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Wettability of hybrid nanofluid-treated sandstone/heavy oil/brine systems: Implications for enhanced heavy oil recovery potential Xiaofei Sun, Yanyu Zhang, Guangpeng Chen, Tailin Liu, Dounan Ren, Jianyun Ma, Yukang Sheng, and Sabrina Karwani Energy Fuels, Just Accepted Manuscript • DOI: 10.1021/acs.energyfuels.8b01730 • Publication Date (Web): 25 Sep 2018 Downloaded from http://pubs.acs.org on September 29, 2018

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Wettability of hybrid nanofluid-treated sandstone/heavy oil/brine systems: Implications for enhanced heavy oil recovery potential Xiaofei Sun*, Yanyu Zhang, Guangpeng Chen, Tailin Liu, Dounan Ren, Jianyun Ma and Yukang Sheng, Sabrina Karwani China University of Petroleum (East China), School of Petroleum Engineering, Qingdao, 266580, PR China

*[email protected] +8613021678278 Abstract In this work, we investigated heavy oil/brine systems on oil-wet sandstone surfaces to quantify the performance of hybrid nanofluids (HNFs) for wettability alteration. In the first step, nanofluid stability analysis was conducted to screen effective single nanoparticles for formulating HNFs and ensure that the properties of the formulated HNFs did not change during the experiments. Then, the ability of HNFs to change the wettability of oil-wet sandstone surfaces to a water-wet state was systematically examined and compared with five types of single nanofluids by contact angle measurements. Then, the effects of HNF composition, hybrid nanoparticle concentration, salinity, and exposure time on the wettability change of sandstones were investigated. Finally, the mechanisms for the wettability shift by HNFs were proposed and verified by scanning electron microscopy visualizations. The results showed that the SiO2+Al2O3, SiO2+TiO2 and Al2O3+TiO2 nanofluids could maintain their stability in the harsh reservoir conditions and that they efficiently induced the wettability change of oil-wet sandstone surfaces to a strongly water-wet state under all operational conditions. The SiO2+Al2O3 nanofluid achieved the highest wettability alteration efficiency (from 156° to 21° at 0.1 wt % HNF). The efficiency was improved by adding a nonionic surfactant and increasing the hybrid nanoparticle (NP) concentration, salinity, and exposure time. However, beyond a certain value, the efficiency slightly decreased due to the instability of the HNFs. Two adsorption kinetics models were applied to predict the measured contact angles at different concentrations and exposure times with good agreement. The stronger adsorption of hybrid nanoparticles on sandstone surfaces was considered to be the underlying mechanism for the higher efficiency of HNFs for the wettability shift than that of single nanofluids. ACS Paragon Plus Environment 1

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Keywords: Enhanced oil recovery, hybrid nanofluids, Heavy oil, Stability, Wettability alteration 1. INTRODUCTION Heavy oil resources are estimated at 5.6 trillion barrels, and this value is over five times greater than the remaining conventional crude oil resources.1,2 To meet the growing global demand for energy, improving the production from heavy oil reservoirs is vital. Various enhanced oil recovery (EOR) techniques, such as steam-assisted gravity drainage, cyclic solvent injection, and vapor extraction, have been utilized to improve the oil recovery from heavy oil reservoirs.3-6 However, these techniques face some important challenges, such as poor reservoir-volumetric-sweep efficiency, the high cost of injected agents, possible formation damages, and heat loss.7 Thus, more efficient, less expensive, and more environmentally favorable techniques are greatly needed. Nanofluids are defined as liquid suspensions of nanometer-sized particles (1–100 nm) dispersed in base fluids (deionized water, brine, engine oil, etc.), and they have become an elegant solution to some of the challenges associated with the existing EOR techniques.8,9 Many experiments show promising potential of nanofluid flooding to enhance oil recovery.10-12 The reason for this success is mainly due to the wettability change of rock surfaces from oil-wet to water-wet after treatment with nanofluids.13,14 Many researchers have investigated the performance of various nanofluids for altering the wettability of sandstone, carbonate and shale surfaces.10,12,13, 15-21 Specifically, Li et al. reported that a 0.5 wt% silicon dioxide (SiO2) nanofluid could alter the core wettability from oil-wet to neutral-wet or even more water-wet.12 Al-Anssari et al. experimentally observed that the SiO2 nanofluid could be utilized as an effective agent for inducing the wettability change of carbonate surfaces under room conditions.10 Mohebbifar et al. found that nano biomaterials have the ability to alter the wettability of shale from oil-wet to water-wet.20 Recently, Al-Anssari et al. suggested that silica nanofluids could render oil-wet calcite strongly water-wet under high pressure, temperature and salinity conditions, which is consistent with studies conducted under room conditions.13 Maghzi et al. investigated heavy oil/brine systems on glass surfaces treated by SiO2 nanofluid and proved that the SiO2 nanoparticles (NPs) could alter the ACS Paragon Plus Environment 2

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wettability regardless of the oil viscosity.19 In addition, several types of metal oxide-based NPs, including titanium oxide (TiO2), aluminum oxide (Al2O3), zirconium oxide (ZrO2), cerium oxide (CeO2), and magnesium oxide (MgO), as well as carbon nanotubes (CNT) have been investigated and compared with SiO2 NPs.22-29 The reported data showed that these metal oxide-based NPs could render the strongly oil-wet sandstone or carbonate surfaces water-wet to various degrees. Specifically, Hendraningrat, et al. found that Al2O3 nanofluids could alter the wettability of the sandstone from a strongly oil-wet to a strongly water-wet condition.27 Then, Hendraningrat et al. compared Al2O3 and TiO2 via experiments and found that TiO2 changed the quartz plate so that it was more strongly water-wet.28 Karimi et al.29 found that ZrO2-based nanofluids had the same influence on the wettability alteration of carbonate surface. The ability of NPs in terms of wettability alteration of rock surfaces significantly depends on several factors, including the NP size, salinity, exposure time and solid surface chemistry. Li et al. reported that the efficiency of the SiO2 nanofluid increased with NP concentration until reaching a minimum contact angle at which point no more reduction was observed with increased NP concentrations.30 Hendraningrat et al. showed that the contact angle decreased as the NP size decreased due to higher electrostatic repulsion forces between the NPs.31 Hendraningrat, et al. also found that higher salinity, longer exposure time of rocks and more divalent ions improve the efficiency for inducing a wettability change to a more water-wet condition.32 In a series of works, Al-Anssari et al. observed that NP adsorption was mainly irreversible. Nanofluid treatment was more efficient at elevated temperatures, and the temperature increase reduced the required immersion time to achieve the same contact angle reduction.10, 33 A single nanofluid does not have all the favorable advantages required for a particular EOR process. Therefore, in certain practical applications, trade-offs must be made between several characteristics of various NPs, and these trade-offs led to the study of hybrid nanofluids (HNFs).7 More recently, authors have found the favorability of using HNFs for increasing oil recovery. Specifically, Alomair et al. ACS Paragon Plus Environment 3

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investigated the performance of HNF flooding in sandstone cores and found that the SiO2+Al2O3 HNF with a low concentration yielded higher oil recovery than that with nickel oxide or titanium oxide nanofluids.34 Tarek and EI-Diasty stated that the HNF (40 wt% Fe2O3+35 wt% Al2O3+25 wt% SiO2) could achieve higher oil recovery than those of the tested single nanofluids.35 Subsequently, Tarek conducted several experiments with different mixture concentrations of NPs on a high permeability core starting directly with tertiary recovery, and the results showed that the optimum nanofluid mixture concentration was dependent on both the fluid and rock properties.36 Although the activity of HNFs to improve oil recovery in reservoir rocks has been verified on laboratory scales, the underlying mechanisms involved in HNFs are still not clear. In addition, the wettability of a hybrid nanofluid-treated sandstone/heavy oil/brine system has not been discussed. The influence of the HNF composition, hybrid NP concentration, salinity, and exposure time on HNF performance for wettability alteration is still unknown. Light oil or model oil, such as n-decane, n-heptane, and dodecane, among others, was commonly used in previous investigations. Little is known about whether heavy oil affects the efficiency of NPs in terms of wettability alteration of reservoir rocks. In this work, we investigated heavy oil/brine systems on oil-wet sandstone surfaces to quantify the performance of HNFs for wettability alteration. In the first step, nanofluid stability analysis was conducted to screen effective single NPs that formulate HNFs and ensure that the properties of the formulated HNFs do not change during the experiments. Then, the ability of HNFs to change the wettability of oil-wet sandstone surfaces to a water-wet state was systematically examined and compared with five types of single nanofluids by contact angle measurements. Then, the effects of the HNF composition, hybrid NP concentration, salinity, and exposure time on the wettability change of sandstones were investigated. Finally, the mechanisms for the wettability shift by HNFs were proposed and verified by scanning electron microscopy (SEM) visualizations. The findings will provide new insights into the potential for the application of HNFs for improving heavy oil recovery. ACS Paragon Plus Environment 4

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2. MATERIALS AND METHODS 2.1 Materials Five types of NPs (SiO2, Al2O3, TiO2, Fe2O3 and CuO) reported in the literature that can be used in heavy oil development were utilized to prepare single NFs and HNFs in this study. Figure 1 and Table 1 show the transmission electron microscopy (TEM, JEM-2100UHR, JEOL, Japan) images and properties of the NPs used in this study, respectively. All the NPs were provided by Sinopharm Chemical Reagent Co. Ltd., China.

Figure 1. TEM images of single NPs: (a) SiO2, (b) Al2O3, (c) TiO2, (d) Fe2O3, and (e) CuO.

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NP Type SiO2 Al2O3 TiO2 Fe2O3 CuO

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Table 1. Properties of the NPs used in this study Approx. size Purity Molecular NP shape (nm) (%) weight(g/mol) Spherical 13 99.8 60.08 Spherical 7 99.9 101.96 Ellipsoid 23 99.8 79.87 Tube 45 99.5 159.69 Ellipsoid 40 99.5 79.55

Heavy oil from a reservoir located in the southern margin of the Eastern Venezuela Basin was provided by China National Petroleum Corporation (CNPC). The oil has a considerable amount of asphaltene (7.78 wt%) and resin (35.86 wt%). The dead oil density and viscosity were 1.013 g/cm3 and 24715 mPa•s (50°C), respectively. To avoid the high viscosity oil from blocking the needle used to generate oil droplets, the oil was diluted with kerosene in a 1/3 (wt/wt) ratio, and the diluted mixture was utilized in the contact angle measurements. The mixture had a density of 0.966 g/cm3 and a viscosity of 1527 mPa•s. The synthetic brine was made as a base fluid between sodium chloride (NaCl) and deionized water (conductivity = 10 µS/cm). NaCl (99.5% purity) was supplied by Xilong Scientific, China. The sandstone cores (2.5 cm in diameter and 4.0 cm in length) were used in this study, and these cores were made by silica sands with an average pore size of 120–380 µm. To improve the nanofluid stability by avoiding early NP aggregation, two types of nonionic surfactants [polyvinylpyrrolidone (PVP), Sinopharm Chemical Reagent Co. Ltd, molecular formula = (C6H9NO)n,, and molecular weight = 58000; and polyethylene glycol (PEG), Sinopharm Chemical Reagent Co. Ltd, molecular formula = HO(CH2CH2O)nH, and molecular weight = 2000] and a ionic surfactant [sodium dodecyl sulphate (SDS), Tianjin Fuchen Chemical Reagents Factory, molecular formula = C12H25NaO4S, and molecular weight = 288.38] were selected as stabilizers.37 2.2 Methods Figure 2 shows a schematic of the experimental setup and procedure used in this study. The detailed procedures are described as follows.


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Figure 2. Schematic of the experimental setup and procedure utilized in this study.

2.2.1 Nanofluid Preparation The NFs were formulated by sonicating the desired amount of single or hybrid NPs in the base fluid using an ultrasonic homogenizer (SM-1000C Ultrasonic Homogenizer/Nanjing Shunma Company) (Figure 2a). To obtain stable NFs, the ultrasonication time was optimized because this time significantly affects the NF stability. First, different types of single NFs and HNFs at different sonication times were prepared. Then, NF stability analysis was conducted to determine the optimum sonication time (see the next section). The results revealed that the NF stability increased with an increase in sonication time. However, no detectable difference could be observed after 1 h. Therefore, the optimum sonication time was determined to be 1 h, and all the NFs were sonicated 3 times at 150 W and 25 kHz for 20 min with 5 min of rest to avoid overheating. The formulated NFs were then utilized for stability analysis and contact angle measurements. 2.2.2 Nanofluid stability analysis To screen effective single NPs that formulate HNFs and ensure that the properties of NFs do not


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change during the contact angle measurements, the stability of the prepared NFs was investigated through direct visual observation (Figure 2b). First, after preparing the single NFs, they were placed in sealed transparent bottles for 72 h under room conditions. Then, the properties of each prepared NF (color, turbidity, sedimentation) were observed and recorded from the side glass to analyze the NF stability (the experimental method was also utilized by other researchers.8,37,38). Subsequently, several stable NPs were selected as candidates to formulate HNFs on the basis of the stability analysis results. Finally, the aforementioned procedure was repeated 213 times under different experimental conditions to study the effects of HNF composition, stabilizer, concentration, salinity, and temperature. Although visual observations can be used to investigate nanofluid stability, NP aggregation may occur at the nanosize scale, which cannot be visually observed. Particle size is an important factor that affects the sedimentation of NPs. The sedimentation rate is directly proportional to the square of the size based on Stokes’s law. Therefore, in addition to visual observations, a Zetasizer (Nano ZS90, Malvern Instrument Ltd., UK) was utilized to measure the NP particle sizes under different experimental conditions (Figure 2c). 2.2.3 Contact angle measurement The experimental procedure for the contact angle measurement was performed as follows. (a) A sufficient amount of substrates was obtained by cutting the sandstone cores. Then, the substrates were polished, washed with deionized water and dried in a heating cabinet at 54.2 °C for 24h (Figure 2d). (b) One of the substrates was aged in heavy oil for 48 h under room conditions to ensure that it was in the oil-wet condition (Figure 2e). Then, it was washed with kerosene and petroleum ether and dried. (c) The oil-wet substrate was immersed in the single NFs or HNFs (Figure 2f) and then taken out and washed with deionized water. (d) The substrate was submerged in a water-filled container and maintained in a horizontal position (Figure 2g). An oil droplet was injected with a stainless needle and trapped below the substrate. An image of the droplet was recorded with a digital CMOS camera, and then, the contact angle (ߠ) was determined by utilizing software to analyze the drop-shape image. The ACS Paragon Plus Environment 8

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maximum change of the contact angles was ±2° based on repeated tests. 2.2.4 Mechanistic study To reveal the mechanisms for the wettability shift by HNFs based on electrokinetic data and the Derjaguin−Landau−Verwey−Overbeek (DLVO) theory, the surface charges (zeta potential) of different nanofluids, heavy oil, and sandstone were characterized at different pH levels from 2 to 12 by using the Zetasizer (Figure 2c). The pH was adjusted with either 0.1 mol/L HCl or 0.1 mol/L NaOH to attain the desired pH. The zeta potential was determined by measuring 1 mL aliquots in polystyrene cuvettes (Malvern Instrument Ltd., UK) with 3 measurements per sample at room temperature. In addition, to further confirm the suggested mechanisms, the substrates before and after the nanofluid treatment were visualized by SEM (Figure 2h). 3. RESULTS AND DISCUSSION 3.1 Nanofluid stability analysis Long-term stability of nanofluids is one of the basic requirements for wettability alteration measurements.9,38,39 Under unstable conditions, coagulation/aggregation of NPs within the nanofluid occurs, which leads to a loss of the advantages afforded by the nanosize of NPs. In addition, various single NPs have been reported in the literature, verifying their ability to improve the oil recovery through wettability alteration of reservoir rock surfaces. The best candidates among the single NPs must be selected to formulate HNFs. Therefore, a stability analysis was conducted to screen the single NPs for formulating HNFs and to evaluate the stability of HNFs prior to obtaining the contact angle measurements. 3.1.1 Determination of the HNF composition by screening the single NPs Five types of NPs were used to formulate distinct NFs with the same NP concentration (0.1 wt%) and salinity of the base fluid (0.5 wt% NaCl). Figure 3 shows the visual observation of single NF stability over 72 h. It can be seen from the figure that there is a large difference in the stability of various single NFs. The Fe2O3 and CuO NPs displayed the worst dispersion performance. These NPs ACS Paragon Plus Environment 9

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agglomerated, and many were deposited to a considerable degree in less than 1 h under the experimental conditions. The Al2O3 nanofluid was completely precipitated after approximately 3 h, and the TiO2 nanofluid was completely agglomerated after 24 h. The SiO2 nanofluid remained homogeneous and stable 72 h after it was prepared, thus, exhibiting higher stability than the other metal oxide nanofluids. In brief, the stability of all the tested NPs can be ranked as follows: SiO2 > TiO2 > Al2O3 > Fe2O3 > CuO. Thus, SiO2, Al2O3, and TiO2 NPs were selected and combined to formulate three types of HNFs: SiO2+Al2O3, SiO2+TiO2, and Al2O3+TiO2.

Figure 3. Visual observations of the stability of the various nanofluids.

To evaluate the stability of the HNFs, the three types of HNFs were prepared by sonicating different NPs (0.1 wt%) in a base fluid (0.5 wt% NaCl) under room conditions. The weight proportions of the single NPs in all HNFs were 1:1. The abovementioned parameters of HNFs are used in the following tests, except where a difference is specifically mentioned. Figure 3 shows the stability of the HNFs over time. As shown in the figure, the SiO2+Al2O3 nanofluid is less stable than the Al2O3+TiO2 and SiO2+TiO2 nanofluids and all HNFs were completely precipitated after approximately 72 h. Thus, measures must be taken for the preparation of stable


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HNFs. In addition, during the experimental processes, the phase behavior of nanofluids was observed, revealing that the single NFs and the HNFs had similar phase behaviors. This behavior can be summarized into three typical stages (Figure 3): (1) an early stage with a clear single phase, (2) an aggregation stage with a turbid single phase, and (3) a sedimentation stage with two separate phases. 3.1.2 Effect of the stabilizer In this study, a series of tests were carried out to investigate the effects of PVP, SDS, and PEG on the nanofluid stability. All the three surfactants with a concentration of 1.0 wt% were added to the aforementioned nanofluids. The stability was visually assessed under room conditions over 72 h as shown in Figure 4. Figure 4 shows that the nanofluid stability was highly dependent on the type of surfactant. Various NPs in the base fluid with SDS and PEG agglomerated and deposited to a considerable degree. Therefore, most of the NPs were completely precipitated after approximately 72 h (Figure 4a and b). In comparison, various nanofluids with 1.0 wt% PVP (excluding CuO) presented good dispersion performance 72 h after preparation (Figure 4c).


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Figure 4. Visual observations of the stability of the various nanofluids treated with surfactants: (a) SDS, (b) PEG, and (c) PVP.


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In addition, Figure 5 shows that except for the SiO2 NPs, the mean particle sizes for the other NPs treated with PVP were smaller than those treated with SDS and PEG. Therefore, the surfactant PVP showed better positive effects compared with SDS and PEG on the dispersion and stability of the nanofluids. These results are consistent with the experimental observations obtained by Xia et al., who found that PVP was more efficient than SDS and PEG in dispersing the single NPs.37

Figure 5. Comparison of mean particle sizes for various NPs treated with the surfactants.

To further verify the stability of the various nanofluids treated with PVP, changes in the mean particle sizes over time were measured as shown in Figure 6.

Figure 6. Mean particle sizes for the various NPs treated with PVP.


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Figure 6 shows that only small changes occurred in the mean particle sizes of the NPs (excluding CuO) after 72 h. The measured mean particle sizes were consistent with the visual stability observation results (Figure 4c). In conclusion, PVP can significantly improve the nanofluid stability, and is an effective stabilizer for both HNFs and single NFs. The HNFs prepared with 1.0 wt% PVP showed acceptable dispersion stability, and they were used for the next step of the study. The reason for the aforementioned results is that nanofluid stability depends on the sum of the van der Waals attractive forces and electrostatic repulsive forces existing among NPs dispersed in NFs. The stability of NFs is achieved only when the electrostatic repulsive forces are greater than the attractive forces.40 PVP covers the surface of NPs with a long loop and tail that extends out into the NFs. In this way, a protective layer is formed on the NPs, and enhances the repulsive forces between NPs. Therefore, the NFs used in this study could maintain stability for a longer period. However, the CuO nanofluid completely settled after approximately 12 h and the mean particle size of the CuO NP presented a noticeable increase from 329.8 nm to 626.5 nm after 72 h, meanings that the CuO nanofluid with 1.0 wt% PVP did not show acceptable dispersion stability. These results were consistent with the experimental observations obtained by Kathiravan in which the production of homogeneous CuO nanofluids with long-term stability was challenging even with the addition of stabilizers to the nanofluid.39 3.1.3 Effect of the hybrid NP concentration The hybrid NP concentration must be evaluated to determine the optimum HNF formulation considering that higher concentrations, although they can efficiently enhance oil recovery, may limit or impair reservoir permeability.10,18 Therefore, it is vital to find the lowest effective hybrid NP concentration that is commercially optimal from an economic perspective. To achieve this goal, the three types of HNFs were prepared by mixing the hybrid NPs with the base fluid (0.5 wt% NaCl) and 1.0 wt% of PVP to obtain five concentrations of 0.01 wt%, 0.05 wt%, 0.1 wt%, 0.5 wt% and 5 wt%. ACS Paragon Plus Environment 14

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Figure 7 illustrates the visual stability observations of the HNFs with different concentrations over time, and Figure 8 shows the mean particle sizes for the hybrid NPs with different concentrations after 72 h.

Figure 7. Visual observations of stability of the various HNFs at different concentrations.

Figure 8. Comparison of the mean particle sizes for various hybrid NPs with different concentrations.

As shown in Figures 7 and 8, the stability of the HNFs is a function of the hybrid NP concentration. For all the HNFs tested, the HNF stability decreased with increasing the hybrid NP concentration. A ACS Paragon Plus Environment 15

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higher hybrid NP concentration can remarkably reduce the HNF stability even in the presence of the PVP stabilizer. However, at low concentrations, an increase in the hybrid NP concentration had only a small influence. For instance, no detectable NP sedimentation was observed for 0.01wt%, 0.05 wt% and 0.1 wt% SiO2+Al2O3 nanofluids, and no noticeable changes were observed in the mean particle sizes of the hybrid NP between 0.01wt% and 0.1 wt%. However, the sedimentation process of the 0.5 wt% SiO2+Al2O3 nanofluid was rapidly finished within 3 h, and the mean particle size of the hybrid NP has a significantly increase when the NP concentration is 0.5 wt%. Therefore, the critical concentration for the SiO2+Al2O3 nanofluid is approximately 0.1 wt%. Similar phenomena were also observed for the SiO2+TiO2 and Al2O3+TiO2 nanofluids. However, their critical concentrations were higher than that of the SiO2+Al2O3 nanofluid (Figure 7). The decrease in the nanofluid stability with increase of the hybrid NP concentration is attributed to an increase in the attraction energy of van der Waals forces caused by the high hybrid NP concentration. Thus, during HNF flooding processes, a high hybrid NP concentration does not necessarily yield a high heavy oil recovery. A relatively high hybrid NP concentration is beneficial for improving heavy oil recovery. However, if the concentration is higher than a critical concentration, then the oil recovery decreases because the sedimentation of hybrid NPs under a high concentration will decrease the porosity and impair permeability. 3.1.4 Effect of salinity It is well known that oil reservoirs usually contain relatively high salt concentrations. The salinity can significantly affect nanofluid properties.13,41 Therefore, it is vital to investigate the performance of HNFs in various salinity environments. To accomplish this goal, the three types of HNFs were prepared with a constant concentration (0.1 wt%) in different brines solutions (0 wt%–20 wt% NaCl). Figures 9 and 10 show the stability observations and mean particle sizes of the three HNFs with different NaCl concentrations, respectively. As shown in Figures 9 and 10, for all HNFs, an increase in NaCl concentration results in gradual visual detection of hybrid NP sedimentation and an increase in ACS Paragon Plus Environment 16

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the mean particle sizes. Therefore, the stability gradually decreases with increase in NaCl concentrations. However, at relatively high salinities, the stability is acceptable. For instance, the SiO2+TiO2 nanofluid with 10 wt% NaCl is still stable and the SiO2+TiO2 NPs only display slight sedimentation and an increase in mean particle size at 20 wt% NaCl.

Figure 9. Visual observations of stability of the various HNFs at different salinities.

Figure 10. Mean particle sizes for various hybrid NPs at different salinities after 72 h.

Mechanistically, the instability of HNFs increasing salinity is due to the reduction in the repulsion forces among hybrid NPs. According to the Derjaguin-Landau-Verwey-Overbeek (DLVO) theory,


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attraction and repulsion forces among NPs that determine the HNF stability depend on the surface electric charge.42 Electrolyte ions reduce the repulsion force among hybrid NPs because of the neutralization of NP surface charges. Consequently, high salinity accelerates hybrid NP aggregation and sedimentation. 3.1.5 Effect of temperature The stability analysis was performed at three different temperatures (20°C, 54.2°C, and 80°C) for the three HNFs. The visual stability observations and mean particle sizes are shown in Figures 11 and 12.

Figure 11. Visual observations of the stability of various HNFs at different temperatures.

The results indicate that temperature has a dramatic impact on HNF stability. Within the temperature range of 20°C– 54.2°C, all the HNFs remain stable and homogeneous against agglomeration and sedimentation for more than 72 h (Figure 11). In addition, in this temperature range, only slight changes in the mean particle sizes are observed for various hybrid NPs over time (Figure 12). Thus, the HNFs can satisfy the needs of applications in the reservoir located in the Venezuela Basin (the reservoir temperature is 54.2°C). However, at a higher temperature (80°C), all the HNFs are unstable. The hybrid NPs precipitated more rapidly in less than 72 h, and their mean particle sizes present a noticeable increase after 72 h (Figures 11 and 12). ACS Paragon Plus Environment 18

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Figure 12. Mean particle sizes for various hybrid NPs at different temperatures after 72 h.

The instability of HNFs is attributed to factors such as the motion of hybrid NPs at the micron scale. As the temperature increases, the molecular velocity of hybrid NPs increases according to the Brownian motion of NPs obtained by Koo et al.43 Therefore, the enhancement of the random velocity of the hybrid NPs leads to decreases in the intermolecular forces between the base fluid and the hybrid NPs, resulting in a decrease in the stability at higher temperatures. 3.2 Contact angle measurement 3.2.1 Comparison of the HNF efficiency of wettability alteration A total of three HNFs and five single NFs with the same NP concentration (0.1 wt%), salinity (0.5 wt% NaCl), and PVP concentration (1 wt%) were prepared to investigate their efficiency of wettability alteration for heavy oil/brine/sandstone systems. The weight proportions of single NPs in all the HNFs were 1:1. The abovementioned parameters of HNFs are used in the following tests, except where a difference is specifically mentioned. The results of the contact angle measurements for substrates after aging in various nanofluids are shown in Figure 13. As shown in Figure 13, the ߠ of the sandstone substrate before aging in nanofluids was approximately 156°, which indicates an oil-wet condition on the basis of Anderson’s classification (Figure 2g). After immersing the oil-wet substrate in the base fluid (0 wt% NPs, 1 wt% ACS Paragon Plus Environment 19

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PVP, and 0.5 wt% NaCl) for 6 h under room conditions, the ߠ was reduced to 56 ± 2°, which indicates that the wettability of the substrate aged in base fluid was altered from strongly oil-wet to an intermediate state. This finding is consistent with reports that PVP is a wettability modifier due to its favorable adsorption behavior on the rock surface.8, 44

Figure 13. Efficiency of different nanofluids based on the contact angle measurements.

Figure 13 also shows that introducing various single and hybrid NPs into the base fluid leads to a wettability shift of the substrates from an oil-wet to a strongly water-wet state. Thus, all the tested nanofluids have the ability to alter the wettability of sandstone surfaces to a water-wet condition. The alteration of the formation’s wettability to a preferentially water-wet state will reduce the forces that bind oil to the rock surface, thus causing oil to flow to producers and facilitating more heavy oil recovery, which is in contrast to microemulsions that change the wettability to intermediate wet conditions.45 It is noted that a comparison of the results with and without NPs confirms that the θ reduction after treatment with the nanofluids was related only to the effect of NPs rather than the effect of the base fluid. In addition, by comparing the results among different nanofluids, the following information can be extracted from Figure 13. (1) The SiO2+Al2O3 nanofluid achieved the highest reduction in ߠ (from 156° to 21°), indicating


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the highest efficiency of wettability alteration. (2) The average contact angle of the three types of HNFs is 22.7°, which is lower than that of the single nanofluids from which they are formulated (26.7°). Therefore, compared with single nanofluids, HNFs can improve the efficiency of inducing a wettability change to a more water-wet condition. In addition, the HNFs will likely combine the favorable effects of different NPs and enhance heavy oil recovery. For example, previous studies found that the Al2O3 NP can decrease the heavy oil viscosity by breaking the carbon-sulfur bonds, and the TiO2 NP can increase the density and viscosity of the injected water, which leads to an increase in sweep efficiency.35,36 Therefore, the aforementioned factors indicate that HNFs have greater application potential than single nanofluids for the enhancement of heavy oil recovery. (3) For single nanofluids, the SiO2 nanofluid was more capable of altering the wettability to a water-wet state than the other metal oxide nanofluids (especially Fe2O3 and CuO), which is consistent with the results of Ju et al. and Hendraningrat et al.46,47 3.2.2 Effect of the hybrid NP concentration The effect of the hybrid NP concentration on the wettability of sandstone surfaces is shown in Figure 14a. In all cases, with increasing hybrid NP concentration, ߠ starts to decrease, and beyond a certain value, a slight increment is observed. Taking the SiO2+Al2O3 nanofluid for an example (Figure 14a), ߠ decreases initially with an increase in the hybrid NP concentration. A significant decrease in the ߠ value is achieved when the hybrid NP concentration is 0.1 wt% (from 156° to 21°). It is noted that more than half of this reduction occurs for the 0.01 wt% SiO2+Al2O3 nanofluid. Therefore, the SiO2+Al2O3 hybrid NPs can change the wettability of the sandstone surfaces from an oil-wet to a water-wet state even at a relatively low concentration, which renders the SiO2+ Al2O3 nanofluid feasible and economically attractive for enhancing oil recovery in heavy oil reservoirs.


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Figure 14. Experimental data and predicted values at different NP concentrations obtained by the model: (a) Equation (1) and (b) Equation (2).

However, when the hybrid NP concentration increases from 0.1 wt% to 0.3 wt%, the ߠ value slightly increases with increasing concentration. This increase in ߠ is attributed to the influence of the concentration on the HNF stability since the stability of the SiO2+Al2O3 nanofluid decreases with increasing concentration (consistent with the stability analysis results shown in the previous section). The wettability of the SiO2+TiO2 and Al2O3+TiO2 nanofluids also showed a behavior similar to that of the SiO2+Al2O3 nanofluid on the same sandstone surfaces. A comparison of the results of the single nanofluids (SiO2, Al2O3, and TiO2) and the HNFs shown in Figure 14a indicated that the variation in ߠ with NP concentration for single nanofluids is consistent with that of HNFs. However, under the same contact angle value, the single NP concentrations are


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higher than the HNF concentrations, indicating that a lower amount of HNFs relative to that of single nanofluids is needed to achieve the same wettability alteration efficiency. Therefore, HNFs have great potential to enhance oil recovery in heavy oil reservoirs from an economic perspective. To describe the results shown in Figure 14a, a model was used that was developed based on the Langmuir isotherm:10, 48, 49 a

θ = θi − 1+

B

(1)

C HNP

By linearizing Equation (1), a straight line relationship between CHNP /( θi − θ) and CHNP can be obtained: C HNP = AC HNP + B θi − θ

A=

(2)

1 a

where θi is the initial contact angle without nano-treatment, CHNP is the hybrid NP concentration; a and A are constants that are related to the maximum change in θ , and B is a constant that is similar

to the Langmuir constant in the Langmuir isotherm. The fitting results of Equations (1) and (2) to the experimental data are shown in Figure 14 and Table 2. The values of constants A and B were determined using the slope and intercept of the straight lines, respectively. Figure 14 and Table 2 (with high values of the correlation coefficient R2) demonstrate that the model can accurately predict the measured θ values at different hybrid NP concentrations. To further evaluate the reliability of the model, the average error percentage (AEP), variance tables, and residual analysis were utilized.50,51 The calculated AEP and variance tables are shown in Table 3, and the residual plots for the contact angles are shown in Figure 15.


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NF type SiO2 Al2O3 TiO2 SiO2+Al2O3 SiO2+TiO2 Al2O3+TiO2

Table 2. Regression analysis results for Equation (2) Coefficient Standard Lower Coefficient Upper 95% value error 95% -5 -6 -6 B 1.94×10 6.84×10 -2.4×10 4.11×10-5 -5 A 0.00745 4.05×10 0.0073 0.0076 B 2.33×10-5 9.26×10-6 -6.1×10-6 5.28×10-5 A 0.00755 5.48×10-5 0.0074 0.0077 -5 B 2.63×10 7.07×10-6 3.78×10-6 4.88×10-5 A 0.00767 4.19×10-5 0.0075 0.0078 -6 B 2.3×10 1.51×10-5 -4.8×10-5 4.85×10-5 A 0.00757 8.94×10-5 0.0073 0.0079 -6 -5 -5 B 2.46×10 1.14×10 -3.4×10 3.88×10-5 -5 A 0.00764 6.76×10 0.0074 0.0079 1.1×10-5 -3.5×10-5 3.56×10-5 B 5.4×10-6 A 0.00771 6.53×10-5 0.0075 0.0079

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R2 0.9999 0.9998 0.9999 0.9996 0.9998 0.9998

Table 3. Calculated AEP and variance tables for the regression analysis of contact angle data at different NP concentrations. Degrees of NF type Source Squares Mean squares F AEP (%) freedom -6 -6 Regression 1 3.08×10 3.08×10 -10 SiO2 33842.06 2.15 Residual 3 2.73×10 9.1×10-11 Total 4 3.08×10-6 Regression 1 3.16×10-6 3.16×10-6 -10 Al2O3 18970.2 3.08 Residual 3 1.67×10-10 5×10 -6 Total 4 3.16×10 Regression 1 3.27×10-6 3.27×10-6 TiO2 33598.77 2.98 Residual 3 2.92×10-10 9.72×10-11 -6 Total 4 3.27×10 Regression 1 3.18×10-6 3.18×10-6 -9 SiO2+Al2O3 7178.54 3.68 Residual 3 1.33×10 4.43×10-10 -6 Total 4 3.18×10 Regression 1 3.24×10-6 3.24×10-6 -10 SiO2+TiO2 12759.17 2.87 Residual 3 2.54×10-10 7.61×10 -6 Total 4 3.24×10 Regression 1 3.3×10-6 3.3×10-6 -10 Al2O3+TiO2 13948.65 2.90 Residual 3 7.09×10 2.36×10-10 Total 4 3.3×10-6


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Figure 15. Residual plots of the NFs: (a) SiO2 nanofluid, (b) Al2O3 nanofluid, (c) TiO2 nanofluid, (d) SiO2+Al2O3 nanofluid, (e) SiO2+TiO2 nanofluid, and (f) Al2O3+TiO2 nanofluid.

It can be seen from Table 3 that the AEP values between the model and experimental data are 2.15 %, 3.08 %, 2.98 %, 3.68 %, 2.87 % and 2.90 % for the SiO2, Al2O3, TiO2, SiO2+Al2O3, SiO2+TiO2 and Al2O3+TiO2 nanofluids, respectively. In addition, considering the significance level of 0.05, the critical value Fc =F(1,3) = 10.13. The calculated F values are 33842.06, 18970.2, 33598.77, 7178.54, 12759.17, and 13948.65, which are much greater than 10.13, thus confirming the fairly good fit of the model. As shown in Figure 15, the residual data for θ values at different concentrations are randomly dispersed along the x-axis, which implies that there is a good agreement between the calculated θ values obtained by the model and the experiments. Overall, the results confirmed the suitability of the model to describe the experimental data. 3.2.3 Effect of exposure time ACS Paragon Plus Environment 26

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Figure 16a presents the measured θ values at different exposure times. For all the HNFs measured, the curves are characterized by an earlier relatively dramatic decrease in ߠ followed by a slower decline rate. Thus, the wettability shift caused by HNFs mainly takes place at the early stage of HNF contact (more than two-thirds of the reduction in ߠ occurs after approximately 1 h). Taking the SiO2+Al2O3 nanofluid as an example, ߠ continually decreased for 1 h of exposure time, and then there was no significant reduction in ߠ upon further exposure (ߠ was reduced by 122° after 1 h and by an additional 13° after a further 5 h).

Figure 16. Experimental data and predicted values at different exposure times obtained by the model: (a) Equation (4) and (b) Equation (5).

Mechanistically, because the wettability alteration of rock surfaces is caused by the continuing


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adsorption of hybrid NPs, a longer contact time leads to a lower ߠ. However, after 6 h, no more incremental reduction in ߠ was noticed, implying that the surface reached its adsorption capacity. To describe the behavior of the ߠ change with time, an adsorption kinetics model was applied as follows: 49,52 d (θ i − θ t ) 2 = k ( c − (θ i − θ t ) ) dt

(3)

The solution to Equation (3) can be obtained with the boundary conditions θt = θi at t = 0 and θt = θt at t = t:

θt = θi −

t t D+ c

(4)

According to Equation (4), a straight line relationship between t/( θi −θt) and t can be developed:

t = Ct + D θi − θ t C=

(5)

1 c

where θt is the contact angle at time t; k is the rate constant, h−1; c and C are constants that are related to the maximum change in ߠ; and D is a constant that is related to k (k = C2/D). To evaluate this model, the experimental data was fitted by Equations (4) and (5) (Figure 16). The model parameters determined by regression analysis are listed in Table 4. As shown in Table 4, The R2 values are 0.9999, 0.9998, and 0.9998 for the SiO2+Al2O3, SiO2+TiO2, and Al2O3+TiO2 nanofluids, respectively, which indicates the good fit of the model. In addition, the calculated k values of the SiO2+Al2O3, SiO2+TiO2, and Al2O3+TiO2 nanofluids are 0.07937 h−1, 0.06159 h−1, and 0.05142 h−1, respectively, which reveals that the constant rate of wettability alteration of the SiO2+Al2O3 nanofluid is higher than those of the SiO2+TiO2, and Al2O3+TiO2 nanofluids.


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HNF type SiO2+Al2O3 SiO2+TiO2 Al2O3+TiO2

Coefficient D C D C D C

Table 4. Regression analysis results for Equation (5) Coefficient Standard Lower 95% Upper 95% value error 0.000674 0.00014 0.000284 0.00106 -5 0.00731 1.78×10 0.00727 0.00736 0.00090 0.00032 1.3×10-5 0.00178 0.00743 4.02×10-5 0.00732 0.00754 0.00108 0.00035 0.000106 0.00206 0.00747 4.5×10-5 0.00734 0.00759

R2

k (h-1)

0.9999

0.07937

0.9998

0.06159

0.9998

0.05142

The corresponding AEP and variance table for ߠ at different exposure times are shown in Table 5. It can be seen from Table 5 that the AEP values between the predicted values and the experimental data are 0.71 %, 1.47 % and 1.47 % for the SiO2+Al2O3, SiO2+TiO2 and Al2O3+TiO2 nanofluids, and that the F values for various HNFs are much greater than the corresponding Fc (7.71). Therefore, the model properly explained the experimental data. Moreover, the residual plots show that the data points are distributed around the x-axis, which confirms that the model is appropriate to describe the θ change with time (Figure 17). Table 5. Calculated AEP and variance tables for the regression analysis of contact angle data at different exposure times. Degrees of HNF type Source Squares Mean squares F AEP (%) freedom Regression 1 0.007855 0.007855 SiO2+Al2O3 Residual 4 1.85×10-7 4.63×10-8 169520.9 0.71 Total 5 0.007855 Regression 1 0.008099 0.008099 Residual 4 9.5×10-7 2.4×10-7 34111.4 1.47 SiO2+TiO2 Total 5 0.008099 Regression 1 0.008190 0.008190 Residual 4 1.2×10-6 2.9×10-7 28051.4 1.47 Al2O3+TiO2 Total 5 0.008190


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Figure 17. Residual plots for the HNFs: (a) SiO2+Al2O3 nanofluid; (b) SiO2+TiO2 nanofluid and (c) Al2O3+TiO2 nanofluid.

3.2.4 Effect of salinity The salinity of heavy oil reservoirs varies significantly, and can directly impact the performance of nanofluid applications.41 Thus, it is necessary to investigate the effect of salinity on the ߠ of sandstone surfaces with different HNFs. To accomplish this goal, the influence of salinity on the wettability change was investigated utilizing experiments conducted in the NaCl concentration range of 0−5 wt%. The experimental results are shown in Figure 18, which indicates that, for all HNFs analyzed, the contact angles decrease with increasing NaCl concentrations. However, the contact angles slightly increase at higher NaCl concentrations. A minimum value for the contact angle exists for each type of HNF. For the SiO2+Al2O3 nanofluid, the contact angle decreases with increasing NaCl concentrations and starts increasing again from 0.5 wt% to 5 wt%. Similar trends were observed for the other HNFs (Figure 18). It is interesting to note that, even under high NaCl concentration conditions, all the HNFs


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still have a great ability to change the wettability of sandstone surfaces to the water-wet state (Figure 18). This result suggests that hybrid NPs have a great potential application in heavy oil EOR where high salinities are likely.

Figure 18. Water contact angles on HNF-treated sandstone surface as a function of salinity.

This aforementioned behavior is related to the stability of the dispersed hybrid NPs. An increase in salinity leads to a decrease in stability (see above), which accelerates the precipitation of hybrid NPs onto the sandstone surfaces. Consequently, increasing the nanofluid salinity improves the wettability alteration efficiency. However, at high salinity, the stability is greatly reduced, which increases the rate of agglomeration among the hybrid NPs and slightly reduces the wettability alteration efficiency. 3.3 Mechanistic study The wettability alteration of oil-wet sandstone by HNFs is likely associated with the adsorption of hybrid NPs on the substrate surface. Monfared and Ghazanfari have demonstrated the adsorption process of single NPs onto stearic acid-modified calcite surfaces49,53 However, the present situation is different because the oil, rock surface and NP types were heavy oil, sandstone, and hybrid NP, respectively. Therefore, in this study, electrokinetic data, DLVO theory as well as SEM analysis were utilized to understand the adsorption processes of hybrid NPs on a heavy oil-modified sandstone surface and reveal the underlying mechanisms for the higher efficiency of HNFs in the wettability shift compared with that of single nanofluids.


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Surface charge controls the amount and extent of the NP adsorption process. Therefore, the zeta potential was measured to determine the surface charges of various NPs, the heavy oil emulsion and the sandstone. In addition, the adsorbate/adsorbent water equilibria were also used to provide insights into the surface charge of the materials. The zeta potentials for the single NPs (SiO2, Al2O3 and TiO2), heavy oil emulsion and sandstone as a function of pH were measured and are presented in Figure 19. The zeta potentials for 0.05 wt% NaCl at a constant pH of 6 are also shown. Figure 19 shows that an increase in the NaCl concentration lowers the absolute value of the zeta potential for various NPs and the heavy oil emulsion and sandstone to some extent. This reduction in zeta potential should be caused by the compression of the double layer.

Figure 19. Zeta potential for the various NPs, the heavy oil emulsion, and the sandstone surface in deionized water and 0.05 wt% NaCl.

Figure 19 also indicates that the sandstone surface is positively charged at low pH values, but gradually becomes negatively charged with an increase of pH values. The iso-electric point (IEP) (the pH at which the net charge of a surface is zero) of the sandstone surface is approximately 2.5. The sandstone surface is the sum of quartz, feldspar, and clay as well as any metal oxide coatings. The surface reactivity of clay often dominates due to its small grain size, high specific surface area, and


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high concentration of unsatisfied bonds at sheet edges. The charge of the sandstone depends on pH, which can be explained by the following reactions: 54 −AlOH2+ ⇋ −AlOH + H+

(6)

−AlOH ⇋ −AlO− + H+

(7)

−SiOH ⇋ −SiO− + H+

(8)

The formation of −Al:SiO− sites (−Al:SiO− is the sum of −SiO− and −AlO−, and the two are combined because they cannot be distinguished individually from sorption experiments) causes the sandstone surface to be negatively charged. When the pH value is reduced, the formation of −AlOH2+ sites (due to the presence of H+ ions) renders the surface charge positive. Figure 19 shows that the charge of the heavy oil emulsion becomes negative from positive at pH 3.0, indicating the presence of basic and acidic surface-active groups at the oil/water interface. A model that considers the zwitterionic nature of the crude-oil/water interface can be used to adequately explain the measured zeta potential and pH relationships for heavy oil:55 AH ⇋ A− + H+

(9)

BH+ ⇋ B + H+

(10)

where A− and BH+ represent acidic and basic groups at the interface. For heavy oil, the main acidic and basic groups are −COO− and −NH+ form carboxylic acids and nitrogen bases. Therefore, the reactions can be expressed as follows:54 −COOH ⇋ −COO− + H+

(11)

−NH+ ⇋ −N + H+

(12)

The negative charge of the interface is caused by the dissociation of carboxylic acids. However, the decrease in pH values increases the −NH+ content, which results in a positive surface charge. The heavy oil used in this study contains enough surface-active components (the asphaltene and resin contents are 7.78 wt%, and 35.86 wt%, respectively). The acid number and base number of the


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heavy oil are 4.95 mg/g and 13.57 mg/g, respectively. Because the surface-active components affect the wettability of the sandstone surface, the high concentration of surface-active components with acidic and basic groups ensures that the sandstone substrate is totally covered, which results in the strongly oil-wet surfaces. The zeta potentials for the SiO2, Al2O3, and TiO2 NPs are also presented in Figure 19. For the SiO2 NP, the IEP is approximately 2.6, which falls in the range of the values reported in the literature (1.6−3.5).56 The zeta potential of SiO2 is negative and decreases from −10.8 mV to −34.7 mV as the pH increases because negative sites are formed via the −SiO− on the SiO2 NP surfaces, which is based on the following reaction: −SiOH + OH− ⇋ −SiO− + H2O

(13)

As a result, the surface charge of SiO2 becomes more negative at basic pH values and the zeta potential decreases. The IEPs for Al2O3 and TiO2 are approximately 9.6 and 6.9 in deionized water, respectively. The surfaces of TiO2 and Al2O3 become more positive as the pH is lowered. However, if the pH is raised, the surface charge becomes more negative. These results are similar to those reported in other studies,57 and they are caused by the following reactions for Al2O3 and TiO2 NPs: MOH + H+ ⇋ MOH2+

(14)

MOH + OH− ⇋ MO− + H2O

(15)

where M represents Al and Ti. Reactions (14) and (15) show that at a lower pH, Al2O3 and TiO2 have a positive surface charge and zeta potential. Conversely, at a pH higher than the IEP, a negative surface charge and negative zeta potential are observed. The measured initial pH of the nanofluids was in the range of 5−7 depending on the NP type and NaCl concentration. Therefore, the Al2O3 and TiO2 NPs are positively charged, and the SiO2, heavy oil and sandstone are negatively charged in the studied pH and salinity ranges (Figure 19). The underlying mechanisms for the higher efficiency of HNFs for the wettability shift and adsorption process were ACS Paragon Plus Environment 34

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conceptually studied based on the electrokinetic data and DLVO theory (Figure 20).

Figure 20. Suggested mechanism for the wettability alteration of oil-wet sandstone using the SiO2+Al2O3 nanofluid: (a) initial state of the oil-wet sandstone surface, (b) interaction between the SiO2 NPs and heavy oil, (c) final state of the adsorption process of the SiO2 NPs, (d) interaction between the SiO2+Al2O3 NPs and heavy oil, and (e) final state of the adsorption process of the SiO2+Al2O3 NPs.

Figure 20a shows the initial state of the oil-wet sandstone surface. The charged species from the oil interface (e.g., NH+) reach the sandstone and then pair with oppositely charged species from the sandstone surface (e.g., −Al:SiO−). Therefore, the heavy oil adsorbs onto the sandstone surface, which leads to the strongly oil-wet condition. The SiO2 nanofluid is used as an example to illustrate the adsorption process of a single nanofluid on the oil-wet sandstone surface. When in contact with water, the surface of SiO2 is negatively charged (Figure 19), which is attributed to the formation of −SiO− sites on the silica surfaces (reaction (8)). When a sandstone oil-wet substrate is immersed in the SiO2 nanofluid, exposed basic groups (e.g., NH+) dangling from the interface attract oppositely charged SiO2 NPs via attractive interactions, resulting in


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the absorption of SiO2 NPs on the sandstone surface (Figure 20b and c). The attachment of particles to surfaces under conditions in which repulsive interactions predominate is termed unfavorable.53 In many aquatic environments, colloids and solid surfaces have a net negative charge and adsorption processes occur under the unfavorable attachment condition.58 Therefore, a competitive adsorption process may occur between SiO2 NPs and acidic groups (e.g., −COO−), whereas the positive species of solution (Na+) forms a complex with acidic groups. Thus, the contribution of positive species helps to release acidic groups and their replacements with anionic surface groups of SiO2 NPs (Figure 20b and c). However, the competitive adsorption process occurs under the unfavorable attachment condition. Therefore, the probability of occurrence is lower in comparison with the adsorption process between oppositely charged basic groups (e.g., NH+) and SiO2 NPs. The SiO2+Al2O3 nanofluid was used as an example and compared with the single nanofluids to reveal the adsorption mechanisms of HNFs. The surface of SiO2 is negatively charged, and the surface of Al2O3 is positively charged. These compounds remain stable in the base fluid via the stabilizer PVP. When an oil-wet substrate is immersed in a HNF, the SiO2 and Al2O3 NPs simultaneously attract oppositely charged sites of the sandstone surface (−COO− and−NH+ groups) (Figure 20d). Therefore, compared with single SiO2 NPs (Figure 20c), the number of NPs and the area occupied by hybrid NPs are significantly increased (Figure 20e). In addition, once the NPs absorb on the sandstone surface by attractive interactions, the following phenomena may occur during the adsorption process (Figure 20d and e): (1) When one type of NP (e.g., SiO2) absorbs on the surface via competitive adsorption, the attractive interaction will aid the competitive adsorption of another type of NP (e.g., Al2O3); (2) the oppositely charged NPs on the sandstone surface will approach each other, which leaves more space for NP adsorption and increases the number of adsorbed NPs and the area occupied by hybrid NPs; (3) certain NPs will absorb on the surface of the absorbed NPs by attractive interactions, which results in an increased adsorption ACS Paragon Plus Environment 36

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thickness for hybrid NPs. In addition to the aforementioned electrostatic interaction, the physical interaction can facilitate hybrid NP absorption. Because hybrid NPs have different shapes and sizes, their interactions lead to a compact and uniform distribution on the sandstone surface and a strong ability to absorb on small rough areas (such as, pores and cracks), where single NPs cannot attach. In addition, compared with single nanofluids, the slight instability of HNFs (Figure 6) accelerates the precipitation of hybrid NPs onto the sandstone surface, which is beneficial for improving the adsorption process. In conclusion, the adsorption of hybrid NPs on the sandstone surface is responsible for altering the wettability toward a water-wet state. Compared with single nanofluids, HNFs increase the probability of competitive adsorption, enlarge the absorption area, and enhance the adsorption thickness due to the electrostatic and physical interactions between hybrid NPs. Therefore, HNFs have a higher wettability shift efficiency compared with single nanofluids. According to the results of the contact angle measurements shown in Figure 13, the wettability shift efficiency for the three types of HNFs is ordered as follows: SiO2+Al2O3 > SiO2+TiO2 > Al2O3+TiO2. This finding is caused by the dependency of Al2O3 and TiO2 NPs with the same charge on physical interactions. Therefore, these NPs have weaker adsorption than NPs with an opposite charge (e.g., SiO2+Al2O3 and SiO2+TiO2). In addition, the higher absolute zeta potential for oppositely charged NPs can generate greater attractive forces between hybrid NPs, which explains why the SiO2+Al2O3 nanofluid has a higher wettability shift efficiency than the SiO2+TiO2 nanofluid. Therefore, the suggested mechanisms can well explain the results of the contact angle measurements. To further confirm the suggested mechanism and interpret the observed wettability alteration processes caused by HNFs, the sandstone substrates were measured before and after treatment with SiO2+Al2O3, SiO2 and CuO nanofluids via SEM techniques. During the processes, SEM images were taken from different points in each sandstone substrate at different magnifications to better describe the morphology of the substrates and the NP distribution on the substrates. ACS Paragon Plus Environment 37

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The images in Figure 21 show the morphology of two different regions in a sandstone substrate after aging in the oil at different magnifications. It can be observed that the surface of the sandstone substrate is relatively smooth and covered with an oil film. There are only a few small rough areas, such as pores, cracks, and dust particles, on the surface (Figure 21).

Figure 21. SEM images of two regions on an untreated sandstone substrate surface at different magnifications.

Figure 22 presents the SEM observations of nanofluid-treated sandstone surfaces. Compared to the images of the substrate after aging in oil (Figure 21), the presence of a NP layer on the substrate surface is clearly observed. Different magnifications of SEM images at different points in each sandstone substrate confirm the adsorption of NPs on the surfaces of the sandstone substrate, and this absorption is responsible for the wettability change as observed by contact angle measurements. It is noted that a high surface density of NPs can be observed on the relatively smooth surface (region 1 shown in Figure 22a and Figure 22c). The existence of a small amount of roughness on the surface adversely affects the


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adsorption of NPs (region 2 shown in Figure 22a and Figure 22c).


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Figure 22. SEM images of different regions on nanotreated sandstone substrate surfaces at different magnifications: (a)

SiO2+Al2O3-treated sandstone surface, (b) SiO2-treated sandstone surface, and (c) CuO-treated sandstone surface.

A comparison of the images in Figure 22 obviously shows that the substrates treated with different NPs have different structural morphologies. SiO2 NPs display a regular particle shape on the substrate surface (Figure 22b), and the sizes of the nanodots are uniform and consistent with the size measured via TEM as presented in Figure 1a. However, the SiO2+Al2O3 NPs approach each other and form larger clusters with a larger surface size (Figure 22a). In addition, the thicker adsorption layer of the SiO2+Al2O3 NPs is observed at the surface because the NPs absorbed to the surface by attractive interactions are covered by NPs. Therefore, compared with the substrate treated with the SiO2 nanofluid, a higher surface density of SiO2+Al2O3 NPs can also be observed in different regions on the oil-wet sandstone substrate (Figure 22a). The adsorption phenomena shown in the SEM images are consistent with the results obtained using electrokinetic data and DLVO theory (Figure 20c and e). A comparison of the substrates treated with the SiO2, SiO2+Al2O3, and CuO nanofluids (Figure 22c) showed that the surface density of the CuO nanofluids is low at certain locations and that oil traces are ACS Paragon Plus Environment 40

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still observed on the oil-wet substrate because of the severe instability of the CuO nanofluid. The higher rate of agglomeration and sedimentation among the CuO NPs greatly reduces the surface density of CuO NPs on the oil-wet sandstone substrate. In conclusion, the SEM image results are consistent with the stability analysis and contact angle measurements. 4. CONCLUSIONS (1) The nonionic surfactant PVP shows better positive effects than SDS and PEG on the dispersion and stability of HNFs. (2) For all HNFs tested, the HNF stability decreases with increasing hybrid NP concentration, salinity and temperature. However, the HNF stability with a low hybrid NP concentration, NaCl concentration, and temperature is still at an acceptable level. (3) The SiO2+Al2O3 nanofluid achieved the highest reduction in ߠ (from 156° to 21°), indicating a significantly higher wettability alteration efficiency. The low concentration makes it feasible and economically attractive for enhancing heavy oil recovery. (4) The efficiency of HNFs for a wettability shift was improved by adding a nonionic surfactant and increasing the hybrid NP concentration, salinity, and exposure time. However, beyond a certain value for the concentration, salinity, or exposure time, the efficiency slightly decreased due to the instability of the HNFs. (5) The two models can accurately describe the change in the contact angles with hybrid NP concentration and exposure time. The constant rate of wettability alteration of the SiO2+Al2O3 nanofluid is 0.07937 h−1, which is higher than those of the SiO2+TiO2, and Al2O3+TiO2 nanofluids. (6) The stronger adsorption of the hybrid NPs on the sandstone surface was considered the mechanism underlying the higher wettability shift efficiency of HNFs compared with single nanofluids. The mechanism was verified via investigations of the surface equilibria and interactions between different species in the system. In addition, the SEM visualization provided objective verification in support of the proposed mechanism. ACS Paragon Plus Environment 41

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ACKNOWLEDGMENTS This work was financially supported by the National Natural Science Foundation of China (No. 51604293), Shandong Provincial Natural Science Foundation, China (No. ZR2016EEB30), the Fundamental Research Funds for the Central Universities (No. 17CX02009A), Qingdao Applied Basic Research Program (No. 17-1-1-32-jch), Scientific Research Foundation of China University of Petroleum for Talent Introduction (No. YJ201601093) and National Science and Technology Major Project (2016ZX05031-002). REFERENCES (1) Jiang, T.; Zeng, F.; Jia, X.; Gu, Y. A new solvent-based enhanced heavy oil recovery method: cyclic production with continuous solvent injection. Fuel 2013, 115(1), 426-433. (2) Mohammadi, S.; Ghazanfari, M. H.; Masihi, M. A pore-level screening study on miscible/immiscible displacements in heterogeneous models. J Petrol Sci Eng 2013, 110(5), 40-54. (3) Soh, Y.; Shokri, A. R.; Babadagli, T. Optimization of methane use in cyclic solvent injection for heavy-oil recovery after primary production through experimental and numerical studies. Fuel 2018, 214, 457-470. (4) Zhang, Z.; Liu, H.; Dong, X.; Jiang, H. A new mathematical model to understand the convective heat transfer mechanism in steam assisted gravity drainage process. J Therm Sci Eng Appl 2018, 10(1), 011006. (5) Sun, X.; Dong, M.; Zhang, Y.; Maini, B. B. Enhanced heavy oil recovery in thin reservoirs using foamy oil-assisted methane huff-n-puff method. Fuel 2015, 159, 962-973. (6) Sun, X.; Zhang, Y.; Cui, G.; Duan, X.; Zhao, C. Feasibility study of enhanced foamy oil recovery of the orinoco belt using natural gas. J Petrol Sci Eng 2014, 122, 94-107. (7) Sun, X.; Zhang, Y.; Chen, G.; Gai, Z. Application of nanoparticles in enhanced oil recovery: a critical review of recent progress. Energies 2017, 10(3), 345.


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