1 Introduction

Despite advances with different enhanced oil recovery (EOR) methods, it is well understood that a great amount of petroleum remains unrecovered in underground reservoirs (Bera and Belhaj 2016). With the advent of nanoscience and emergence of its potential, researchers have investigated the applicability of nanoparticles in the upstream petroleum industry (Barati-Harooni et al. 2016; Emadi et al. 2017; Rezaei et al. 2016). Recent studies have pointed out advantages of utilizing nanofluids as EOR agents, which have not been considered enough (Fletcher and Davis 2010; Rezvani et al. 2017). Generally, the underlying mechanisms of improving oil recovery by injecting nanoparticles fall into six categories, including: (1) establishing disjoining pressure to aid detachment of oil drops from the pore surface (Chengara et al. 2004; Mcelfresh et al. 2012; Wasan et al. 2011), (2) plugging pore channels (Hashemi et al. 2013; Idogun et al. 2016; Sun et al. 2017; Zamani et al. 2012), (3) enhancing sweep efficiency by decreasing the mobility of the displacing fluid (Al-Anssari et al. 2016; Salem Ragab and Hannora 2015; Tarek and El-Banbi 2015), (4) altering rock wettability toward water-wet conditions (Hendraningrat and Torsæter 2014a; Hendraningrat and Torsaeter 2014b; Karimi et al. 2012; Li et al. 2015; Mohebbifar et al. 2015), (5) reducing interfacial tension (IFT) between residual oil and injecting fluids (Alomair et al. 2014; Hendraningrat et al. 2013a; Salem Ragab and Hannora 2015; Torsater et al. 2012) and (6) preventing/retarding asphaltene precipitation by the action of nanoparticles (Haindade et al. 2012; Kazemzadeh et al. 2015; Nassar et al. 2012; Tarboush and Husein 2012).

Among various EOR methods, low-salinity water (LSW) flooding has greatly attracted the notice of petroleum researchers partly due to availability of vast natural water resources and also being an environmental-friendly approach (Sheng 2014). Numerous experimental studies have indicated unexpected capabilities of LSW for improving oil recovery in comparison with conventional flooding of untreated, high-salinity formation water (FW) (Aghaeifar et al. 2015; Morrow and Buckley 2011; Morrow et al. 1998; Rivet et al. 2010; Tang and Morrow 1997, 1999b, c, 2002). Currently, researchers have unanimously regarded wettability alteration as the main reason for applying LSW to bring about additional oil recovery (Jalili and Tabrizy 2014; Kafili Kasmaei and Rao 2015; Mahani et al. 2015; Shabib-Asl et al. 2014; Shaddel et al. 2014; Yang et al. 2015). In this respect, various mechanisms have been proposed to explain the low-salinity effect (LSE) as follows: (1) osmotic pressure (Buckley and Morrow 2010), (2) IFT reduction in response to an increase in reservoir fluid pH (McGuire et al. 2005), (3) multicomponent ion exchange (MIE) (Lager et al. 2008), (4) double-layer expansion (Ligthelm et al. 2009), (5) dissolution of heavy oil components by the salting in effect (RezaeiDoust et al. 2009), (6) saponification (McGuire et al. 2005) and (7) elasticity of water films lying on pore walls (Buckley and Morrow 2010). While wettability alternation is considered as the main mechanism behind LSE, the understanding of which factors control the wettability variation is incomplete due to the complexity of the interactions occurring in the oil/brine/rock system. The two approaches that reveal the controlling factors behind the wettability alteration are (a) double-layer expansion between fine particles and limited fines release (LFR) between oil/rock contact areas (Nasralla and Nasr-El-Din 2014; Tang and Morrow 1999a; Xie et al. 2016) and (b) surface complexation modeling (Brady and Krumhansl 2012; Brady and Thyne 2016; Brady et al. 2015; Mahani et al. 2017; Xie et al. 2017).

To evaluate the potential of nanoparticles as novel EOR agents, some studies have been performed on silica (SiO2) nanoparticles dispersed in deionized water using a glass micromodel as a synthetic porous media (El-Diasty 2015; Gharibshahi et al. 2015; Heydarian et al. 2012; Li et al. 2016; Maghzi et al. 2012; Mohammadi et al. 2012; Ragab and Hannora 2015; Salem Ragab and Hannora 2015). Likewise, many others have investigated LSE in the micromodel (Bondino et al. 2013; Emadi and Sohrabi 2012, 2013; Fredriksen et al. 2016; Maaref et al. 2017; Song and Kovscek 2015; Wei et al. 2017). In light of those studies, one could conceive the question of how much would the benefit be of utilizing LSW augmented by nanoparticles? Naturally, exploiting simultaneous advantages of nanotechnology and LSW may bring about a higher improvement in oil recovery. To the best of our knowledge, few studies have investigated the effect of silica nanoparticles dispersed in brine for oil displacement in porous media. Among them, Torsater et al. (2012) observed an 8% incremental oil recovery by injecting SiO2 nanofluids after water flooding into an oil-saturated sandstone core. In another work, Parvazdavani et al. (2012) made an effort to probe the relative permeability of displacing/displaced fluids by means of injecting plain water or a 1 wt% SiO2 nanofluid prepared with brine into an oil-saturated sandstone core. They obtained relative permeability curves for flowing phases (oil and nanofluid) and pointed out higher oil relative permeability while using silica nanoparticles. Also, by measuring interfacial tension (IFT) of water/oil and oil/nanofluid systems, they ascribed higher oil relative permeability to the IFT reduction which took place during nanofluid injection.

Li et al. used 3 wt% brine thickened by SiO2 nanoparticles (0.01 wt%, 0.05 wt% and 0.1 wt%) for displacing residual oil in a micromodel and a sandstone core. They observed that using nanoparticles had reduced the IFT while contacting the oil phase and shifted the wettability of porous media surfaces toward water wetness. Moreover, they obtained an ~ 5% incremental oil recovery by displacing in situ oil by the nanofluid in comparison with secondary mode water flooding (Li et al. 2013). In a later study, they utilized more concentrated fluids (0.05 wt%, 0.1 wt% and 0.5 wt% SiO2 nanoparticle) and again observed a tendency of the oil-wet micromodel surface to shift toward water wetness once it contacted the silica nanofluid. In this fashion, there was a direct proportionality between the degree of wettability alteration and the concentration of nanoparticles (Li and Torsæter 2014). In a further step, Li et al. (2015) scrutinized the degree of wettability alteration by performing imbibition tests on sandstone plugs with brine (3 wt% NaCl) containing dispersed SiO2 nanoparticles, and pointed out a strong tendency of nanofluid to be imbibed into the oil-saturated plug.

To evaluate the capability of nanofluids for mobilizing oil trapped in tortuous pores, Aurand et al. (2014) carried out core flood experiments by injecting North Sea brine having 0.05 wt% SiO2 nanoparticles and observed 20% incremental recovery after flushing the core plug with plain water. Analogously, Alomair et al. observed the effect of SiO2 nanoparticles on the incremental oil recovered through tertiary mode injection, i.e., when water flooding cannot sweep residual oil. In this way, they observed a maximum recovery (~ 6%) at 0.01 wt% of nanoparticles. However, severe pore plugging occurred as a result of nanofluid instability and subsequent deposition at higher SiO2 concentrations (Alomair et al. 2014). In a similar study, Hendraningrat et al. (2013b) proceeded with using silica nanofluids for flooding oil-saturated sandstone cores and demonstrated the importance of the nanoparticle concentration, where the maximum incremental oil recovery (25%) occurred at 0.05 wt% nanofluid. Later, they investigated the effect of nanoparticle diameter (7, 16 and 40 nm) and pointed out that the highest oil recovery was achieved using the smallest nanoparticles (Hendraningrat et al. 2013c).

Based on the aforementioned studies, silica nanoparticles form an effective agent to be employed for EOR. However, it should be emphasized that most of the previous works have only used sodium chloride (NaCl) for brine preparation and the impact of other ions has been neglected (Hendraningrat et al. 2013b; Li et al. 2013; Li and Torsæter 2014; Torsater et al. 2012) and most of them used high-salinity brine to disperse nanoparticles (Aurand et al. 2014; Hendraningrat et al. 2013b, c; Li and Torsæter 2014; Li et al. 2013). Also, only Li and co-workers carried out a thorough investigation on SiO2 nanofluids using a micromodel as the porous substrate (Li et al. 2013; Li and Torsæter 2014). Therefore, there is a lack of understanding of the extend of oil recovery using SiO2 as an additive to LSW.

In this study, performance of silica nanoparticles dispersed in low-salinity water was investigated in terms of wettability modification, quantified by contact angle measurements and displacement efficiency with injection into a glass micromodel. For this purpose, we used diluted samples of synthetic Persian Gulf seawater for injection. The core of our experiments includes: examining the stability of SiO2 in LSW, contact angle measurements at varying concentrations and temperatures, and finally, evaluating oil displacement efficiency of low-salinity nanofluids by injecting them into glass micromodels.

2 Experimental

2.1 Materials

The oil used in this study with a specific gravity of 33°API was taken from a field in southwest Iran. Silica nanoparticles with 98% purity, 20 nm in diameter and a specific surface area of 20 m2/g were purchased from Merck (Germany). Ultra-deionized water of conductivity 0.2 µS/cm was used to prepare nanofluids containing varying concentrations of salts and nanoparticles. In this research, the base brine (synthetic Persian Gulf seawater) was prepared by dissolving different salts (NaCl, KCl, CaCl2, Na2SO4, MgCl2·6H2O and NaHCO3). They were all purchased from Merck. Hexamethyldisilane, Si2(CH3)6, was used for turning the original wettability of the micromodels from strongly water wet to oil wet. Also, methanol (CH3OH) and toluene (C7H8), both of 99% purity, were used as washing and wettability-altering agents, respectively. In this research, the seawater (SW) was synthesized with the same composition as the Persian Gulf seawater. The salts used and ions and their concentrations are presented in Table 1. Also, the physical properties of the crude oil are listed in Table 2.

Table 1 Composition of the synthetic Persian Gulf seawater
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Table 2 Crude oil characterization
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2.2 Apparatus

2.2.1 Sessile drop

The most popular method for determining contact angles with sessile drops is the goniometric technique that was used in this work. The images which were taken by a camera (3CCD Color Sony DXC-C33P Video Camera PAL) were analyzed by image processing software, to record contact angles accurately. A schematic of contact angle measurement using the sessile drop method is depicted in Fig. 1.

Fig. 1
figure 1

Sessile drop apparatus for measuring contact angles

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2.2.2 Micromodel

For visual inspection of oil displacement processes, a microfluidic device (micromodel) was utilized, which is a two-dimensional glass sheet with narrow conduits (pores) etched on its surface. This transparent device represents the pore structure of sandstone. It consists of a 6 × 6 cm2 matrix and etch depth of 6 µm, corresponding to a porous media having 38% porosity and 0.22 cm3 pore volume (PV). With the aid of a photolithography technique, first the underlying pattern of the porous medium was etched on a silicon wafer to achieve a homogenous pattern with coordination number of 4, which means every pore body is connected to 4 neighboring pores on average. This standard pattern has typically been employed in previous work (Wu et al. 2016a, b; Wang et al. 2014; Kazempour et al. 2014). It was polished to obtain a smooth pattern by removing any unwanted residues. Afterward, two holes were drilled at two opposite corners of the glass plane to provide input and output conduits of the porous medium for fluid injection and production, respectively, as depicted in Fig. 2. Contrary to most conventional micromodels, our model permits investigating sweeping performance by imitating a five-spot injection pattern adopted in most classical EOR studies (Sheng 2010; Green and Willhite 1998). This structure was chosen to allow observation of the fluid front to obtain insight into the effect of viscosity on the displacement process.

Fig. 2
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A schematic of the pore network structure of the micromodel. Inset shows a magnified image of etched pores

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Once the etched glass was prepared, it was bonded to a flat piece of glass and put in a furnace and fused at 700 °C. At high temperature, the glass plates stick to each other to make a unified piece, having only the etched pattern and the drilled holes open for flow. Also, exposing the glass surface to oxygen at a high temperature generates a layer of silica (SiO2), which constitutes the main part of natural sandstones. With this, one could obtain a strongly water-wet substrate similar to intact underground quartz minerals. Table 3 summarizes the main characteristics of the micromodel used in this work.

Table 3 Characteristics of the glass micromodel used as a porous medium
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3 Experimental

3.1 Design of experiments

In this research, contact angle measurements were conducted for different salinity fluids with varying ionic strengths and nanoparticle concentrations.

The different salinity nanofluids were prepared with 2, 5, 10, 20 and 100 times diluted seawater (named 2-TDSW, 5-TDSW, 10-TDSW, 20-TDSW and 100-TDSW). To account for both parameters simultaneously and reducing the number of trials, nanofluids were prepared according to the values specified in Table 4. SW was diluted up to 100 times of the original composition [the extreme case of dilution reported in previous work (Fjelde et al. 2012)] with a maximum of 1 wt% dispersed SiO2 nanoparticles (the extreme case of SiO2 nanoparticle concentration reported in most previous works).

Table 4 Fluids prepared with synthetic seawater
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3.2 Preparation of nanofluid

Two fluids, with and without nanoparticles, were used in contact angle and injection experiments. The nanofluids were prepared by adding nanoparticles to brines with different salinity, which were obtained from dilution of SW, and then homogenized by a magnetic stirrer at 400 rpm for 30 min. In the next step, the nanofluids were sonicated using an ELMA Elmasonic 1.5-Gal Tabletop Ultrasonic Cleaner, P60H, for 30 min to ensure complete dispersion of nanoparticles.

3.3 Preparation of the oil-wet micromodel

The following steps were taken to alter the wettability of the micromodel toward oil wetness:

  1. (a)

    The micromodel was rinsed with a sodium hydroxide (NaOH) solution and soaked in it for 1 h.

  2. (b)

    The micromodel was then rinsed with deionized water and dried in an oven for at least 15 min at 200 °C to ensure no residue remained on its surface.

  3. (c)

    The micromodel was soaked in a solution of 2% hexamethyldisilane and 98% anhydrous toluene for 5 min. At the end, a thin hydrophobic layer repelling water droplets was observed covering the glass surface.

  4. (d)

    Lastly, the micromodel was rinsed with methanol in order to purge any excess silicon fluid and then was dried in an oven at 100 °C to strengthen the adsorbed silicon layer.

3.4 Contact angle measurement

At first, square glass slabs (1.5 × 1.5 cm2) were cut and submerged in toluene to remove any undesirable adsorbed oleic components. Afterward, the contact angle of a water drop was measured on the glass surfaces to ensure they were initially in a strongly water-wet state. The slab wettability was then changed to an oil-wet state following the procedure detailed below. Once oil-wet slabs were obtained, they were immersed in the nanofluid, comprised of diluted brine and nanoparticles, in an attempt to restore their original water wetness. This latter process was repeated at varying concentrations of nanoparticles and brine salinity to evaluate wettability by contact angle measurement. For this purpose, the sessile drop method was applied, where a drop of n-heptane (representing the oleic phase) was injected into a cell, full of deionized water, at constant temperature (25 °C). Naturally, the drop moves upward driven by buoyancy force and touches the glass slab, as shown in Fig. 1. A high-resolution camera and a microscope captured pictures of the drop on the glass slab in three modes, namely initial, original oil-wet and modified wettability states. The error of measured contact angles is \(\pm \; 5^\circ\), and error bars are shown in the following figures. In this work, each contact angle was measured three times and the average has been reported.

3.5 Micromodel flooding

Before proceeding to this stage, the stability of nanofluids was confirmed at different nanoparticle concentrations to avoid any unwanted precipitation or pore plugging by nanoparticle deposition. To this end, all fluids were checked visually to be sufficiently transparent.

Flooding processes were conducted under ambient conditions (25 °C and 1 atm), and the micromodel was mounted horizontally to exclude any effect of gravity. Figure 3 shows the schematic of the flooding setup consisting of the micromodel (detailed earlier), a syringe pump (Harvard Apparatus, Holliston, MA) and a high-resolution camera (Canon VIXIA HF S200 HD Camcorder). The flooding procedure could be summarized as follows:

Fig. 3
figure 3

Schematic of the flooding setup

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  1. (a)

    Initially, the pores of the micromodel were preflushed with toluene to ensure that no oil was left in the micromodel.

  2. (b)

    The micromodel was evacuated to remove any possible trapped solvents, fluids or air.

  3. (c)

    To achieve a fully oil-saturated model, the syringe pump injected oil into the pores at a rate of 0.05 mL/h.

  4. (d)

    After saturating the micromodel, the nanofluid was injected at a rate of 0.05 mL/h to push the oil out of the model. This was performed using the syringe pump. At the same time, a camera placed above the micromodel took images at 2-minute intervals to monitor fluid front advancement in the porous media and also to allow a later oil recovery calculation.

  5. (e)

    Eventually, the images were analyzed by image processing software, to obtain the amount of oil recovery by counting pixels of the image representing oil spots in the model.

3.6 Turning micromodel wettability to oil wetness

The micromodel was placed in a 1:1 methanol/toluene volumetric mixture to ensure having an entirely clean surface, without any attached organic impurities. To verify the water-wet state of the glass surfaces, the contact angle of an n-heptane drop in deionized water was measured on those surfaces, as shown in Fig. 4.

Fig. 4
figure 4

n-Heptane droplet contacting the water-wet glass surface

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Once clean glass surfaces were prepared, they were immersed in an oleic mixture (2% hexamethyldisilane and 98% toluene) for 30 min, to make them oil-wet surfaces. Subsequently, they were dried for 2 h in an oven at 80 °C. Afterward, those surfaces were drenched in synthetic formation water with a salinity of 180,000 ppm NaCl and then were placed in crude oil for 12 h at 80 °C. Once again, samples were rinsed with toluene and dried at 80 °C. Eventually, the oil-wet tendency of the treated surfaces was probed by measuring the contact angle by a heptane droplet in deionized water. Through this soaking/drying procedure, one could obtain oil-wet slabs representing wetting characteristics of real reservoir conditions. Although using hexamethyldisilane is a common practice for making glass surfaces oil wet, we also made use of crude oil to heighten accuracy of the treatment and as shown in Fig. 5, the glass surfaces became completely oil wet. This procedure was done by aging oil-wet slabs in crude oil at ambient conditions (25 °C and 1 atm) for 48 h; and then the slabs were washed with toluene to remove extra oil from them to prepare for contact angle measuring tests. The contact angles for all slabs were measured after the aging time showing a complete oil-wet condition (~ 180°).

Fig. 5
figure 5

n-Heptane droplet contacting the oil-wet glass surface

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4 Results and discussion

In this section, we discuss the results of oil–water contact angle measurements, stability of nanofluids and oil recovery during injection of the nanofluids at varying salinities.

4.1 Nanofluid stability

Turbidity is a measure of assessing stability of suspensions over time. In this method, the reflection of a light beam shone through fluid records its stability and is recorded in nephelometric turbidity units (NTU). The stability curve of 20-TDSW containing varying concentrations of nanoparticles is shown in Fig. 6. The sample stability is related to nanoparticle concentrations, where diluted ones show constant NTU versus time. Noteworthy, all samples showed good stability in the first 72 h, ensuring that wettability and flooding experiments have been performed with stable fluids. Based on similar measurements, the turbidity of the samples of silica nanoparticles dispersed in deionized water (salinity 0) with different concentrations (0.10, 0.25, 0.50, 0.75, 1.00 and 2.00 wt%) remained approximately constant after 200 h. The results are presented in Table 5.

Fig. 6
figure 6

Turbidity of low-salinity nanofluids at varying concentrations of nanoparticles dispersed in 20-TDSW

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Table 5 Turbidity (in NTU) of the samples of silica nanoparticles dispersed in deionized water at different concentrations
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4.2 The effect of nanoparticle concentration in deionized water (salinity 0) on wettability of treated glass surfaces

The effect of nanofluids on the wettability of treated (oil-wet) glass surfaces was investigated at varying nanoparticle concentrations after 3 days of soaking at the ambient temperature (25 °C). In this section, the nanofluids used were prepared by dispersing nanoparticles in deionized water, i.e., the salinity of these nanofluids was zero. As shown in Fig. 7, the contact angle was nearly constant (~ 160°) up to 0.75 wt% nanoparticle concentration. However, a dramatic reduction occurred at higher nanoparticle concentrations, reflecting an abrupt change in the glass surface wettability toward water wetness. Increasing the concentration of silica nanoparticles above a threshold value, somewhere between 0.75 wt% and 1.00 wt%, brought about a large shift of the oil-wet glass surface to a practically water-wet state, with a contact angle of ~ 60°. On the other hand, the wettability remains almost constant with a further increase in the nanoparticle concentration in the soaking fluid, up to 2.00 wt%, as shown in Fig. 7. The interesting steplike diagram of Fig. 7 suggests that nanofluids used in this study would be effective once the nanoparticle concentrations were greater than a critical value, that is, 0.75 wt% in the conditions prevailing for this study. Besides undesirable instability of the solution, as shown in Fig. 6, using highly concentrated nanofluid has no appreciable influence on altering wettability toward the favorable state, which imposes a major economical constriction on their applicability.

Fig. 7
figure 7

Effect of nanoparticle concentrations on the contact angle of n-heptane droplet on the glass surface (nanofluids prepared with deionized water)

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At this point, one question arises. What is the mechanism underlying this peculiar observation? Previous studies have confirmed that coating glass or rock surfaces with nanoparticles alter their wettability. However, based on our observation, one cannot attribute wettability alteration solely to adsorption of nanoparticles on glass surfaces. The structural disjoining pressure is the plausible mechanism behind the observed phenomenon. In this mechanism, negatively charged nanoparticles diffuse around oil droplets lodged on the glass surface. Recalling that the water–oil interface beneath the oil droplet is of negative charge, except at the high pH and ionic strength relevant to the formation brines (Jackson et al. 2016) and/or in highly acidic crude oil (Buckley 1999), as a result, repulsion between the interfaces leads to detachment of oil droplets from the surface by nanoparticles, and consequently, wettability changes the glass surface from oil wet toward water wet.

To provide an insight into effect of the soaking period on wettability alteration, the experiment was conducted again in 6 days. As shown in Fig. 8, there is no difference between the trend of the earlier test and the latter, except for a further reduction in contact angle at 1.00 wt% and 2.00 wt% nanoparticle concentrations as a result of longer soaking time of glass surface in the nanofluids.

Fig. 8
figure 8

Effect of nanoparticle concentrations on the contact angle of n-heptane droplet on the glass surface after 6 days

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4.3 Effect of seawater dilution on wettability of treated glass surfaces

In this research, synthetic Persian Gulf brine (called SW) was used as the base fluid to investigate the effect of brine dilution extent on wettability alteration. For this purpose, SW was diluted 2, 5, 10, 20 and 100 times (in short 2-TDSW, 5-TDSW, 10-TDSW, 20-TDSW and 100-TDSW) by mixing with deionized water. Treated oil-wet glass surfaces were submerged in each brine sample for 3 days at environmental temperature (25 °C). It was observed that brine dilution has a negligible effect on wettability of the glass surface, as demonstrated in Fig. 9. In contrast, repeating the experiment at 80 °C revealed a marked influence of dilution on changing the wetting, as shown in Fig. 10. Unsurprisingly, as well understood in previous work (Al-Aulaqi et al. 2011a, b), ions are more active at higher temperatures and could contribute to interfaces more effectively, as pointed out by Agbalaka et al. (Agbalaka et al. 2009). By measuring the Amott–Harvey wetting index for sandstone cores, they understood that a temperature increment of low-salinity brines would make the core samples more water wet. Noteworthily, dilution above 10 times has reduced the contact angle of oil-wet glass surface by ~ 80°. Additionally, once the abrupt change took place, further dilution of the SW (20 and 100 times) did not reduce the contact angle any further. This behavior is analogous to that observed for the variation in nanoparticle concentrations, as shown in Fig. 8.

Fig. 9
figure 9

Effect of seawater dilution on wettability alteration of the oil-wet treated glass surface at 25 °C

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Fig. 10
figure 10

Effect of seawater dilution on wettability alteration of the oil-wet treated glass surface at 80 °C

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4.4 Simultaneous influence of nanoparticles and seawater salinity on wettability of treated glass surfaces

Based on the preceding experiments, the 20 times diluted seawater (20-TDSW) was chosen as the base fluid and was thickened by varying concentrations of nanoparticles. As shown in Fig. 11, the nanofluid could incredibly restore the original (untreated) water wetness of the glass surfaces, as a result of the synergic effect of silica nanoparticles and seawater salinity. This observation points to the beneficial aspect of applying nanotechnology in conjunction with low-salinity water flooding, which both are current research topics in petroleum engineering. The improved performance of the nanofluid for altering wettability in low-salinity environment supports our hypothesis that surface adsorption is not the sole cause of wettability alteration. The structural disjoining pressure, which was enforced simultaneously by the effect of nanoparticles as well as seawater salinity, leads to a contact angle reduction, as shown in Fig. 11. However, this trend is somewhat erratic, suggesting that there is no point in using high concentrations of SiO2 nanofluid more than 0.25 wt%, which was discussed in the preceding section.

Fig. 11
figure 11

Contact angle of n-heptane droplet on the treated (oil-wet) glass surface at varying concentrations of nanoparticles dispersed in 20-TDSW

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In another attempt, the effect of salinity on glass wettability was investigated with different salinity nanofluids containing 0.25 wt% SiO2 nanoparticles. These nanofluids were prepared by dispersed SiO2 nanoparticles in synthetic SW, 2-TDSW, 5-TDSW, 10-TDSW, 20-TDSW and 100-TDSW, and the contact angle of n-heptane was measured on the treated (oil-wet) glass surface. As shown in Fig. 12, 0.25 wt% nanofluid prepared with 2-TDSW results in a sharp reduction in contact angle, that is, restoring the original (untreated) wettability state of the glass surface. Nevertheless, further dilution was of mild influence on wettability alteration in achieving the minimum contact angle of 22° at 20-TDSW. It was notable that at an extreme dilution level, dissolved ions would be of minimal activity, where the diluted brine would act like deionized water. In support of this argument, no wettability alteration effect was observed in the case of 100-TDSW, as shown in Fig. 12.

Fig. 12
figure 12

Effect of salinity of nanofluids (0.25 wt%) on wettability of the oil-wet treated glass surface

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4.5 Oil recovery

After analyzing the effect of dilution (i.e., brine salinity) and nanoparticle concentration on the wettability of the glass surface, here we proceed to a higher-scale micromodel network, to evaluate the contribution of wettability alteration to oil displacement by nanofluid injection. It has been well understood that the distribution of oil and water phases in a porous media is proportional to the wettability of its pore structure. Intuitively, one would expect a direct relation between the oil displacement efficiency and the degree of wettability alteration by the injected fluid, herein low-salinity SiO2 nanofluid.

By injecting 0.25 wt% SiO2 nanofluid prepared with 20-TDSW or 1.00 wt% nanofluid prepared with deionized water into the oil-saturated micromodel, we observed oil recovery enhancement while using suspensions with higher concentration. As shown in Fig. 13, the nanofluid containing 1.00 wt% SiO2 particles resulted in higher oil recovery, 15% higher than the nanofluid containing 0.25 wt% SiO2. Recall that the micromodel in this experiment was initially water wet, and as discussed earlier, no further wettability alteration would have occurred in the presence of nanoparticles, since the substrate was initially strongly water wet. As a result, some other mechanism(s) come(s) in effect to bring about a higher recovery while injecting a nanofluid with higher concentration. Among diverse properties associated with fluid displacement in porous media, viscosity is of paramount importance, as it affects both the rate and amount of ultimate oil recovery. To exclude any experimental artifact in this study, higher injection rates were used during injection scenarios to overcome capillary end effects (Al Harrasi et al. 2012; Hosseinzade Khanamiri et al. 2016), as discussed in the experimental section. As evident in Fig. 13, one could notice a delayed breakthrough in the case of injecting the 1.00 wt% SiO2 nanofluid prepared with deionized water (with a salinity of 0) in comparison with the 0.25 wt% nanofluid with salinity of 0. Similar behavior was also observed in the case of 0.25 wt% SiO2 nanofluid prepared with 20-TDSW. Increasing viscosity leads to lower mobility contrasts of the displacing (nanofluid) to displaced (oil) phases, and consequently, uniform displacement in pore networks is provided. Additionally, as inferred by the Buckley–Leveret theory (Buckley and Leverett 1942), decreasing mobility of the displacing fluid delays the breakthrough time, as exemplified in Fig. 13. Apart from the change of rheological characteristics, Brownian motion of silica nanoparticles induces their interaction with surface-active compounds at the oil–water interface by attracting natural surfactants on the interface, thus reducing the interfacial tension and as a result, higher oil recovery.

Fig. 13
figure 13

Oil recovery during injection of different fluids into the water-wet micromodels. In this section, 1.00 wt% and 0.25 wt% SiO2 nanofluids were prepared with deionized water, with a salinity of zero; 0.25 wt% of low-salinity SiO2 nanofluid was prepared with 20-TDSW

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In a further evaluation, we repeated the foregoing experiment for the case of treated (oil-wet) micromodels. Contrary to the previous water-wet medium, we observed a maximum oil recovery of 62% when injecting 0.25 wt% of low-salinity SiO2 nanofluid (prepared with 20-TDSW). As discussed earlier, brine dilution and the presence of nanoparticles both modified the wettability of glass substrate toward the favorable water-wet state. Maximum recovery as well as the longest breakthrough time was observed in the case of injecting 0.25 wt% of low-salinity SiO2 nanofluid, which reflects a synergic contribution of wettability alteration and mobility reduction by increased viscosity. Interestingly, in contrast to results of the water-wet medium shown in Fig. 13, brine dilution and nanoparticle thickening have comparable influences on the ultimate oil recovery, as illustrated in Fig. 14. This figure also supports the advantage of utilizing nanoparticles in EOR processes, where 8% incremental recovery was achieved by blending 0.25 wt% nanoparticles in 20-TDSW. Figure 15 shows micromodel images used for sweep efficiency calculation. The images show the injection of the above fluids (0.25 wt% SiO2 low-salinity fluid, 1.00 wt% SiO2 nanofluid, 20-TDSW and formation water) into the treated (oil-wet) micromodel. From these images, it can be concluded that injection of 0.25 wt% of low-salinity SiO2 nanofluid into the micromodel has the highest areal sweep efficiency. The images also indicate that formation water injection yields the lowest oil recovery among these injection scenarios.

Fig. 14
figure 14

Oil recovery during injection of formation water, 20-TDSW, 1.00 wt% SiO2 nanofluid (prepared with deionized water) and 0.25 wt% of low-salinity SiO2 nanofluid (prepared with 20-TDSW) into the treated (oil-wet) micromodels

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Fig. 15
figure 15

Micromodel images of sweep efficiency during injection of 0.25 wt% of low-salinity SiO2 nanofluid (prepared with 20-TDSW) (a), 1.00 wt% nanofluid (prepared with deionized water) (b), 20-TDSW (c), and formation water (d), into the treated (oil-wet) micromodels; all images were taken after 2 pore volume injection

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Figure 16a compares oil recovery by injecting 0.25 wt% of low-salinity SiO2 nanofluid into oil-wet and water-wet micromodels. There was a difference of 4% in oil recovery due to wettability alternation of pore networks. Although the low-salinity nanofluid is able to change the wetting state to a favorable one, oil-wet (treated) medium will not completely resume its original strongly water-wet characteristics during the short period of the displacement process. On the other hand, wettability restoration is a result of the synergic contribution of both low-salinity and dispersed nanoparticles. Figure 16b compares oil recovery via injecting 20-TDSW into oil-wet and water-wet micromodels, and there was a difference of 3% in oil recovery due to wettability alternation. In this respect, about 16% more recovery would be achieved by adding 0.25 wt% of SiO2 nanoparticles to 20-TDSW in the case of the water-wet medium, by the comparison of Fig. 16a, b.

Fig. 16
figure 16

Effect of the micromodel wettability on the oil recovery during injection of low-salinity nanofluids (0.25 wt%) (a) and 20-TDSW and formation water (b)

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Viscosity variation of different injection fluids and the differential pressure between the inlet and the outlet of the micromodel are shown in Fig. 17. Experimental viscosity data for different fluids were measured by an Ostwald viscometer under ambient conditions (25 °C and 1 atm). The characteristics of the viscometer were mentioned in our previous work (Dehaghani and Badizad 2016). In addition, differential pressures between the inlet and outlet of the micromodel at the start of injection and after 5 PV of injection were measured using an accurate barometer. According to these parameters, it can be concluded that by increasing the viscosity, the differential pressure would increase. Moreover, 1.00 wt% SiO2 nanofluid had the highest viscosity (1.6 cP) of all. It is essential to note that the differential pressures after 5 PV for all injection fluids were less than what they were at the start of injection, that is, because of the establishment of continuous fluid flow. The latter occurred after 5 PV injection where a continuous flow of the displacing fluid with a lower viscosity in comparison with the displaced fluid will be established.

Fig. 17
figure 17

Viscosity and differential pressure data for different injection fluids

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5 Conclusions

In this research, the synergic contribution of the low-salinity effect and SiO2 nanoparticles were evaluated for EOR by conducting contact angle measurements and micromodel flooding. Major conclusions are drawn from this work:

  1. 1.

    The contact angle of the treated (oil-wet) glass surface after soaking in nanofluids with varying concentrations of dispersed SiO2 particles demonstrates an abrupt change of wettability once the nanoparticle concentration increases above 0.75 wt%. To scrutinize the kinetic nature of wettability alteration, contact angle measurements were replicated over a longer period (for 6 days), but the deviation was insignificant.

  2. 2.

    Diluted samples of original seawater (SW) were ineffective in altering the contact angle at ambient temperature. However, contact angle measurements at 80 °C revealed the capability of diluted SW to change wetting toward a water-wet favorable state. This observation was ascribed to higher activities of dissolved ions at an elevated temperature.

  3. 3.

    The low-salinity effect was also active in the presence of dispersed SiO2 nanoparticles. However, the nanofluid failed to change wettability in 100-fold dilution SW. In order to achieve a synergic contribution of both low-salinity effect and nanoparticles, an optimum concentration is needed. In the case of extraordinary dilution (here 100 times), the solution acts as does deionized water.

  4. 4.

    Micromodel flooding was performed to investigate displacement efficiency of SiO2 nanofluids. The solution containing 1.00 wt% nanoparticles displayed the longest breakthrough time in comparison with the diluted ones. Silica nanoparticles dispersed in the 20-fold diluted brine also affected the oil recovery very much. These experiments showed that the increase in breakthrough time is not only due to viscosity increment but also due to other mechanisms such as the salting in effect and the Brownian motion of silica nanoparticles.

  5. 5.

    Afterward, a 20 times diluted brine, 1.00 wt% silica nanofluid (prepared with deionized water) and a combined fluid of 0.25 wt% silica nanoparticles in a 20 times diluted brine were injected into oil-wet micromodels. The results indicated that the combination of silica nanoparticles and the 20 times diluted brine (low salinity) had a better influence in comparison with the nanofluid of higher silica concentrations and salinity of 0. The test also demonstrated that the combined fluid is more effective in oil-wet environments.

  6. 6.

    Comparison was made of silica nanoparticles in water-wet and oil-wet porous media, and it was concluded that in a water-wet medium the oil recovery was about 4% more than that in an oil-wet medium.

  7. 7.

    The effects of injecting the 20 times diluted brine and the formation water into oil-wet and water-wet micromodels were compared. The test proved that injecting formation water into an oil-wet porous medium led to lower oil recovery compared to the situation where the 20 times diluted brine was injected. The injection of the 20 times diluted brine into a water-wet porous medium also resulted in a higher oil recovery compared to the oil recovery obtained in an oil-wet porous medium. The latter indicates that the wettability of the porous medium is very effective for oil recovery; however, it is not the only factor controlling distributions of oil and other fluids in porous media.