuwait Int Pet Conf Exhib 10–12 December, Kuwait City, Kuwait, pp. 1–14 (2012). https://doi.org/10.2118/163280-ms 158. Kumar, S., Saxena, N., Mandal, A.: Synthesis and evaluation of physicochemical properties of anionic polymeric surfactant derived from Jatropha oil for application in enhanced oil recovery. J. Ind. Eng. Chem. 43, 106–116 (2016). https://doi. org/10.1016/j.jiec.2016.07.055 159. Zhang, Q.-Q., Cai, B.-X., Xu, W.-J., Gang, H.-Z., Liu, J.-F., Yang, S.-Z., et al.: The rebirth of waste cooking oil to novel biobased surfactants. Sci. Rep. 5, 9971 (2015) 160. Eftekhari, A.A., Krastev, R., Farajzadeh, R.: Foam stabilized by fy ash nanoparticles for enhancing oil recovery. Ind. Eng. Chem. Res. 54, 12482–12491 (2015). https://doi.org/10.1021/ acs.iecr.5b03955 161. Ponnapati, R., Karazincir, O., Dao, E., Ng, R., Mohanty, K.K., Krishnamoorti, R.: Polymer-functionalized nanoparticles for improving waterfood sweep efciency: characterization and transport properties. Ind. Eng. Chem. Res. 50, 13030–13036 (2011). https://doi.org/10.1021/ie2019257 162. Pu, W.-F., Liu, R., Wang, K.-Y., Li, K.-X., Yan, Z.-P., Li, B., et al.: Water-soluble core-shell hyperbranched polymers for enhanced oil recovery. Ind. Eng. Chem. Res. 54, 798–807 (2015). https://doi.org/10.1021/ie5039693 163. Maurya, N.K., Kushwaha, P., Mandal, A.: Studies on interfacial and rheological properties of water soluble polymer grafted nanoparticle for application in enhanced oil recovery. J. Taiwan Inst. Chem. Eng. 70, 319–330 (2017). https://doi. org/10.1016/j.jtice.2016.10.021 164. Cheng, Y., Zhao, M., Zheng, C., Guo, S., Li, X., Zhang, Z.: Water-dispersible reactive nanosilica and poly(2-acrylamido2-methyl-1-propanesulfonic acid sodium) nanohybrid as potential oil displacement agent for enhanced oil recovery. Energy Fuels 31, 6345–6351 (2017). https://doi.org/10.1021/acs.energ yfuels.7b00743 165. Behzadi, A., Mohammadi, A.: Environmentally responsive surface-modifed silica nanoparticles for enhanced oil recovery. J Nanoparticle Res 18, 1–19 (2016). https://doi.org/10.1007/ s11051-016-3580-1 166. Liu, R., Pu, W., Sheng, J.J., Du, D.: Star-like hydrophobically associative polyacrylamide for enhanced oil recovery: comprehensive properties in harsh reservoir conditions. J. Taiwan. Inst. Chem. Eng. 80, 639–649 (2017). https://doi.org/10.1016/j. jtice.2017.08.043 167. Liu, R., Pu, W.-F., Du, D.-J.: Synthesis and characterization of core–shell associative polymer that prepared by oilfeld formation water for chemical fooding. J. Ind. Eng. Chem. 46, 80–90 (2017). https://doi.org/10.1016/j.jiec.2016.10.018 168. Ye, Z., Qin, X., Lai, N., Peng, Q., Li, X., Li, C.: Synthesis and performance of an acrylamide copolymer containing nanoSiO2 as enhanced oil recovery chemical. J Chem 2013, 1–33 (2013) 169. Yang-Chuan, K., Guang-Yao, W., Yi, W.: Preparation, morphology and properties of nanocomposites of polyacrylamide copolymers with monodisperse silica. Eur. Polym. J. 44, 2448–2457 (2008). https://doi.org/10.1016/j.eurpolymj.2008.06.007 170. Lai, N., Wu, T., Ye, Z., Zhang, Y., Zhou, N., Zeng, F.: Hybrid hyperbranched polymer based on modified nano-SiO2 for enhanced oil recovery. Chem. Lett. 45, 1189–1191 (2016). https ://doi.org/10.1246/cl.160554 171. Maghzi, A., Mohebbi, A., Kharrat, R., Ghazanfari, M.H.: Porescale monitoring of wettability alteration by silica nanoparticles during polymer fooding to heavy oil in a fve-spot glass micromodel. Transp. Porous Media 87, 653–664 (2011). https://doi. org/10.1007/s11242-010-9696-3 172. Cheraghian, G.: Efect of nano titanium dioxide on heavy oil recovery during polymer fooding. Pet. Sci. Technol. 34, 633–641 (2016). https://doi.org/10.1080/10916466.2016.1156125 173. Rezaei, A., Abdi-Khangah, M., Mohebbi, A., Tatar, A., Mohammadi, A.H.: Using surface modifed clay nanoparticles to improve rheological behavior of Hydrolyzed Polyacrylamide (HPAM) solution for enhanced oil recovery with polymer fooding. J. Mol. Liq. 222, 1148–1156 (2016). https://doi.org/10.1016/j.molli q.2016.08.004 174. Zheng, C., Cheng, Y., Wei, Q., Li, X., Zhang, Z.: Suspension of surface-modifed nano-SiO2 in partially hydrolyzed aqueous solution of polyacrylamide for enhanced oil recovery. Colloids Surf. A Physicochem. Eng. Asp 524, 169–177 (2017). https:// doi.org/10.1016/j.colsurfa.2017.04.026 175. Haeri, M.F.: Experimental evaluation of surfactant-based nanofuids on wettability alteration and oil recovery. A doctoral dissertation submitted to Craft & Hawkins Department of Petroleum Engineering, Louisiana State University (2018) 176. Zhao, M., Lv, W., Li, Y., Dai, C., Wang, X., Zhou, H., et al.: Study on the synergy between silica nanoparticles and surfactants for enhanced oil recovery during spontaneous imbibition. J. Mol. Liq. 261, 373–378 (2018). https://doi.org/10.1016/j.molli q.2018.04.034 177. Pei, H., Zhang, G., Ge, J., Zhang, J., Zhang, Q.: Investigation of synergy between nanoparticle and surfactant in stabilizing oilin-water emulsions for improved heavy oil recovery. Colloids Surf. A Physicochem. Eng. Asp 484, 478–484 (2015). https:// doi.org/10.1016/j.colsurfa.2015.08.025 178. Mobaraki, S., Zakavi, M., Mahmoodi, O., Omidvar Sorkhabadi, M., Khalilinezhad, S.S., Shiri, Torkmani R.: An experimental study on the mechanisms of enhancing oil recovery by nanoparticles-assisted surfactant food. Geosyst. Eng. (2018). https://doi. org/10.1080/12269328.2018.1515670 179. Bazazi, P., Gates, I.D., Sanati Nezhad, A., Hejazi, S.H.: Silica-based nanofluid heavy oil recovery a microfluidic approach. SPE Can. Heavy Oil Tech. Conf. (2017). https://doi. org/10.2118/185008-ms 180. Vatanparast, H., Javadi, A., Bahramian, A.: Silica nanoparticles cationic surfactants interaction in water–oil system. Colloids Surf. A Physicochem. Eng. Asp 521, 221–230 (2017). https:// doi.org/10.1016/j.colsurfa.2016.10.004 181. Pichot, R., Spyropoulos, F., Norton, I.T.: Competitive adsorption of surfactants and hydrophilic silica particles at the oil–water interface: interfacial tension and contact angle studies. J. Colloid Interface Sci. 377, 396–405 (2012). https://doi.org/10.1016/j. jcis.2012.01.065 182. Zargartalebi, M., Barati, N., Kharrat, R.: Infuences of hydrophilic and hydrophobic silica nanoparticles on anionic surfactant properties: interfacial and adsorption behaviors. J. Pet. Sci. Eng. 119, 36–43 (2014). https://doi.org/10.1016/j.petrol.2014.04.010 183. Suleimanov, B.A., Ismailov, F.S., Veliyev, E.F.: Nanofuid for enhanced oil recovery. J. Pet. Sci. Eng. 78, 431–437 (2011). https ://doi.org/10.1016/j.petrol.2011.06.014 184. Giraldo, J., Benjumea, P., Lopera, S., Cortés, F.B., Ruiz, M.A.: Wettability alteration of sandstone cores by alumina-based nanofuids. Energy Fuels 27, 3659–3665 (2013). https://doi. org/10.1021/ef4002956 International Nano Letters (2019) 9:171–202 201 1 3 185. Ahmadi, M.A., Shadizadeh, S.R.: Induced efect of adding nano silica on adsorption of a natural surfactant onto sandstone rock: experimental and theoretical study. J. Pet. Sci. Eng. 112, 239–247 (2013). https://doi.org/10.1016/j.petrol.2013.11.010 186. Mohajeri, M., Hemmati, M., Shekarabi, A.S.: An experimental study on using a nanosurfactant in an EOR process of heavy oil in a fractured micromodel. J. Pet. Sci. Eng. 126, 162–173 (2015). https://doi.org/10.1016/j.petrol.2014.11.012 187. Sharma, T., Iglauer, S., Sangwai, J.S.: Silica nanofuids in an oilfeld polymer polyacrylamide: interfacial properties, wettability alteration, and applications for chemical enhanced oil recovery. Ind. Eng. Chem. Res. 55, 12387–12397 (2016). https://doi. org/10.1021/acs.iecr.6b03299 188. Karimi, A., Fakhroueian, Z., Bahramian, A., Pour Khiabani, N., Darabad, J.B., Azin, R., et al.: Wettability alteration in carbonates using zirconium oxide nanofuids: EOR implications. Energy Fuels 26, 1028–1036 (2012). https://doi.org/10.1021/ef201475u 189. Bayat, A.E., Rajaei, K., Junin, R.: Assessing the efects of nanoparticle type and concentration on the stability of CO2 foams and the performance in enhanced oil recovery. Colloids Surf. A Physicochem. Eng. Asp 511, 222–231 (2016). https://doi. org/10.1016/j.colsurfa.2016.09.083 190. Espinoza, D.A., Caldelas, F.M., Johnston, K.P., Bryant, S.L., Huh, C.: Nanoparticle-stabilized supercritical CO2 foams for potential mobility control applications. In: Present. SPE Improv. Oil Recover. Symp. 24–28 April. Tulsa, Oklahoma, USA, Society of Petroleum Engineers, pp. 1–13 (2010). https://doi. org/10.2118/129925-ms 191. Yu, J., Liu, N., Li, L., Lee, R.L.: Generation of nanoparticle-stabilized supercritical CO2 foams. In: C. Pap. Present. Carbon Manag. Technol. Conf. 7–9 February, Orlando, Florida, USA, Orlando, Florida, USA: Carbon Management Technology Conference, pp. 1–11 (2012). https://doi.org/10.7122/150849-ms 192. Yang, W., Wang, T., Fan, Z.: Highly stable foam stabilized by alumina nanoparticles for EOR: efects of sodium cumene sulfonate and electrolyte concentrations. Energy Fuels 31, 9016–9025 (2017). https://doi.org/10.1021/acs.energyfuels.7b01248 193. Mo, D., Yu, J., Liu, N., Lee, R.L.: Study of the efect of diferent factors on nanoparticle-stabilized CO2 foam for mobility control. In: SPE Annu. Tech. Conf. Exhib. 8–10 October, San Antonio, Texas, USA, Society of Petroleum Engineers, pp. 1–11 (2012). https://doi.org/10.2118/159282-ms 194. Risal, A.R., Manan, M.A., Yekeen, N., Azli, N.B., Samin, A.M., Tan, X.K.: Experimental investigation of enhancement of carbon dioxide foam stability, pore plugging, and oil recovery in the presence of silica nanoparticles. Pet. Sci. (2018). https://doi. org/10.1007/s12182-018-0280-8 195. Yu, J., An, C., Mo, D., Liu, N., Lee, R.L.: Foam mobility control for nanoparticle-stabilized supercritical CO2 foam. In: SPE Improv. Oil Recover. Symp. 14–18 April. Tulsa, Oklahoma, USA, Tulsa, Oklahoma, USA: Society of Petroleum Engineers, pp. 1–13 (2012). https://doi.org/10.2118/153336-ms 196. Kalyanaraman, N., Arnold, C., Gupta, A., Tsau, J.S., Ghahfarokhi, R.B.: Stability improvement of CO2 foam for enhanced oil-recovery applications using polyelectrolytes and polyelectrolyte complex nanoparticles. J. Appl. Polym. Sci. 134(1–15), 44491 (2017). https ://doi.org/10.1002/app.44491 197. Aroonsri, A., Worthen, A.J., Hariz, T., Johnston, K.P., Huh, C., Bryant, S.L.: Conditions for generating nanoparticle-stabilized CO2 foams in fracture and matrix fow. In: SPE Annu. Tech. Conf. Exhib. 30 Sept. October, New Orleans, Louisiana, USA, New Orleans, Louisiana, USA: Society of Petroleum Engineers, pp. 1–19 (2013). https://doi.org/10.2118/166319-ms 198. Singh, R., Gupta, A., Mohanty, K.K., Huh, C., Lee, D., Cho, H.: Fly ash nanoparticle-stabilized CO2-in-water foams for gas mobility control applications. In: SPE Annu. Tech. Conf. Exhib. 28–30 Sept. Houston, Texas, USA, Houston, Texas, USA: Society of Petroleum Engineers, pp. 1–13 (2015). https://doi.org/10.2118/175057-ms 199. Manan, M.A., Farad, S., Piroozian, A., Esmail, M.J.A.: Efects of nanoparticle types on carbon dioxide foam fooding in enhanced oil recovery. Pet. Sci. Technol. 33, 1286–1294 (2015). https://doi. org/10.1080/10916466.2015.1057593 200. Kim, I., Worthen, A.J., Johnston, K.P., DiCarlo, D.A., Huh, C.: Size-dependent properties of silica nanoparticles for Pickering stabilization of emulsions and foams. J Nanopart. Res 18, 82 (2016). https://doi.org/10.1007/s11051-016-3395-0 201. Singh, R., Mohanty, K.K.: Foams stabilized by in-situ surface-activated nanoparticles in bulk and porous media. SPE J. 21, 121–130 (2016). https://doi.org/10.2118/170942-PA 202. Wang, S., Chen, C., Kadum, M.J., Shiau, B.-J., Harwell, J.H.: Enhancing foam stability in porous media by applying nanoparticles. J. Dispers. Sci. Technol. 39, 734–743 (2018). https://doi. org/10.1080/01932691.2017.1388175 203. Singh, R., Mohanty, K.K.: Foam fow in a layered, heterogeneous porous medium: a visualization study. Fuel 197, 58–69 (2017). https://doi.org/10.1016/j.fuel.2017.02.019 204. Yekeen, N., Manan, M.A., Idris, A.K., Samin, A.M., Risal, A.R.: Experimental investigation of minimization in surfactant adsorption and improvement in surfactant-foam stability in presence of silicon dioxide and aluminum oxide nanoparticles. J. Pet. Sci. Eng. 159, 115–134 (2017). https://doi.org/10.1016/j.petrol.2017.09.021 205. Singh, R., Mohanty, K.K.: Nanoparticle-stabilized foams for hightemperature, high-salinity oil reservoirs. In: Present. SPE Annu. Tech. Conf. Exhib. 9–11 October, San Antonio, Texas, USA, San Antonio, Texas, USA: Society of Petroleum Engineers, pp. 1–15 (2017). https://doi.org/10.2118/187165-ms 206. Esfandyari Bayat, A., Junin, R., Samsuri, A., Piroozian, A., Hokmabadi, M.: Impact of metal oxide nanoparticles on enhanced oil recovery from limestone media at several temperatures. Energy Fuels 28, 6255–6266 (2014). https://doi.org/10.1021/ef5013616 207. Shahrabadi, A., Bagherzadeh, H., Roostaie, A., Golghanddashti, H.: Experimental investigation of HLP nanofuid potential to enhance oil recovery: a mechanistic approach. In: SPE Int Oilf Nanotechnol Conf Exhib 12–14 June, Noordwijk, The Netherlands, pp. 1–9 (2012). https://doi.org/10.2118/156642-ms 208. Ehtesabi, H., Ahadian, M.M., Taghikhani, V., Ghazanfari, M.H.: Enhanced heavy oil recovery in sandstone cores using TiO2 nanofuids. Energy Fuels 28, 423–430 (2014). https://doi.org/10.1021/ ef401338c 209. Roustaei, A., Safarzadeh, S., Mohammadi, M.: An evaluation of modifed silica nanoparticles’ efciency in enhancing oil recovery of light and intermediate oil reservoirs. Egypt J. Pet. 22, 427–433 (2013). https://doi.org/10.1016/j.ejpe.2013.06.010 210. Hendraningrat, L., Torsæter, O.: Metal oxide-based nanoparticles: revealing their potential to enhance oil recovery in diferent wettability systems. Appl. Nanosci. 5, 181–199 (2015). https://doi. org/10.1007/s13204-014-0305-6 211. Zhang, H., Nikolov, A., Wasan, D.: Enhanced oil recovery (EOR) using nanoparticle dispersions: underlying mechanism and imbibition experiments. Energy Fuels 28, 3002–3009 (2014). https://doi. org/10.1021/ef500272r 212. Salem Ragab, A.M., Hannora, A.E.: A comparative investigation of nano particle efects for improved oil recovery—experimental work. In: Present. SPE Kuwait Oil Gas Show Conf. 11–14 October, Mishref, Kuwait, Society of Petroleum Engineers, pp. 1–16 (2015). https://doi.org/10.2118/175395-ms 213. Tarek, M., El-Banbi, A.H.: Comprehensive investigation of efects of nano-fuid mixtures to enhance oil recovery. In: SPE North Africa Tech. Conf. Exhib. 14–16 Sept. Cairo, Egypt, Cairo, Egypt: Society of Petroleum Engineers, pp. 1–10 (2015). https:// doi.org/10.2118/175835-ms 202 International Nano Letters (2019) 9:171–202 1 3 214. Li, S., Hendraningrat, L., Torsaeter, O.: Improved oil recovery by hydrophilic silica nanoparticles suspension: 2-phase fow experimental studies. In: Present. Int. Pet. Technol. Conf. 26–28 March, Beijing, China, International Petroleum Technology Conference, pp. 1–15 (2013). https://doi.org/10.2523/iptc-16707-ms 215. Li, S., Genys, M., Wang, K., Torsæter, O.: Experimental study of wettability alteration during nanofuid enhanced oil recovery process and its efect on oil recovery. In: Present. SPE Reserv. Characterisation Simul. Conf. Exhib. 14–16 Sept. Abu Dhabi, UAE, Society of Petroleum Engineers, pp. 1–11 (2015). https:// doi.org/10.2118/175610-ms 216. Roustaei, A., Bagherzadeh, H.: Experimental investigation of SiO2 nanoparticles on enhanced oil recovery of carbonate reservoirs. J. Pet. Explor. Prod. Technol. 5, 27–33 (2015). https://doi. org/10.1007/s13202-014-0120-3 217. Maghzi, A., Mohammadi, S., Ghazanfari, M.H., Kharrat, R., Masihi, M.: Monitoring wettability alteration by silica nanoparticles during water fooding to heavy oils in fve-spot systems: a porelevel investigation. Exp. Therm. Fluid. Sci. 40, 168–176 (2012). https://doi.org/10.1016/j.expthermfusci.2012.03.004 218. El-Diasty, A.I.: The potential of nanoparticles to improve oil recovery in Bahariya formation, Egypt: an experimental study. In: Present SPE Asia Pacifc Enhanc Oil Recover Conf 11–13 August, Kuala Lumpur, Malaysia, pp. 1–14 (2015). https://doi. org/10.2118/174599-ms 219. Johnson, K.E.: What’s an ionic liquid? Electrochem. Soc. Interface 5, 38–41 (2007) Publisher’s Note Springer Nature remains neutral with regard to jurisdictional claims in published maps and institutional afliations.

If you need answers to this assignment, WhatsApp/Text to +1 646 978 1313  

or send us an email to admin@shrewdwriters.com and we will reply instantly. We provide original answers that are not plagiarized. Please, try our service. Thanks