Enhancing oil recovery using nanoparticles—a review

Engeset (2012) describes the structural disjoining pressure as a pressure that is the outcome of two surface layers obtained from their reciprocal overlap. This happens by the summation of different forces [10]. The structural disjoining pressure reacts normally to the interface of solid-liquid and tends to arise as a result of NPs structuring in the wedge type film formed between an oil droplet and a solid surface [14].

The nanoparticles in the nanofluids have the ability to procedure a self-build wedge-shaped film when they come in contact with the phase of oil. The self-build wedge-shaped film tends to separate the droplets of oil from the surface of the rock, thus retrieves more amount of oil as compared to recovery obtained by conventional injection fluids [15].

In simple terms, nanofluids that are injected into the formation apply a pressure on NPs forcing them to acquire a confined space, as a result they arrange themselves in well-ordered layers like a wedge film. This arrangement of NPs applies additional disjoining pressure at the interface of nanofluids and oil phase, hence retrieves a large quantity of oil [16].

McElfresh (2012) explained this mechanism as Brownian motion and electrostatic repulsion between the NPs. The force of electrostatic repulsion will be greater when size of NPs will be smaller. When quantity of the NPs increase, the force of electrostatic repulsion will also increase. The force generated by a single nanoparticle is very low, but when a large number of small NPs are present, the produced force can be above 50,000 psi at the vertex [17].

The main mechanisms that affect the propagation of NPs in porous medium are: (1) physical filtration, (2) solution chemical stability, and (3) adsorption on the surface of the rock.

It has been observed when NPs are larger in size as compared to the size of pore, this situation will cause physical filtration. This mechanism may even happen for well-dispersed NPs, when injecting in low-permeability rocks, for instance; tight sandstones. Solution chemical stability, refers to the solubility and dispersibility of NPs. High salinity causes poor stability of the chemicals which can lead to the precipitation of NPs. Third mechanism, adsorption onto solid surfaces, may hinder the transportation of NPs from porous medium. Low adsorption on rock may improve the economics of the oil recovery process. Experiments have showed that coatings of polymers can help to stabilize NPs in solution but may cause high adsorption and retardation of nanoparticles in the porous medium [1].

As the nanofluids enter the porous media, different mechanisms may decrease the concentration of NPs. The main cause is pore channel plugging. Pore channels can be plugged or blocked either by; mechanical entrapment or log-jamming.

Mechanical entrapment is caused when size of injected NP is larger as compared to pore throat size through which it will pass. Usually, size of pore throats is in microscale, which means they are thousand times greater in size than NPs. Thus, NPs are easily capable to pass through the pore throats without any mechanical entrapment. Though, it is reported that some metal type NPs may block pore throat because of their large size [18]. This mechanism is also called straining. To avoid this, the size of NPs should be smaller than the size of pore throats [19].

Log-jamming is caused in a very small pore throat, where the difference of density between NPs and the water hinders the NPs movement, hence causing them to accumulate; as a result pore diameter will reduce and finally blockage will occur. Due to this blockage, pressure increases in the adjacent pores which forces the oil to flow out of pore. Once the oil is released, pressure drops in the surroundings, blockage caused by NPs is slowly dissolved and they tends to flow with the flowing water. This mechanism can be termed as temporary log-jamming. This mechanism majorly depends on size of pore throats, quantity and size of NPs in nanofluids and flow rate [19].

Alberto et al used polymer-coated silica nanoparticles with injecting seawater for enhancing the oil recovery process. Results of permeability measurements showed very small retention by particle within the core. In addition a consistent low differential pressure was also witnessed throughout the flooding process of nanofluids [14].

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Among other parameters, interfacial tension is one that defines distribution and movement of fluid in a porous medium. Thus, it is very essential to investigate the interfacial tension between oil and injected fluids for the application of enhanced oil recovery technique [16]. Interfacial tension can be best defined as a surface free energy that appears between two non-mixable liquids. Generally, surfactants are utilised to reduce the IFT and to attain a higher capillary number [20]. The nanofluid flooding has shown reduction in IFT, increased viscosity of the displacement fluid and alteration in the rock wettability. All these factors contribute to impacting capillary number and as a result recovery of crude oil is increased. Since this process requires large concentration on NPs, for this reason Giraldo et al developed NiO-containing Janus nanoparticles based on zero-dimension (0D) SiO₂ nanoparticles which can be effective at low concentrations. The obtained results indicated a sudden increase of capillary number at a very low concentration of 100 mg l⁻¹ of Janus nanoparticles. It was presented that up to 50% increase in oil recovery was observed [21].

Pendant drop method is generally used to determine interfacial tension between oil and nanofluids. In this method, a droplet of oil is introduced into a nanofluid from a capillary needle. The value of interfacial tension is measured by examining the shape of the oil droplet through a perfect video system and an analysing software [16].

Rostami et al stated that use of brine with low salt concentration may result in greater recovery of oil as compared to brines with high salt concentration. In an oil reservoir, capillary forces depend on numerous factors, for instance size and geometry of pore, reservoir wetting characteristics, surface and IFT of the rock and fluids. Many studies have discovered a lower salinity threshold to an increased recovery of oil [22].

Lan et al examined the influence of silicon oxide nanoparticle and cationic surfactant on interfacial tension. The cationic surfactant has the ability to change the surface of the nanoparticles from fully hydrophilic to partially hydrophobic, which tends to aggregate the NPs, hence lowers the interfacial tension [23]. Adel et al conducted their study at ambient pressure and temperature to compare the effects of SiO₂ and Al₂O₃ nanofluids on interfacial tension. The findings of their study concluded that interfacial tension noticeably declined when any of these NPs was added into a solution of brine. The nanofluid composed of SiO₂ had a lower value of interfacial tension as compared to Al₂O₃ nanofluid. Thus, SiO₂ NP has more potential to recover oil from a reservoir [24].

A few studies have reported the use of NPs for improving the surfactant flooding. Laboratory experiments have proved the use of nanoparticles and surfactant in improving the oil recovery. The addition of the nanoparticles into surfactant flooding can be incorporated by two methods: (A) by the preparation of nanofluids, in which nanoparticles are added in a surfactant-containing solution and, (B) attachment of the surfactant over the surface of nanoparticles by chemical process. However, in both methods the main purpose is the reduction of the surfactant adsorption. Wu et al evaluated the effect of the silica NPs on the surfactant adsorption onto the porous media and suggested an inhibition mechanism [25].

Wu et al showed that the surfactant molecules that are adsorbed onto surface of silica NPs, reduced the adsorption of surfactant onto the rock; as a result oil recovery was improved. Stefania et al reported that in the absence of surfactant, IFT between crude oil and brine produced no significant changes as a result of paraffinic content of the crude oil. The combined use of surfactant and SiO₂ NPs did not show any major effect on reducing the IFT between crude oil and brine. On the contrary, the NPs-surfactant flooding increased the recovery of oil up to 240% as compared to surfactant flooding. The results generated were linked to the ability of NPs for inhibiting the surfactant adsorption onto the rock surface [26].

In another study, Esmaeilzadeh et al investigated the effect of ZrO₂ NP on interfacial properties of anionic surfactant. It was found that ZrO₂ NP increases the surface activity of the anionic surfactant and tends to lower the interfacial tension between water and oil [27]. Similarly, Alomair et al compared three NPs (Al₂O₃, SiO₂ and NiO) to find their ability of interfacial tension reduction. They concluded that SiO₂ had a lowest value of interfacial tension and NiO NP had the lowest reduction on interfacial tension [28].

Olayiwola et al proposed a mathematical model that was capable to define the changes in surface tension of different sized NPs when dispersed in deionised water. This consists of the structural effect of nanoparticles and the dipole-dipole interaction to produce a mathematical model that can define the surface tension of NPs in brine [29]. However, the behaviour of nanoparticles in brine solution is different from that of mixture of different electrolytes. In deionised water, fluid's surface tension tends to increase with an increase in the quantity of NPs, but in electrolyte solution NPs behave as surface active agent; as a result decrease in the surface tension was observed as their concentration increases [30]. The use of surfactant not only improves the stability of nanoparticles in solution but also helps to reduce the IFT. This is because of the effective charges of the ions of NPs and surfactant [31].

Wettability can be explained as the attraction of solid surface towards a particular liquid to occupy the pore when other immiscible liquids are also present [19]. Depending on the wettability, reservoirs can be categorised as oil-wet, water-wet, or mixed-wet as shown in figure 2. Generally, water-wet reservoirs give high oil recoveries while; recovery from oil-wet reservoirs is low, changing the wettability of a reservoir from oil-wet to water-water in order to get high recoveries is termed as wettability alteration [32]. The contact angle measurement method, the Amott test and the core displacement test are the methods used by researchers to determine wettability, among these methods, the contact angle measurement is a most commonly used method [33].

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Many researchers, either by using the NPs alone or combinedly with surfactants have reported the results on the wettability alteration. They concluded that the alteration of wettability using nanoparticles relies on many factors such as nature of nanoparticles and reservoir, hydrophobicity and concentration of NPs in nanofluids [19].

Hendraningrat, et al studied the impact of Al₂O₃ nanoparticle on wettability alteration. The study was conducted using sandstone cores. It was found that nanofluids containing Al₂O₃ NP can change the wettability from a strongly oil-wet condition to a strongly water-wet condition [34]. In another study, Li et al measured the wettability index using Amott tests and concluded that SiO₂ nanofluids changed the wettability of sandstone cores from oil-wet to neutral wet [35]. Then, Roustaei and Bagherzadeh examined the influence of SiO₂ NPs on carbonate rock. Also in this study, the obtained results showed that SiO₂ nanofluid can change the wettability of carbonate rock [36].

Mahdi et al concluded that nano-biomaterials can change the wettability of shale rock from oil-wet to water-wet by the use of nanoparticle and biomaterials, simultaneously [37]. Maghzi et al studied the influence of SiO₂ NPs on fluid distribution on pore walls and noticed the capability of this NP to change the wettability of pores surfaces [38]. Roustaei et al investigated the modified SiO₂ NP. The study was conducted using both light and heavy oil. It was found that modified SiO₂ NP can effectively change the wettability of light oil reservoir [39].

Silica, also known as silicon dioxide, is abundantly found in nature as sand or quartz. It is a composite of silicon and oxygen and has a chemical formula SiO₂. The surfaces of SiO₂ NPs have the ability to become non-polar when treated with alcohols, alkoxysilanes, etc. This treatment of the NPs is beneficial, if it is being dispersed in non-alcoholic solvents [40].

Silica NPs are used by many industries especially in the formulation of different items such as humidity sensors, thermal insulators, electrical insulators, etc [41]. Studies conducted on SiO₂ proved it as a suitable EOR agent. It also has a good thermal stability which can tolerate temperatures up to 650 °C [42].

E. Rodriguez Pin et al examined the transportability of silica nanoparticles in limestones and sandstone cores. Limestone cores had permeability 10–15 mD and sandstone cores had 421–921 mD. The size of NPs selected for core flood experiment was 5 and 20 nm, with 5 and 18.65% wt suspensions. Surface-treated silica NPs can move through reservoir rocks of different permeabilities [43]. Nhu et al investigated the application of synergistic blends of SiO₂ NPs with surfactants in sandstone reservoirs for enhanced oil recovery. They experiments were performed at high temperature and high brine hardness. By utilizing various types of anionic surfactants with SiO₂ NPs, they concluded that SiO₂ NPs have a high potential for enhancing the oil recovery as they have ability to resist the adsorption on the surface of rock. In addition, SiO₂ NPs are thermally stable [44]. Laboratory experiments of low molecular weight HPAM solutions combined with silica NPs showed decline in chemical and thermal degradation of the polymer solutions. This combination also provided stability to rheological parameters even at high temperature. In addition, viscosity of HPAM solution was also observed to increase. Sangwai conducted an experiment to determine the effect of silica NPs in polymer and polymer/surfactant systems. It was observed that addition of silica NPs up to 10,000 mg l⁻¹ will result in increased viscosity at high temperatures. Recovery factor for polymer/ surfactant system compared to the polymer system was also increased as a result of change of wettability to a strong water-wet system [45]. Table 1. shows the results of silica NPs in terms of oil recovery percentage and recovery mechanisms.

Aluminum oxide or alumina refers to corundum. It has a general formula Al₂O_3. Laser ablation technique is used for the synthesis of alumina NPs. Al₂O₃ has different phases such as gamma, delta, theta, and alpha. The alpha phase of aluminum oxide is the most thermodynamically stable phase [46].

Ali et al (2014) investigated the effects of aluminum oxide, titanium dioxide, and silicon dioxide for their application in enhanced oil recovery at various temperatures. They used intermediate-wet limestone core samples. They concluded for limestone porous media at all the experimental temperatures, Al₂O₃ is the best nanoparticle for the application in enhanced oil recovery as compared to SiO₂ and TiO₂ [47]. Another study, conducted by Hasnah et al (2014) investigated the effects of change of morphology of Al₂O₃ NPs. For this, they treated Al₂O₃ NPs with 10 M NaOH and 1M of NaOH. They reported by comparing the results of core flooding experiments that the highest oil recovery was achieved by nanofluid containing Al₂O₃ NPs treated with 10 M NaOH. Oil recovery was 26.20% greater as compared to Al₂O₃ NPs treated with 1M NaOH. Thus they concluded that, the morphology of Al₂O₃ NPs also effect the recovery of oil [48]. Further, Ogolo et al in his study clarified that Al₂O₃ NPs have the ability to reduce oil viscosity and the interfacial tension between oil and brine. Especially, when brine is the dispersion medium for Al₂O₃ NPs [9]. An analysis of oil recoveries achieved using alumina NPs is shown in table 2.

Iron oxide has a general formula Fe₂O₃, is a mineral compound which is found abundantly in nature. This NP has many crystal structures and various structural and magnetic properties. The three main forms of Fe₂O₃ are hematite, magnetite and maghemite [49].

E. Joonaki and S. Ghanaatiana (2014) investigated the application of Fe₂O₃ NP in EOR application and reported in sandstone porous media, this NP increased the oil recovery by 17.3% [50]. Guan et al (2014) also studied the use of Fe₂O₃ NP in EOR, they concluded that Fe₂O₃ NP prepared at 300 °C provided 10% increase in the oil recovery as compared to Fe₂O₃ NP prepared at 600 °C [51]. Ogolo et al concluded through his experimental work that Fe₂O₃ NP enhances the oil recovery through sandstone reservoirs, when the dispersion medium is brine [9]. Table 3. shows the results of iron oxide NPs in terms of oil recovery percentage and recovery mechanisms.

Titanium dioxide has a general formula TiO₂. TiO₂ has its place in the family of transition metal oxides. TiO₂ in the form of NPs is much more effective than in bulk powder. It is most widely used in the treatment of wastewater, hydrophilic coatings, pesticide degradation, hydrogen fuel production, etc [52].

Ehtesabi et al indicated in their research paper that TiO₂ NPs have the ability to retrieve about 80% of the oil from oil-wet Berea sandstone in an enhanced oil recovery project. They further described that the recovered amount of oil was only 49% in the absence of TiO₂ NPs [53]. Another study conducted by Cheraghian (2016) revealed the effect of TiO₂ NPs on polymer flooding for the recovery of heavy oil through sandstone core. The partly hydrolysed polyacrylamide (HPAM) polymer was used in combination with TiO₂ NPs. It was concluded that overall recovery of oil was enhanced by 3.9% by the use of nano-polymer flooding as compared to simple polymer flooding [54]. Table 4. shows the results of silica NPs in terms of oil recovery percentage and recovery mechanisms.