Introduction

Unfortunately, only 15% of the original oil in place (OOIP) can be produced with the natural pressure of the reservoir which means the requirement of using methods namely secondary and tertiary oil recovery methods which can enhance the reservoir pressure or trapped oil extraction. Unfortunately, even after using secondary oil recovery methods, a high volume of crude oil (about 70% of the OOIP) remained unrecovered which means the necessity of using enhanced oil recovery (EOR) methods. In this way, new methods are proposed periodically to introduce the most applicable and effective EOR methods for different reservoirs including carbonate and sandstone reservoirs. Although several EOR methods have been proposed and examined during the past decades, operating limitations such as heterogeneity, fractures, etc. lead to moderate effectiveness of these EOR methods. In detail, unfortunately, the complexities of reservoirs make it hard for one individual EOR method to enhance the oil recovery to its ultimate level. In this way, one of the proposed solutions is using hybrid methods which concomitantly activate multiple mechanisms (Cheraghian 2015); (Abhishek et al. 2015); Cheraghian and Hendraningrat 2016). In this way, different innovative EOR methods were proposed such as using ionic liquids (ILs) as a new class of surfactants, or nanoparticles as one of the new and interesting methods for oil recovery purposes (Bera and Belhaj 2016; Khalil et al. 2017; Li et al. 2021; Negin et al. 2016).

Besides, respecting the interesting features of nanoparticles (NPs) they are proposed for activating different mechanisms during the EOR processes e. g. reducing the interfacial tension (IFT) between the crude oil/aqueous solution (Ju et al. 2006; Torsater et al. 2012; Zaid et al. 2013), changing the wettability of the rock surface toward mixed-wet or strongly water-wet conditions (Al-Anssari et al. 2016; Saien and Gorji 2017), or even changing the viscosity and swelling of crude oil (Ehtesabi et al. 2015; El-Diasty and Ragab 2013; Kazemzadeh et al. 2015; Mohammadi et al. 2017; Taborda et al. 2016, 2017; Wei et al. 2007). Moreover, the investigations revealed that it is possible to use the NPs to produce nano-emulsion (Bobbo et al. 2012), selectively plug the pore (Anganaei et al. 2014; Hashemi et al. 2013), and enhance and manipulate the thermal conductivity and disjoining pressure (Aveyard et al. 2003; McElfresh et al. 2012; Zamani et al. 2012). The interesting point regarding the NPs besides the aforementioned features is their transportation capability which can move through the pore networks and keep them dispersed in the fluids (Rodriguez Pin et al. 2009).

In this way, Onyekonwu and Ogolo (Onyekonwu and Ogolo 2010) used polysilicon NPs for possible wettability change of surface since it is a vital parameter to produce higher trapped oil in the reservoir pore networks. Also, Hendraningrat et al. (Cheraghian 2016; Hendraningrat et al. 2013a, 2013b, 2013c; Torsater et al. 2012) reported the possibility of wettability change of rock surface toward water-wet condition using silica-based NPs.

Moreover, in the field of using hybrid EOR methods, several researchers investigated the effect of silicon dioxide nanoparticles (SiO2-NPs) on the water alternate gas injection processes (Aziz et al. 2021; Moradi et al. 2015a, 2015b). For example, Moradi et al. (Moradi et al. 2015b) investigated the effect of SiO2 nanoparticles (SiO2-NPs) with spherical morphology and two different sizes of 11–14 and 30–40 nm to improve the efficiency of the water alternate gas injection method. They have reported that nano-silica adsorption on the rock surface moves the rock wettability from oil-wet to strongly water-wet conditions. They also reported that nanoparticles can be arranged at the oil/water interface leading to IFT reduction besides an increase in the viscosity. The point is that the viscosity enhancement and wettability alteration increase the oil recovery by modifying the capillary numbers. The other point that must be considered is that the obtained results revealed a direct relationship between the size reduction of nanoparticles and better efficiency for higher oil recovery.

Among the different possible mechanisms that NPs can activate, wettability alteration is the most important one since they have a limited impact on the other mechanisms that directly impact the possible oil recovery. For example, although NPs can change the wettability of the rock surface toward strongly water-wet conditions, NPs cannot reduce the IFT to low or ultra-low values where the IFT reduction would be dominant. In light of the importance and advantages of NPs in the EOR processes, a comprehensive review was performed by Iravani et al. (Iravani et al. 2023) to investigate the history and challenges of this method for EOR purposes. According to their findings, depending on the NPs type and their application in bare status or hybrid condition (combination with the other EOR processes), it is possible to modify the IFT, wettability of the rock surface, the viscosity of displacing phase, and even control the surfactant adsorption which has a direct impact on the operating cost of chemical injection processes.

Furthermore, Gholinezhad et al. (Gholinezhad et al. 2022) used a new type of NPs commonly known as EOR-12 which was comprised of a silica core with a nominal diameter of 12 nm and a covalently attached ethylene glycol as a proprietary surface coating for EOR purposes. Their results revealed that the examined EOR-12 agent similar to many other NPs was capable of changing the wettability of the surface to water-wet condition and also provided considerable emulsification characteristics without any acceptable level of IFT reduction to be considered as an effective mechanism. But the point must be mentioned is that although using NPs is not suitable for IFT reduction to a level that the residual oil being mobilized, the IFT reduction even to values around 1 mN/m or 0.5 mN/m (far above the ultra-low value IFT) can facilitate the movement of molecules and particles toward the surface for better and faster wettability alteration. In other words, although the NPs and modified-NPs are unable to well reduce the IFT value, their capability to reduce the IFT to a few mN/m is enough to help the molecules for better movement and packing them in the rock surface/aqueous solution for more effective wettability alteration.

Besides, the NPs are faced with an intrinsic risk of precipitation in the aqueous solution and plugging of the pore networks which would be destructive to the entire reservoir since it makes the tapped oil inaccessible forever. In other words, keeping the nanofluids stable during reservoir treatment through EOR processes and selecting the proper NPs size selection which has a direct impact on the pore blockage, economic feasibility, and compatibility of selected NPs considering the production severities are among the most important challenges of using NPs for EOR processes which must be carefully being examined and investigated before any field application (Iravani et al. 2023).

According to these limitations and shortcomings, it is highly required to combine the NPs with other methods to eliminate the risk of precipitation and improper effect on the IFT reduction.

One of the solutions to eliminate these shortcomings is using surfactants which can stabilize the nanoparticles in the solution and reduce the IFT to more desired values. Unfortunately, conventional surfactants lose their functionality under harsh conditions of salinity and temperature. In light of this concern, a new class of solvents namely ionic liquids (ILs) has been proposed and examined during the past decade as new surfactants with a high capability of tolerating harsh salinity and temperature conditions.

Generally, ILs are excellent substitutions for common solvents and chemicals because they can provide unique characteristics such as high chemical stability, especially under high temperatures and high salinity contents (Chen et al. 2014; Dharaskar Swapnil 2012; Domańska 2005; Lee and Kim 2013; Martins et al. 2014; Peng et al. 2011), etc. The other point that makes the ILs applicable in different industries is their chemical structure since they are a combination of two different sections namely cationic and anionic groups provide a high chance to tailor desired ILs with specific tasks (José-Alberto and Jorge 2011; Khupse and Kumar 2010).

For example, Smit et al. (Smit et al. 1991) and Hezave et al. (Hezave et al. 2013c) investigated the capability of ILs for EOR purposes under harsh and high salinity conditions. Their results revealed that dissolution of the cationic ILs in formation brine is highly effective on the IFT reduction, especially for the solutions with high salinity contents (Hezave et al. 2013a). The other point is that not only the ILs can reduce the IFT to a desired value but also change the wettability toward more water-wet conditions (Rodríguez-Palmeiro et al. 2015). Moreover, Al-Asadi et al. (Al-Asadi et al. 2022) examined the impact of [C12mim][Cl] as the surfactant and aluminum oxide (Al2O3) as the NPs under high salinity condition of 5.0 wt% NaCL to approach the salinity of the seawater usually in the range of 5 wt% TDS. They reported that an increase in the IL concentration from 0.01 to 1.00 wt% has a significant impact on IFT by reducing the IFT values from 3.8 mN/m to 0.6 mN/m. The point is that although this low value of IFT is not enough to mobilize the trapped residual oil in the pore networks, further experiments performed by Al-Asadi et al. (202) with contact angle (CA) measurements revealed that the adsorption of IL concomitant with Al2O3-NPs has a significant effect on the wettability alteration toward strongly water-wet conditions as the CA was changed from 143.5o (initial value) to minimum value of 25.6°. The other point that they reported is that the presence of NPs concomitant with the surfactant has a negative impact on the surfactant adsorption by increasing its adsorption value. According to these findings, one can conclude that the presence of NPs and surfactants especially [C12mim][Cl] has a considerable impact on the oil recovery by activating the wettability alteration mechanism as the dominant mechanism.

Besides the importance of chemical combination, the type of oil (natural acidic or basic crude oil or synthetic oil) is the other important option that must be carefully examined (Demirbas 2016; Demirbas and Taylan 2015; Muhammad et al. 2013). Unfortunately, most of the performed investigations were focused on the effect of ILs on the IFT reduction and wettability alteration regardless of the crude oil type.

So, since according to the best knowledge of the authors no reports existed regarding the concomitant effect of SiO2-NPs, ILs from the imidazolium family, pH (as an operating condition), and heavy acidic crude oil on oil recovery, the current investigation is focused on the optimum formulation (hybrid solution) of these chemicals. In detail, the existence of acidic contents in the crude oil can be combined with the pH of the aqueous solution and fabricate the in-situ surfactants (saponification) which can act as a kind of alkaline injection process. In this way, the current investigation can examine the possible synergism between the in-situ surfactants and ILs for IFT reduction or wettability alteration and even for NPs stabilization for the first time.

So, a hybrid solution including SiO2-NPs and 1-dodecyl 3-methyl imidazolium chloride ([C12mim][Cl]) or 1-octadecyl 3-methyl imidazolium chloride ([C18mim][Cl]) under different pH values of 3–11 is going to be prepared and examined for the IFT reduction and wettability alteration purposes in the presence of acidic heavy crude oil. Finally, the efficiency of the obtained optimum chemical formulation will be examined using core flooding experiments with two different approaches of quick flooding and core flooding followed by a soaking time (1 month) to differentiate the effect of IFT reduction and wettability alteration on the oil recovery.

Materials and methods

The step-by-step procedure of performed experiments is as below (Fig. 1).

Fig. 1
figure 1

Flowchart for the roadmap of the current investigation

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Material and solutions

The sample acidic oil is provided from one of the Iranian oilfields (by Offshore Oil Company, Iran) with asphaltene and resin contents of 11.1% and 13.3%, respectively, with a density of 0.918 g.cm−3 @ ambient conditions.

The required salts with a minimum purity of 99% (Sigma-Aldrich, USA) and SiO2 nanoparticles with a particle size range of 20–30 nm were prepared from Finenano, Iran with purity better than 99%. Besides, the sample ILs namely [C12mmim][Cl] and [C18mim][Cl] were synthesized according to the procedure previously reported (Hezave et al. 2013b, 2013c) (see Fig. 2) (Bennett and Larter 1997).

Fig. 2
figure 2

The analysis results of synthesized [C12mim][Cl], A) FTIR of the current investigation, and b) FTIR reported by Bennet et al. (Bennett and Larter 1997)

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Interfacial tension and contact angle measurement

Measuring the IFT using the pendant drop method is one of the most accurate and easy methods for both ambient and reservoir conditions. The other advantage of using the pendant drop method is its capability for measuring the contact angle which is an indication of the surface wettability (Yang et al. 2014). In light of these advantages, pendant drop equipment (APEX Technologies Co., Arak. Iran) (see Fig. 3)) was used for measuring the CA and IFT of the different aqueous solutions/crude oil/rock systems.

Fig. 3
figure 3

IFT and contact angle measurements equipment

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A detailed description of the used method and the theory behind this method is give n by stauffer (Stauffer 1965). By the way, the following equation can be used to calculate the interfacial tension (IFT):

$$\gamma =\frac{\Delta \rho g{ D}^{2}}{H}$$
(1)

In the above equation, Δρ is the difference between the drop and bulk phases, g is the gravitational acceleration, and H is the shape-dependent parameter in which the value of H is correlated to the shape factor known as S = d/D, (D is an indication of the equatorial diameter and d is the diameter at the distance D from the top of the drop.

In detail, the equipment is comprised of different sections including the automatic dispensing system to suspend a drop on the tip of the capillary needle, the image processing software which processes the captured images via charge-coupled device (CCD) camera and Macro lens, XYZ moving stages to adjust the rock sample or cuvette for proper images required shape analysis. After forming the drop at the tip of the nozzle, it is possible to calculate the IFT using online software which directly analyzes the images of the formed drop. The used CA measurement procedure in the current investigation poses two different steps including (1) thin section preparation, and (2) contact angle measurement.

In the first step, the core plugs were cut into several thin sections (core slices) with a thickness of 3 mm and a diameter of 1.5″. After cutting the thin sections, the core slices were sonicated for about 30 min and then followed by Soxhlet extraction to be cleaned and rinsed. Then, the cleaned samples were well-dried in a forced air-circulating oven under a temperature of about 120 °C for 48 h. In the last stage, the prepared thin sections were placed in the high-pressure stainless steel chamber filled with the desired oil sample. At this point, the pressure was increased to 1000 psi and then placed in an oven under the temperature of 80 °C for about 3 months to complete the aging process. The worth mentioning point is that the previously performed investigations by the coauthors revealed that using three months of aging is enough to restore the thin sections to the reservoir condition which was applied in the current investigation. After three months of aging, the prepared sections were used for wettability alterations by 10 days of aging in brine solutions. During this, the static contact angle was measured as a function of time to examine the effect of salinity on the wettability of the treated samples.

In the second step, the drop must be placed beneath the thin section surface using gentile drop injection at the tip of the nozzle and then catching the formed drop by moving the thin section toward the formed drop to avoid any disturbances between the phases. This disturbance must be avoided since it can directly affect the accuracy of the contact angle measurements.

Core flooding procedure

In the current investigation, a high pressure-high temperature core flooding apparatus was designed and constructed for pressure up to 150 °C and 700 bar, respectively, (Fanavari Atiyeh Pouyandegan Exir Co., (APEX Technologies Co., Arak, Iran) was used to perform the required experiments (see Fig. 4).

Fig. 4
figure 4

Core flooding experimental apparatus

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This equipment mainly consists of different parts including a high-pressure injection pump, high-pressure high-temperature accumulators for different liquids (three of them have a volume of 500 cc while one of them has a volume of 100 cc for easy handling of the chemical slugs), high pressure-high temperature hassler core holder type, confining pressure system control and monitoring, gas back pressure regulator (GBPR) monitoring and controlling unit, and data acquisition system. In this equipment, the injection of fluids is done using a high-pressure pump with the desired injection rate mostly between 0.1 and 0.6 cc/min since the laminar flow of the fluids in the reservoir is about 1 ft/day which is close to 0.3 cc/min. So, the current apparatus can be used as a way to perform the different injection patterns, and inject different solutions under different pressures and temperatures using the following sequence:

  • Measuring the porosity and permeability of the core plugs

  • Saturation of the fresh core plug using formation brine injection for several pore volumes (PVs) to ensure no air existed in the core

  • Injection of crude oil under a flow rate of 0.3 cc/min to saturate the core plug with crude oil and reach the irreducible water saturation (Swirr). At this point, the core is reached the reservoir condition after the primary production stage which means the core is ready to be used for secondary and tertiary oil recovery stages.

  • Injection of formation brine or any aqueous solution for several pore volumes with a flow rate of 0.3 cc/min to reach the point where no oil is being produced (Swro) (secondary oil recovery stage). Injection of any chemical solution slug in the range of 0.1 to 0.5 PV with desired injection rate in the range of 0.1 to 0.6 cc/min chased with formation brine for several PVs for further oil production as the tertiary oil recovery stage

  • Soaking the flooded core plug with the chemical slug for a specific period of time more than 7 days to give the required chance to reach the ultimate wettability alteration. It is possible to differentiate the effect of different mechanisms such as IFT reduction from wettability alteration to some extent.

Results and discussion

Effect of [C12mim] [Cl] and [C18mim] [Cl] on the IFT and CA

In the first phase of this study, the influence of ILs dissolution in the formation brine on the IFT and changing the wettability of the rock surface was examined by changing the ILs concentrations from 0 to 2000 ppm (see Figs. 5 and 6).

Fig. 5
figure 5

The effect of ILs type and concentration on the IFT reduction

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Fig. 6
figure 6

The effect of ILs type and concentration on the CA of the rock surface

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As demonstrated in Fig. 5, the results depicted that as the concentration of IL increases, the IFT values experience a reduction. Besides, the measurements revealed that ILs with longer chain lengths lead to better IFT reduction due to better packing and orientation of the molecules at the interface. The measurements also revealed that the examined system has critical micelle concentrations (CMC) values (the highest IFT reduction pulse considering the initial IFT values) of about 250 and 500 ppm for [C18mim][Cl], and [C12mim][Cl], respectively. CMC is usually defined as the point where the surfactant molecules start to form micelle instead of being dissolved as monomers. This value which strongly depends upon the surfactant structure is a crucial parameter that must be accurately determined for any system if the IFT is an essential parameter through that system. In brief, surfactant molecules reduce the interfacial energy of the solution and remove the hydrophobic groups from the surface of the surfactant (those that are in contact with the water) while the system's free energy reduces on the other hand. As follows, when the concentration of surfactant molecules increases in the aqueous phase, the agglomeration of surfactant molecules begins which leads to the formation of micelles. The formation of micelles rapidly reduces the free energy of the solution by reducing the possible interactions that existed between the hydrophobic groups and surfactants, and the surfactant concentration reaches the CMC value. This is a point in which further enhancement of surfactant concentration introduces no significant influence on the IFT reduction since the excess number of surfactant molecules would tend to form micelles instead of being in monomer status.

Besides the effect of concentration on the IFT, the results revealed that using IL with a longer chain length, in this case, is [C18mim][Cl] compared with [C12mim][Cl] leading to better IFT reduction. The reason behind this trend is that as the chain length increases, more space would exist for the ions at the interface to be packed between the tails of the surfactant molecules leading to more stable packing of those molecules at the interface with lower repulsive forces consequently increasing the number of surfactant molecules can be placed in a certain area leading to better IFT reduction.

Finally, the effect of ILs with the aforementioned concentrations was examined on the CA of the rock surface to see if they can change the rock surface wettability toward more desired conditions which are mix-wet or water-wet conditions (see Fig. 6). The results depicted in Fig. 6 revealed that both of the examined surfactants were capable to reduce the CA toward more water-wet conditions although the effect of IL with longer chain length was more evident and considerable.

Effect of pH on the IFT and CA of solutions prepared by ILs

In the next phase of this study, the effect of pH in the range of 3–11 was examined on the IFT variation and CA manipulation using acidic crude oil and ILs. In this way, the IL concentrations were held constant at 500 ppm for [C18mim][Cl] and 1000 ppm for [C12mim][Cl] well above the CMC values obtained in the previous section (see Table 1). The tabulated results in Table 1 showed that although a higher concentration of [C12mim][Cl] was used compared with the [C18mim][Cl], the IFT is still lower for the [C18mim][Cl] considering the pH = 7 as the base condition. The results also demonstrated that as the pH value increases (the aqueous solution moves toward basic conditions) the efficiency of both ILs was increased due to the formation of in-situ surfactant from the reactions between the acidic content of the crude oil (saponifiable components) and OH− ion existed in the solution. In other words, a type of alkaline can be formed in the solution which can boost the effect of ILs for IFT reduction, especially the IL with a longer chain length which here is [C18mim][Cl]. In detail, alkaline flooding is an interesting EOR method in which an alkali agent (which here is OH−) reacts with acidic components of the crude oil to form surface-active substances. In detail, it has been well evaluated that alkaline flooding is responsible for the activation of different mechanisms such as emulsification and entrainment, wettability reversal (oil-wet to water-wet, or water-wet to oil-wet), and emulsification and coalescence which all of them are correlated to the soap generation. The other important effect of alkaline injection which is not the main objective of this study to be investigated is the production of precipitations that can plug the pore networks of the reservoir. In detail, alkaline has the potential to react with rock and formation and divalent to form precipitates which can preferentially decrease the high-permeability pathways leading to better sweep efficiency usually known as mobility-controlled caustic flood. Also, the addition of the alkali enhances pH and reduces surfactant adsorption so that very low surfactant concentrations can be used to reduce costs. In detail, it is well established that the efficiency of using surfactant during flooding processes (no matter whether it is formed in in-situ conditions or dissolved in the formation brine before injection) is highly correlated to surfactant adsorption on rocks (Kalam et al. 2021; Kamal, et al. 2017; Belhaj et al. 2020; Gale and Sandvik 1973).

Table 1 The effect of pH on the IFT and Ca of aqueous solution prepared by different ILs
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Adsorption, which is the accumulation of molecular species on a solid surface mainly occurs because of multidisciplinary work between chemistry, physics, and engineering which means that the primary appearance of surfactant adsorption comes from the electrostatic attraction. For example, in the case of cationic surfactant, the surfactant molecules are generally being attracted by the rock surface with the negative charges directly causing the surfactant adsorption. But, using anionic surfactants leads to the electrostatic attraction between the surfactant molecules and the positively charged surfaces which mainly are clay edges present in the rock. Although the surfactant adsorption is important in total, the formed aggregates of surfactants which can be in the form of hemimicelles, admicelles, and micelles is also a determining factor that must be carefully examined (Kalam et al. 2021).

In this way, it is highly required to reduce the surfactant adsorption on the rock surface since lower surfactant adsorption can guarantee the successfulness of the chemical flooding for higher oil recovery production (Ahmadall et al. 1993). So, for the purpose of reducing the surfactant adsorption, several researchers including Zhou et al. (2005), ShamsiJazeyi et al. (2013), Le et al. (2011), and Ahmadi et al. (2012) proposed the utilization of different additives into the formation brine concomitantly or before the injection of surfactant solution. One of these additives is an alkali which can affect the charge density on the rock surfaces. The other possible additive is the polymer injection which can provide coverage on the rock surface preventing the surfactant adsorption on the rock surface. For example, Wang et al. have studied polymers for reducing surfactant adsorption in carbonate reservoirs. It was found that a polymer layer was formed on the rock surface, leading to a decrease in active adsorption sites (Wang et al. 2013). Unfortunately, although several investigations were performed to use alkalines and polymers as the preventing agent for surfactant adsorption, these chemicals are faced with several drawbacks and shortcomings since most of them lose their functionality under high-temperature and high-salinity reservoirs (Dai et al. 2010; Lorenz et al. 1989; French et al. 1990). According to this fact, it seems that how to reduce surfactant adsorption is still a big challenge for cost-effective surfactant flooding projects which raises the necessity of performing more systematic investigations regarding alkaline flooding or other possible approaches.

Respecting these facts, it seems that by tuning the pH it is possible to activate several other effective mechanisms for EOR purposes besides the IFT reduction and wettability alteration. Moreover, it seems that in the field scale applications, the produced alkaline can act as the sacrifice by being adsorbed onto the rock surface prior to the surfactants and reduce the adsorption of the expensive surfactant on the rock surface which means a more cost-effective EOR method. In contrast to the higher pH values, the lower pH values have a destructive effect on the IFT reduction for both ILs especially the IL with the longer chain length. This observed trend can be related to the fact that the presence of more H+ ions in the solution can enhance the repulsive forces that exist in the solution. As a consequence of this repulsive force, IL molecules leave the interface to provide more space and minimize the repulsive forces. This trend was more evident in the solution containing IL with a longer chain length which experiences more powerful repulsive forces leading higher effect on the IFT enhancement. A similar but weaker trend that was observed for IFT reduction also existed for the effect of pH on the CA. In detail, the results revealed that increasing the pH value leads to more change in the wettability of the rock surface toward water-wet conditions while the lower pH value has a reverse effect. This observed trend can be exactly described based on those mechanisms proposed for IFT variation which was the production of in-situ soap for pH values higher than 7 and higher repulsive forces that force the molecules to leave the rock surface under the acidic condition.

Stability of SiO2 particles

Since the NPs suffer fast precipitation and SiO2-NPs are not exceptional although they occur at a slower rate, several experiments were performed to find the optimum concentrations of the sample ILs namely [C12mim][Cl], and [C18mim][Cl] in the primary stage of this study (see Fig. 7). In this way, the concentrations of ILs were changed from 50 to 800 ppm while the concentration of SiO2-NPs was held constant at 1000 ppm. The point is that the observations revealed that using only SiO2-NPs leads to fast precipitation of SiO2-NPs while the addition of ILs can retard the SiO2-NPs precipitation in the solution. In detail, the concentration of SiO2-NPs was held constant at 1000 ppm since a higher amount of SiO2-NPs would not be cost-effective to be injected into the reservoir in the field scale.

Fig. 7
figure 7

a Precipitation of SiO2-NPs without ILs (50, 100, 300, 600, and 1000), and b effect of [C12mim][Cl] concentration on the aqueous solution of SiO2-NPs with concentration of 1000 ppm

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Based on the performed stability analysis, it seems that using a minimum concentration of 400 ppm and 300 ppm for [C12mim][Cl], and [C18mim][Cl], respectively, a stability period of about more than 40 days can be achieved. Respecting these findings, one can conclude that using the aforementioned ILs with concentrations lower than 300 and 400 ppm leads to the precipitation of SiO2-NPs which is not acceptable for field applications.

In other words, although during the measurements lower concentrations of ILs would be examined to draw a better picture of the possible trends and mechanisms, in the field-scale applications, the concentration of these ILs cannot be lower than that obtained optimum/threshold values due to several operating and intrinsic concerns.

Interactions between SiO2-NPs and pH on the IFT and wettability alteration

In the last stage of this investigation, the concomitant effect of pH and SiO2-NPs concentration on the CA and IFT was investigated while the concentration of ILs was held constant at 1000 and 500 ppm for [C12mim][Cl], and [C18mim][Cl], respectively. The results tabulated in Table 2 revealed that as the pH value increases from 3 to 11, the IFT reduces for both examined ILs although the effect of pH variation on the IFT reduction of [C18mim][Cl] was more evident. A glance into the results tabulated in Table 2 revealed that the effect of pH variation on the IFT reduction is higher than those observed for the effect of SiO2-NPs on the IFT reduction due to the formation of in-situ surfactant for high pH values. In detail, the results revealed that as the concentration of SiO2-NPs increases from 0 to 1000 ppm, the IFT of solution prepared by [C12mim][Cl] reduces from 6.6 mN/m to 3.9 mN/m while if the pH value increases from 3 to 7 without the existence of SiO2-NPs, the IFT reduces from 6.6 to 4.3 which is rather close to those values. a similar trend can be observed for all of the other pH values of 7 and 11 and even for those solutions prepared by [C18mim][Cl]. Respecting this fact, it seems that manipulating the IFT values for both examined ILs using chemical agents which can enhance pH value is more effective, and cost-effective with lower operational risk (no precipitation) than using SiO2-NPs to introduce similar IFT variation. But, considering the SiO2-NPs impact on the wettability of the rock at different pH values, it is possible to combine the effect of pH and the presence of SiO2-NPs to move the wettability of the rock toward strongly water-wet conditions. A close look into the results tabulated in Table 2 demonstrated that the concomitant influence of SiO2-NPs and increased value of pH on the wettability is higher for the solution prepared by [C18mim][Cl] than [C12mim][Cl] which is due to the longer alkyl chain length of [C18mim][Cl] which provides better emulsification capability in the solution. The other point that must be mentioned is that for some of the experimental conditions as determined by “undetectable”, the IFT values were immeasurable since the IFT values were lower than the limitations of the used equipment ( no numerical IFT values are reported in Tables 2, 3, 4).

Table 2 The effect of pH and SiO2-NPs on the IFT reduction and wettability alteration of the rock surface
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Table 3 The effect of pH and SiO2-NPs on the IFT reduction and wettability alteration of the rock surface
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Table 4 The effect of pH and SiO2-NPs on the IFT reduction and wettability alteration of the rock surface
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Besides the IFT measurements, the CA of different solutions in the presence and absence of SiO2-NPs were measured to find the possible effect of SiO2-NPs on the wettability alteration of the rock surfaces. The measured CA values revealed that although the effect of SiO2-NPs was weaker than pH variation on the IFT reduction, the SiO2-NP effect on the wettability alteration was more considerable than the pH effect. In other words, it seems that using 1000 ppm of SiO2-NPs along with the optimum chemical formulation obtained in the previous section is capable of enhancing the potential of the aqueous solutions for better EOR efficiency by improving the wettability of rock from mixed or neutral or water-wet conditions toward a strongly water-wet condition in which higher oil can be mobilized and produced through the EOR processes. The worth mentioning point is that a similar trend was observed by Hendraningrat and Torsæter (Hendraningrat and Torsæter 2014) who examined the effect of silica-based nanoparticles on the IFT reduction, wettability alteration, and tertiary oil recovery efficiency.

They claimed that it is possible to change the wettability of rock surface toward water-wet status in the shadow of a change in the solid/fluid interface that comes from the adsorption of hydrophilic NPs. They even find that the level of wettability changes toward water-wet conditions regardless of the initial status of the rock surface (water or oil-wet). They observed that as the hydrophilic NPs are dissolved into the synthetic seawater, the NPs lead to a reduction in the CA from 39° to 26° (a 33% reduction), which indicates that NPs have rendered the quartz plate surface more water-wet. On the other side, in an oil-wet system, the presence of hydrophilic NPs in synthetic seawater tends to change the quartz plate to a weakly oil-wet system from 131° to 112° (a 15% reduction). Hence, the surface quartz wettability was modified and will favor the aqueous phase. Morrow reported that large changes in the wettability of a quartz surface can be achieved by the adsorption of a monolayer of polar molecules, although the use of a quartz plate has limitations in using a rock surface as a single mineral (quartz), as reported by Morrow (Morrow 1990).

Core flooding experiments

Finally, the optimum solutions of 1000 ppm SiO2-NPs + 1000 ppm [C12mim][Cl] and 1000 ppm SiO2-NPs + 500 ppm [C18mim][Cl] under basic condition (pH 11) were used to perform the core flooding experiments. In this way, two different types of core flooding experiments were designed and performed including quick flooding (which is a conventional type of core flooding) and quick flooding which utilizes a soaking stage of about 1 month instead of an immediate injection of formation brine after chemical slug injection. The second type of core flooding experiment was performed to find the ultimate effect of wettability alteration on the oil recovery since wettability alteration is a time-consuming procedure. In this regard, four different core flooding experiments were performed to find the effect of using optimum solutions on the tertiary oil recovery (see Table 5). The results tabulated in Table 5 revealed that using the optimum solution with [C18mim][Cl] leading to higher oil recovery which was expected since these solutions leading to lower IFT values and better wettability alteration toward strongly water-wet condition. So, a more stable oil bank can be produced and mobilized by formation brine injection leading to higher tertiary oil recovery. In detail, the results revealed that using an optimum formulation of 1000 ppm [C12mim][Cl] + 1000 ppm SiO2-NPS and pH of 11 and 500 ppm of [C18mim][Cl] + 1000 ppm of SiO2-NPs under pH value of 11 leading to oil recovery of 8.3 and 11.3% based on the original oil in place (OOIP), respectively. Besides, the further performed core flooding experiments using the soaking stage revealed that it is possible to enhance the tertiary oil recovery of the solutions from 8.3 to 13.3% and 11.3 to 15.6% based on OOIP. This observed higher oil recovery can be correlated to the ultimate effect of wettability alteration due to the injection of optimum chemical formulation since during the quick flooding the system has not enough time to introduce its ultimate effect on the trapped oil droplet. But as the system was flushed by the chemical solutions and then soaked, there was enough time for the chemicals to change the wettability of the rock surface, fabricate oil banks, and mobilize it toward the production port. The point is that the effect of soaking on the tertiary oil recovery of the solution prepared by 1000 ppm of [C12mim][Cl] was higher than that obtained for the chemical solution including [C18mim][Cl]. The reason behind these obtained trends can be correlated to the adsorption of the surfactants onto the rock surface. In detail, since the concentrations of injected [C18mim][Cl] were 500 ppm and the [C12mim][Cl] concentrations were 1000 ppm, a higher amount of [C12mim][Cl] than [C18mim][Cl] was available to be adsorbed on the rock surface leading to more effective wettability alteration and oil production.

Table 5 Properties of the used core rocks and the obtained result during the chemical flooding at the presence of optimum chemical formulation with and without soaking stage
Full size table

The worth mentioning point is that experiments conducted by Hendraningrat and Torsæter (Hendraningrat and Torsæter 2014) revealed that using the optimal nano-EOR condition reduced the residual oil saturation and increased the displacement efficiency in all wettability systems. They also reported that increasing the temperature can enhance the efficiency of the displacement mechanism. Finally, they performed an extended post-flush nano-flooding which revealed the possibility of producing more oil from the core plugs with maximum incremental oil recovered up to 4.9% of OOIP. According to the findings of Hendraningrat and Torsæter (Hendraningrat and Torsæter 2014) and those obtained in the current investigation, it seems that combining the SiO2-NPs with ILs as the chemical surfactant and stabilizer can provide a more efficient chemical formulation for oil recovery purposes. Respecting these findings, one can conclude that using both chemical formulations of 1000 ppm of SiO2-NPs + 1000 ppm [C12mim][Cl] and 1000 ppm of SiO2-NPs + 500 ppm of [C18mim][Cl] under basic conditions (pH 11) are excellent choices for EOR purposes.

Conclusions

The present work is performed to propose a new chemical hybrid formulation of ionic liquid (ILs)-based surfactant concomitant with SiO2-nanoparticles (SiO2-NPs) under controlled pH conditions. The performed experiments revealed the following conclusions:

  • An increase in the ILs concentrations regardless of their chain length reduced the IFT for all of the examined conditions regardless of the pH value.

  • The results revealed a lower critical micelle concentration (CMC) value for 1-octadecyl-3-methyl imidazolium chloride ([C18mim][Cl]) compared with the 1-dodecyl-3-methyl imidazolium chloride ([C12mim][Cl]) which can be correlated to the longer carbon chain length of [C18mim][Cl]. Although IL introduced a considerable effect on the interfacial tension (IFT) reduction, combining these chemicals with SiO2-NPs provides a wider window for activating different effective mechanisms for higher oil recovery especially if the pH of the solution moves toward basic condition.

  • The measurements revealed that the formation of in-situ surfactants under high pH value conditions can boost the effect of ILs and SiO2-NPs not only by a better reduction in IFT values but also by better wettability alteration toward water-wet conditions. Besides, it seems that the formation of in-situ surfactant can occupy the active sites of the core plugs and provide higher oil recovery.

  • The measured contact angle values revealed the significant effect of IL on the wettability alteration which moves the rock surface toward neutral wet although both SiO2-NPs addition and controlling the pH are the other influential parameters for wettability alteration toward strongly water-wet conditions with contact angle value of 23.3°.

  • Using SiO2-NPs + IL under controlled pH conditions through core flooding experiments leading to a maximum oil recovery factor of 13.3% based on the original oil in place (OOIP). This oil recovery will be pumped if the chemical slug injection is followed by the soaking stage of about 1 month before the final formation injection sequence which leads to an oil recovery factor of 15.6% based on OOIP.