Synergistic Effect of Silica Nanoparticles and Rhamnolipid on

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Synergistic Effect of Silica Nanoparticles and Rhamnolipid on Wettability Alteration of Low Permeability Sandstone Rocks Di Wang, Shanshan Sun, Te Sha, Tongjing Liu, Honghong Dong, Kai Cui, Hailan Li, Yejing Gong, Jirui Hou, Zhongzhi Zhang, and Pengcheng Fu Energy Fuels, Just Accepted Manuscript • DOI: 10.1021/acs.energyfuels.8b01207 • Publication Date (Web): 18 Jul 2018 Downloaded from http://pubs.acs.org on July 19, 2018

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Energy & Fuels

Synergistic Effect of Silica Nanoparticles and Rhamnolipid on Wettability Alteration of Low Permeability Sandstone Rocks Di Wang, Shanshan Suna,* Te Sha, Tongjing Liub, Honghong Dong, Kai Cui, Hailan Li, Yejing Gong, Jirui Hou b, Zhongzhi Zhang a, Pengcheng Fuc,* a

State Key Laboratory of Heavy Oil Processing, China University of Petroleum,

Beijing, 102249, P. R. China b

Research Institute of Enhanced Oil Recovery, China University of Petroleum, Beijing,

P. R. China c

State Key Laboratory of Marine Resource Utilization in South China Sea, Hainan

University, Hainan 570228, P.R. China

1

ACS Paragon Plus Environment

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ABSTRACT Wettability modification is one of the main mechanisms to increase oil recovery from low-permeability oil reservoirs. Nanofluids composed of nanoparticles can be used as modifiers to alter wettability from oil-wet to water-wet condition thus to promote hydrocarbon recovery. Biosurfactants, which are candidates to replace synthetic surfactants for industrial applications, have the potential to prepare nanofluids. In this study, nanofluids prepared by dispersing SiO2 nanoparticles in rhamnolipid solution (hereby named bionanofluids) were considered potential wettability modifiers to apply to petroleum recovery from low-permeability sandstone reservoirs. Analyses via visual observation, optical absorbance measurement, ζ-potential determination, and particle size measurements demonstrated that the bionanofluids with 25 ppm rhamnolipids maintained an optimal stability. The effect of bionanofluids on wettability alteration was investigated through contact angle measurement and imbibition test. The results showed that bionanofluids could alter the wettability of oil-wet sandstone to strongly water-wet. The best performance was achieved with a nanoparticle concentration of 1000 ppm. Additionally, a micromodel test using rhamnolipid solution and bionanofluid was carried out to evaluate the synergistic effects of SiO2 nanoparticles and rhamnolipid on displacing oil. Bionanofluid injection following biosurfactant flooding was shown to improve oil recovery, yielding an additional 5% production. These results reveal that the bionanofluid prepared with SiO2 and rhamnolipids not only remained stable but also provided a potential way for enhanced oil recovery.

Keywords: wettability, biosurfactants, SiO2 nanoparticles, low-permeability, sandstone 2


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1. INTRODUCTION Most of the world’s high-quality reservoirs have begun showing depletion in oil recovery while the demand for petroleum products is increased. As a result, low-permeability reservoirs have become an important part of energy supply.1 With the characteristics of small pore size and complex strata structure, it is not only challenging but also potentially costly to recover petroleum from such reservoirs.2,3 The wettability of the rock matrix is an important parameter to determine oil production from low-permeability reservoirs.4 The oil-wet and low-permeability properties of reservoirs reduce the oil displacement efficiency and sweep efficiency of injected fluid. Therefore, recovering crude oil through spontaneous imbibitions is difficult when the rock matrix remains saturated with residual oil.5-7 In summary, altering the wetting condition of the rock matrix from an oil-wet to water-wet state is an important direction for enhancing oil recovery.8 In recent years, many reports have proposed that nanoparticles offer support for future enhanced oil recovery processes and silica-based nanoparticles have attracted many researchers demonstrating their potential application in energy sectors.9-11 Nanoparticles with diameters ranging from 1 nm to 100 nm can flow through low-permeability reservoir pore spaces.12 Dispersing small volumetric fractions of nanoparticles into a liquid phase allows researchers to design nanofluids that can improve fluid properties. Several studies have shown that nanofluids have promising abilities for altering the wettability of solid surfaces. Giraldo et al.4 studied the application of alumina-based nanofluids as potential wettability modifiers for changing the wettability of sandstone cores from oil-wet to water-wet condition via contact angle measurements and spontaneous imbibition tests. Bayat et al.13 3


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investigated enhanced oil recovery from limestone media by various nanoparticles, including Al2O3, TiO2, and SiO2 at several temperatures (26, 40, 50 and 60 °C). Ju et al.9 explored the wettability and permeability alterations caused by adsorption of hydrophilic SiO2 nanoparticles. Al-Anssari et al.8 examined the influence of silica nanoparticles on the wettability of oil-wet calcite. Moreover, the effect of silica nanofluid on wettability of subsurface formation at high temperature and pressure condition was further analyzed.14,15 Sofla et al.16 studied the stability of hydrophilic silica nanoparticles in seawater for enhanced oil recovery. Yu et al.17 reported that the assembly of nanoparticles at interfaces could significantly lower interfacial tension and enhance oil recovery. Zhang et al.18 were the first to investigate the effect of nanoparticles on fluid flow and oil displacement in porous media using advance micro-visualization. In addition, researchers have suggested that the structural disjoining pressure is a significant mechanism for the development of crude oil from reservoirs via nanoparticles.19-23 Recently, some researchers have proposed that the effectiveness of surfactants on wettability alteration could be increased by adding nanoparticles.24-27 Zargartalebi et al.26,27 utilized hydrophilic and hydrophobic silica nanoparticles to alter anionic surfactant properties and enhanced surfactant flooding performance with silica nanoparticles. Nwidee et al.28 explored the wettability alteration of oil-wet limestone using surfactant-nanoparticle formulation. Kuang et al.29 prepared the nanofluids by dispersing three nanoparticles (i.e., SiOx, Al2O3, and TiO2) and five chemical agents (i.e., oleic acid, polyacrylic acid, a cationic, an anionic, and a nonionic surfactant) in base brine solutions for enhanced oil recovery. Moreover, stabilization of oil-in-water emulsions could be improved by mixing surfactants and SiO2 nanoparticles.30 Potential advantages of biosurfactants relative to chemically synthesized surfactants 4


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include their unusual structural diversity that could lead to unique properties such as: biodegradability, higher selectivity, low toxicity, possible cost-effective production, and stable activity under extreme environments.31,32 The application of rhamnolipid as a new agent for bioremediation and oil recovery has been investigated.33,34 In spite of some studies on the use of nanoparticles for surfactants flooding, there is very little data about any synergistic effect between nanoparticles and biosurfactants for wettability alteration of low-permeability reservoirs and there is a serious lack of data with respect to nanoparticle synergisms with biosurfactants for enhanced oil recovery. In the present study, nanoparticles were dispersed in base fluids containing rhamnolipids to prepare bionanofluids that alter the wettability of sandstone rock for enhanced oil recovery. The synthesis, characterization, and application of these nanofluids are described in detail. The optimum particle concentration was determined from our experimental results. The performance of bionanofluid was compared with that of rhamnolipid solution and SiO2 nanofluid flood schemes for enhanced oil recovery efficiency in micromodel flooding experiments. To the best of our knowledge, this is one of the first attempts to analyze nanoparticle synergisms with biosurfactants for wettability alteration of low-permeability sandstone. 2.

MATERIALS AND METHODS

2.1. Materials. The utilized unmodified nanoparticles used to prepare the bionanofluids were hydrophilic SiO2 nanoparticles with the average size of 10~20 nm (purity, 99.5%) provided from Aladdin Reagent Co., Ltd., China. As shown in the scanning electron microscope (SEM) image (Figure S1), the SiO2 nanoparticles are observed in the form of white powder. Density and specific surface area of the particles are 2.2~2.6 g/cm3 and 180~270 m2/g, respectively. Rhamnolipid, comprised of Rha-C10C10 and 5


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Rha-Rha-C10C10, was purchased from Huzhou Zijin Biotech Company (China). It is an anionic surfactant. The critical micelle concentration (CMC) and molecular weights of rhamnolipid are 25 ppm and 600 g/mol, respectively. Crude oil from a reservoir located in Changqing oil field (China) was used as the oil phase in experiments. The density of the oil was measured as 0.914 g/cm3, and its viscosity was approximately 82.5 mPa·s at 25 °C. The flash point and boiling point of the crude oil were 70~90 °C and 300~400 °C respectively. Deionized water (conductivity = 0.02 mS/cm) was used in all experiments. Berea sandstone cores with average permeability equal to 50 mD were utilized as low-permeability rock matrix. 2.2. Preparation and Characterization of Nanofluids. In this study, three concentrations (12.5, 25, and 50 ppm) of rhamnolipids and five concentrations (100, 500, 1000, 5000, and 10000 ppm) of SiO2 nanoparticles were tested to characterize the bionanofluids. Nanoparticles were added to rhamnolipid solution to obtain utilized bionanofluids. The bionanofluids were subjected to a magnetic stirring treatment and then sonicated 15 times at 450 W for 1 min with 1 min rest to prepare a homogeneous and uniform nanoparticle suspension. The highest temperature of the system reached to 48 °C that couldn’t impact the properties of the rhamnolipid. To ensure the stable performance of the bionanofluid during the experiments, the stability of the prepared nanofluid was investigated. Settlement and aggregation of nanoparticles in the aqueous phase were investigated through visual observation and ultraviolet-visible (UV-vis) absorbance spectroscopy respectively,35,36 the effective diameter and ζ-potential were measured by Malvern Zetasizer Nano zen3600. 2.3. Surface Modification of Sandstone Core. To perform contact angle measurements, a number of substrate slides of 5 mm 6


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thickness were cut from the sandstone core plugs using a trimming machine and then burnished with fine sandpaper to achieve a relatively smooth surface. Before further experimentation, the investigated slices were cleaned by Soxhlet extraction with toluene vapor to remove organic impurities and then washed in deionized water followed by oven drying at 40 °C. The unmodified sandstone surfaces were water-wet. To alter the wetting tendency of substrate surfaces to an oil-wet state, twenty slice samples were completely submerged in the crude oil for 7 d at 70 °C each time. The volume radio between the treated samples and the crude oil was 1:5. This process induced asphaltene precipitation and adsorption from the crude oil on the utilized core slices. After this aging process, the oil-wet substrates were washed with n-heptane and deionized water and then dried at 40 °C for 24 h. 2.4. Wettability Alteration Using Nanofluids. To investigate the potential of nanofluids for altering the wettability of sandstone surfaces, methods of both equilibrium and transient analysis were applied to measure contact angles on said surfaces. In the equilibrium tests, the oil-wet substrates were hung vertically with a thin thread and immersed in previously prepared bionanofluids with five different nanoparticle concentrations, ranging from 100 ppm to 10000 ppm, at ambient temperature for 48 h, followed by flashing process with deionized water and drying at 40 °C for 12 h. The flashing process could remove the reversibly adsorbed nanoparticles and thus the experimental results were credible. The procedure was also performed with pure rhamnolipid solution. The mechanisms and motive forces for nanoparticles adsorption on sandstone surfaces are complicated. In general, adsorption of nanoparticles is the combine force of Brownian motion and the electrostatic interaction between the migrating particles and the solid surface that causes the particles to cling to the rock surface. The high surface area of the 7


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nanoparticles plays an important role in the adsorption process as it increases the surface energy of the nanoparticles.37 In addition, Yu et al. argue that the presence of clay in sandstone enhance SiO2 nanoparticle adsorption.38 In order to understand the effect of treatment duration on the wettability alteration of sandstone surfaces treated with nanofluids, transient analyses were performed. Twelve oil-wet core slices were immersed vertically in bionanofluid with the definite nanoparticle concentration of 1000 ppm, and then core samples were removed for analysis at suitable time intervals. 2.5. Contact Angle Measurement. Contact angle was the first criterion used to evaluate the potential of nanofluids for wettability alteration of substrate surfaces. For this purpose, two methods of contact angle measurements (air phase and water phase) were applied as followed: (1) a droplet of water was placed onto the surface of the dried samples directly. (2) Samples were submerged in deionized water and then an oil droplet was released and captured below the treated substrates using an inverted syringe. The side images of drops (water and oil) were captured using a high-resolution camera and then the contact angle was estimated by visual image analysis software (FTA32 vedio2.1, Linseis, Figure S2). The processes were repeated three times to ensure the obtained results reliable. 2.6. Spontaneous Imbibition Tests. In addition to contact angle measurement, spontaneous imbibition tests were used to evaluate the performance of nanofluids for altering wettability. Two methods for measuring the amount of imbibed water and displaced oil were applied in spontaneous imbibitions tests. The first method was carried out by hanging a nano-treated slice sample under an electronic balance with the sample immersed in distilled water. With 8


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the imbibition of water into the core slice, the accumulated weight was recorded as a function of aging time until remaining constant. As a control, an oil-wet core slice without nanofluid treatment was used for comparison to the results of previous experiments. The second method to evaluate the oil recovery during spontaneous imbibitions tests was performed utilizing Amott-Harvey cells. The Amott-Harvey cell is a visual glass cell with a graduated tube on the top. Low-permeability cores aged by petroleum were cut into columns with a length and diameter of 5.0 and 2.5 cm, respectively, and then placed into the cell filled with nanofluids for a period of time. As the nanofluid imbibed into the sandstone core sample, the expelled oil from the core could be captured in the graduated tube, accurately measuring the amount of expelled oil. This experimental setup was maintained at 50 °C, and the oil recovery (% of original oil in place, OOIP) was monitored at appropriate intervals. In this set of experiments, the spontaneous imbibitions tests were conducted for both bionanofluid and pure SiO2 nanofluid. 2.7. Micromodel Experiments. A glass micromodel, with average diameter of pores being 20~40 µm, simulating the complex reservoir pore distribution is convenient for researchers to study enhanced oil recovery at the pore scale. This micromodel can be used to observe directly the fluid flows in porous media and thus analyze phase displacement mechanisms. In the present study, micromodel flooding experiments were conducted to identify the displacement mechanisms for improving oil recovery after nanofluid flooding. During the experimental process, the potential of the nanofluids for efficient oil displacement was evaluated by determining crude oil recovery and the change in oil distribution in the model. 9


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According to the previous studies, the etched glass model was prepared as an adaptation of the manufacture method devised by Dawe and Grattoni,39 channels with different sizes were distributed in the model to generate a heterogeneous porous medium. The micromodel is consisted of two glass plates. One is an etched plate, with another fine cover glass plate annealed over the etched pattern on the facing glass plate in an oven with a temperature cycle reaching a maximum of 700 °C. During the preparation, the glass micromodel was washed with dichloromethane and deionized water, and then burned in a muffle furnace at 500 °C for 2 h to remove organic residues followed by cooling to ambient temperature. The first experiment performed with this apparatus was waterflooding followed by rhamnolipid solution flooding with the procedure as follows: (1) saturating the porous model with deionized water, (2) displacing the injected fluid with crude oil until water was no longer produced, (3) flooding water for 10 PV (pore volume), (4) injecting the rhamnolipid solution (25 ppm) for 1 PV into the visual micromodel, and (5) resuming water injection for 10 PV. The comparative experiment was waterflooding followed by bionanofluid flooding, following an identical procedure but substituting rhamnolipid solution with the bionanofluid. The bionanofluid in the previous experiment utilized rhamnolipid and SiO2 nanoparticles with the concentration of 25 ppm and 1000 ppm, respectively. This system consisted of an inverted microscope for observing the distribution of crude oil in the micromodel before and after fluid flooding. A constant flow pump was used to inject fluids at low rates. A camera was placed above the micromodel for capturing images at defined time intervals. During these experiments, the injection rate was 0.005 mL/min, which approximates laminar fluid flow in porous media. From a review of the literature, micromodel tests are noted as a cornerstone of 10


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fundamental studies for enhanced oil recovery, allowing for qualitative observations, quantitative analyses and theoretical development of transport phenomena. Furthermore, there are many additional advantages to micromodel tests, such as clearly visible results, short-time testing, and ability to easily model different porous patterns. 3. RESULTS AND DISCUSSION In this section, we first present the results for determination of the dispersion stability of the bionanofluids utilizing different methods including: visual observation, optical absorbance measurements, ζ potentials and particle size measurements.35 Next, we discuss the wettability alteration of sandstone surfaces investigated via contact angle measurements and spontaneous imbibitions tests. Finally, we present the results of the micromodel flooding experiments using bionanofluid and conventional injection fluid. 3.1. Nanofluid Stability. To investigate the stability of nanofluids with various SiO2 concentrations, visual observation and UV-vis absorbance spectra analysis were performed.35 These experiments were conducted for three particle concentrations of 500, 1000, and 5000 ppm and at rhamnolipid concentrations of 0, 12.5, 25, and 50 ppm. Figure 1 outlines the visualization of nanofluid stability and particle sedimentation monitored over 10 days. In general, instability was enhanced with increasing nanoparticle concentration. No detectable sedimentation was observed in the 500 ppm nanoparticles over the tested range of rhamnolipid concentrations. However, the 1000 ppm nanoparticles exhibited visual instability within the bionanofluids treated with 50 ppm rhamnolipids after 7 days. Significant destabilization was observed in the bionanofluid with 12.5 ppm rhamnolipids on day 10. At the nanoparticle 11


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concentration of 5000 ppm, the first visual evidence of destabilization was noted in the bionanofluid with 50 ppm rhamnolipids on day 5. The nanofluids with rhamnolipid concentrations of 12.5 and 25 ppm remained stable for 7 and 10 days, respectively. Satisfactory stability was observed at the rhamnolipid concentration of 25 ppm during this experiment because particle sedimentation was undetected at the different nanoparticle concentrations. 500 ppm

1000 ppm

5000 ppm

1d

5d

7d

10d

Figure 1. Visual observation of bionanofluids at different nanoparticle (500, 1000, 5000 ppm) and rhamnolipid concentrations (0, 12.5, 25, and 50 ppm) after 1, 5, 7, and 10 days. Visual observation alone is insufficient to determine the stability of nanoparticles because the aggregation of nanoparticles may occur at nanoscale which cannot be 12


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visually determined.36 UV-vis absorbance spectroscopy analysis was performed as shown in Figure 2 to analyze particle aggregation in the nanofluids. In accordance with the research by Metin et al.,35 this experiment was conducted at the analytical wavelength of 400 nm. Based on the previous results, the nanofluid samples were prepared with different concentrations of SiO2 nanoparticles (500, 1000, 5000 ppm) and rhamnolipids (12.5, 25, 50 ppm) to ensure completeness of the determined stability for the UV-vis adsorption curve. In Figure 2a, the nanofluids with 500 ppm nanoparticles were considered stable at all rhamnolipid concentrations because of the nonsignificant change in absorbance value. However, Figure 2b illustrates that the UV-vis absorbance curve of bionanofluid with the nanoparticle concentration of 1000 ppm began to increase on day 6 at the rhamnolipid concentration of 50 ppm. This result indicates the aggregation of nanoparticles, considered a standard occurance for nanofluid destabilization (Figure S3). As shown in Figure 2c, the nanofluids with particle concentrations of 5000 ppm presented poor dispersion stability. Thus, the optimal rhamnolipid concentration for maintaining bionanofluid stability is 25 ppm. The results of this analysis demonstrate that the stability of the bionanofluid used for subsequent experiments was related to the following factors: nanoparticle concentration, rhamnolipid concentration, and processing time.40,41

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Figure 2. UV-vis absorption at 400 nm wavelength of bionanofluids in terms of rhamnolipid concentration and time: (a) 500 ppm; (b) 1000 ppm; (c) 5000 ppm. CMC indicates the critical micelle concentration of rhamnolipids (25 ppm). 14


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According to the above results, nanofluids at 5000 ppm and 10000 ppm are opaque. The size distribution and ζ-potential of the bionanofluid for 1000 ppm SiO2 nanoparticles were measured. The optimal ζ-potential of the bionanofluid with 25 ppm rhamnolipid concentration was −35.6 mV, which is acceptable for phase stability. The average diameter of nanoparticles (~150 nm) was less than 1/10 of the average size of the sandstone pores in this experiment, preventing the nanoparticles from plugging the rock pores.4 3.2. The Analysis of Rhamnolipid Effect on Bionanofluid Stability. A possible scheme for the interaction between SiO2 nanoparticles and rhamnolipids is demonstrated in Figure 3. The two adsorption paths depended on rhamnolipid concentration. Songolzadeh et al.40 and Al-Anssari et al.42 have introduced similar figures in early years. They utilized chemical surfactants to analyze the stability of nanoparticles in saline environments. As shown in Figure 3a, as these nanoparticles are negatively charged because of the hydroxyl group on the surfaces, they attempt to repel from anionic surfactants.40 The rhamnolipid molecule rotates from the effect of electrical repulsion, and the hydrophobic tail may then adsorb on the surface due to high surface energy. As the surfactant concentration increase, rhamnolipid adsorption continues until the surfactant saturates the nanoparticle surface. Figure 3b indicates concentrations that are higher than the rhamnolipid critical micelle concentration (CMC), where the surfactant molecules prefer to form micellar structures via their hydrophobic tail and escape from the nanoparticle surface. The micellar structure with negative charges attempts to repel nanoparticles, which inhibits the effective coagulation of the nanoparticles.

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Figure 3. Schematic of rhamnolipid adsorption to SiO2 nanoparticles. (a) Concentration lower than the CMC; (b) concentration higher than the CMC. 3.3. Contact Angle on Sandstone Surfaces Treated by Nanofluid. We performed contact angle measurements and spontaneous water imbibitions to evaluate the ability of the bionanofluids to alter the wettability of sandstone surfaces. Figure 4a shows the static contact angles before and after nanofluids treatment of the water/air/rock system as functions of nanoparticle concentration, thus evaluating the ability of the designed bionanofluids in altering the wettability of oil-wet sandstone surfaces. According to Anderson et al.,43 a measured contact angle in the range of 0°~75° for a water droplet can be considered water-wet state, 75°~105° demonstrates intermediate wet, and 105°–180° indicates oil-wet state. The contact angle of the water droplet placed on the untreated sandstone surfaces ranged from 128° to 138°(＞ 105°) which indicated that the wettability of untreated samples were oil-wet state. When rhamnolipids were used as the wettability modifier, the contact angle of the oil-wet surfaces changed from 128° to 77°. With the addition of SiO2 nanoparticles 16


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(100 ppm), the contact angle of the water droplet decreased from 138° to 49°. The nanoparticles modification thus enhanced wettability reversal. In addition, the ability of the bionanofluid to change wettability was improved as the nanoparticle concentration was increased. A major decrease in the contact angle value to 31° was achieved by 1000 ppm nanoparticle bionanofluid, illustrating the wettability alteration from oil-wet to water-wet condition at a relatively low nanoparticle concentration. Figure 4b illustrates the effect of aging time on the wettability alteration through the changes of contact angle values in the air/water/rock system over different time intervals, revealing the transient behavior of the bionanofluid 1000 ppm concentration. For the 1000 ppm bionanofluid, a minimum of 24 h is required to alter wettability from oil-wet to water-wet condition, reaching a final stable contact angle. The main change in wettability of oil-wet sandstone toward water-wet sandstone occurred at the initial stage of the experiment, as inferred from the curve variation in Figure 4b. In summary, the previous experimental results are fundamental for investigating the capability of bionanofluids to alter the wettability of mineral surfaces within practical time scales.

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Figure 4. Results of contact angle measurement: (a) alteration of contact angle of oil-wet surfaces before and after treatment with bionanofluids at concentrations ranging from 100 ppm to 10000 ppm; (b) contact angle alteration vs. time when 18


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treated by 1000 ppm bionanofluids. The notation BIO-x indicates the continuous phase (biosurfactant) and the nanoparticle concentration used in ppm. Wettability conditions could be estimated for several systems to confirm the ability of the bionanofluid to alter wettability.44 As shown in Figure S4a,b, the contact angles of the original plates in air/water/rock and water/oil/rock systems were approximately 130° and 21°, respectively, implying a strong oil-wet condition. However, Figure S4c,d shows that the air/water and oil/water contact angles on the rock surfaces treated with the 1000 ppm bionanofluid for 48 h were 25° and 132°, respectively, indicating a strong water-wet condition. 3.4. Spontaneous Imbibition Tests. In addition to contact angle measurement, spontaneous imbibition tests were also conducted to evaluate the performance of the nanofluids in altering wettability. A main difference is the area of rock surface that contacts with water during the experiment.4 For the contact angle measurement, only a drop of water makes contact with sample surface. During spontaneous water imbibition, a given amount of water permeates into the interconnected porous space of the rock and makes contact with its internal surface area. As shown in Figure 5, the accumulated weight was recorded as a function of aging time until it remained constant with the imbibition of water into the core slice. Figure 5a, b compare the results of the spontaneous water imbibitions for pure SiO2 nanofluids at five particle concentrations ranging from 100 ppm to 10000 ppm. Immersed in different nanofluids, nanoparticles were adsorbed on the oil-wet sample slices, resulting in various degrees of wettability alteration. Once deionized water imbibed into the treated sample, the accumulated weight was recorded as a function of time. When the weight value remained constant, the equilibrium time (T) and 19


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equilibrium weight (M) were recorded. Figure 5a shows that the difference (∆Mw) between the weight of a sample and the original weight was plotted as a function of time. ∆Mw represented the weight of water imbibed at a given time. Figure 5b reveals that the ratio between ∆Mw and the weight of imbibed at the equilibrium time (MwT) was plotted as a function of time.4 Figure 5a,b illustrate the results of spontaneous imbibition tests on the wettability alteration caused by various nanofluids. The untreated sample (water-0) exhibited the slowest imbibition process, indicating the oil-wet wettability. All treatments using the nanofluids improved the imbibition by altering the wettability of the samples from oil-wet to water-wet state. Regarding the effect of nanoparticle concentration on wettability alteration, Figure 5a presents the results. For nanofluids with different nanoparticle concentrations, the imbibing water capacity could be improved by increasing nanoparticle concentration up to 1000 ppm. At nanoparticle concentrations higher than 1000 ppm, the nanofluids obstructed the imbibition process; thus, the sample treated by the 10000 ppm nanofluid exhibited the smallest amount of imbibed water. Figure 5b shows that the sample slices treated by nanofluids with concentrations lower than or equal to 5000 ppm could also be inferred to exhibit similar imbibing rates during the process, but “water-10000 ppm” presented the slowest imbibition process. To summarize, the best performance was achieved at 1000 ppm concentration in accordance with the weight and rate curve of imbibed water. On the basis of previous research, pure SiO2 nanofluid achieved a significant alteration of sandstone surface wettability from oil-wet to increasing water-wet condition. Figure 5c,d present the synergistic effect of rhamnolipids and SiO2 nanoparticles in the bionanofluids on wettability alteration. With regard to imbibing water weight, the ability for wettability alteration of the nanofluids with 20


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concentrations lower than or equal to 1000 ppm would be improved by rhamnolipids. The enhancement of nanofluids by rhamnolipids became negligible at nanoparticle concentrations higher than 1000 ppm. This result indicates that increasing the nanoparticle concentration above a certain threshold negatively affects nanofluid imbibition via particle aggregation.4 Figure 5c,d demonstrates the synergistic effect of SiO2 nanoparticles and biosurfactant. The presence of rhamnolipids on the SiO2 nanoparticle surface may allow these particles to diffuse through the oil-wet porous medium samples to alter the wettability of oil-wet surfaces more easily.

Figure 5. Spontaneous imbibition curves for sandstone cores. (a) (b) Pure SiO2 nanofluid treatment (water-x); (c) (d) bionanofluid treatment (bio-x). The notation water/bio-x indicates the continuous phase (water and biosurfactant) and the 21


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nanoparticle concentration used in ppm. To further study the performance of the bionanofluid, the second method to evaluate the oil recovery during spontaneous imbibition tests was performed using Amott–Harvey cells.44 Figure 6a shows that the oil-wet sandstone cores were treated by various nanofluids and that crude oil was expelled. These results indicated a weak positive correlation between oil displacement efficiency and nanoparticle concentrations ranging from 100 ppm to 10000 ppm. The optimal concentration for the highest oil recovery was determined. Oil recovery increased to a final rate of 68% with increasing nanoparticle concentration to 1000 ppm. This result is consistent with the experimental result showing the best performance of a 1000 ppm nanofluid for wettability alteration. When the particle concentration exceeded 1000 ppm, the recovery rate of crude oil still increased during the early phases of the experiment. However, the final oil recovery was eventually obstructed by increasing nanoparticle concentration. Another unique finding occurred during the initial period of the experiment, i.e., the curve for oil recovery remained stable over a period of time. As the nanoparticle concentration was increased, this stabilization period became shorter. In addition, a comparison of oil recovery results of pure SiO2 nanofluid and bionanofluid in Figure 6b shows that the resultant oil displacement from the oil-wet sandstone via bionanofluid was greater than that via pure SiO2 nanofluid. Specifically, the bionanofluid had higher final oil recovery and faster recovery rate than the pure SiO2 nanofluid, revealing the synergistic effect of rhamnolipid and SiO2 nanoparticles in bionanofluid for oil displacement. In conclusion, these bionanofluids show potential to enhance oil recovery.

22


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Figure 6. Spontaneous imbibition test with Amott–Harvey cell. (a) Results of recovery oil via bionanofluids with different particle concentrations; (b) Comparison between the oil recovery results obtained with pure SiO2 nanofluid and bionanofluid. The notation water/bio-x indicates the continuous phase (water and biosurfactant) and the nanoparticle concentration used in ppm. 3.5. The Analysis of Oil Displacement with Bionanofluid. In the spontaneous imbibition tests, crude oil was recovered from oil-wet sandstone. Two mechanisms are available to investigate the displacement of oil. The first is that crude oil is detached from the rock surface as the result of wettability alteration. The second is crude oil being displaced by nanofluid via the effect of structural disjoining pressure. Researchers define “structural disjoining pressure” as the driving force for the spreading of the nanofluid to disjoin the crude oil from a surface.19-21 According to the previous studies,19-21 SiO2 nanoparticles converge on a three-phase contact region (oil drop/nanofluid/rock surface) and form a wedge film. The ordering of the nanoparticles in the wedge-film region results in excess pressure termed structural disjoining pressure. The direction of the pressure is toward to the vertex of the wedge-film region.20,21 On the basis of the results of previous 23


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experiments, crude oil was not displaced immediately and the system exhibited a slow change during the initial period. Localized nanoparticle concentration was inferred to increase until the required pressure value was reached, after which the contact line would begin migration. In addition to concentration, the thickness of wedge film might also influence this pressure. With the decrease in wedge film thickness, the structural disjoining pressure increased immediately and surpassed the interaction required for the adsorption between oil drops and rock surface. This phenomenon caused the contact line to move toward the vertex of the wedge film until the oil drops were ultimately displaced from the rock surfaces.21 Simultaneously, nanoparticles were adsorbed on the exposed surfaces, thereby improving the hydrophilicity of rock surfaces.36,44 It is this process that allows for nanofluid to displace crude oil under static conditions. However, when applied in the oil recovery industry, nanofluids would reduce the interaction between rock surfaces and oil drops, acting as a displacing fluid. These fluid flows could expedite the separation of crude oil from surfaces and enhance the efficiency of oil recovery. Figure 6 compares the performances of different nanofluid samples in the experiment, which is explained by structural disjoining pressure. When SiO2 nanoparticles were dispersed in rhamnolipid solution, the biosurfactant was absorbed onto the particle surface via electrostatic attraction and formed a new monomer layer. Adding rhamnolipid into the nanofluid promoted the ordering of nanoparticles in the wedge-film region, which shortened the stable period and enhanced oil displacement efficiency. Beyond this, the final oil recovery of the bionanofluids (68%) was higher than the recovery of pure SiO2 nanofluids (42%). The comparative results in Figure 6b were consistent with previous experiments, indicating the potential of the bionanofluids to enhance oil recovery. 24


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3.6. Micromodel Flooding Experiments. A micromodel test of nanofluid flooding was operated using a heterogeneous micromodel with pore diameter of 20~40 µm to investigate the displacing mechanism at pore level.45 Figure 7 presents a comparison among the oil recovery results obtained with water, rhamnolipid solution, and bionanofluid. Based on previous experimental results, the concentration of nanoparticles and rhamnolipid in bionanofluid was 1000 ppm and 25 ppm, respectively. The images of Figure 7 presented sections of micromodels that represent oil recovery efficiency at the microscale observed under the inverted microscope. These images were processed in Image-J software (National Institutes of Health) to analyze the residual oil saturation of the micromodel after flooding treatments. In Figure 7b, the trapped oil was still stranded in the pore throat or adsorbed on the pore wall, indicating the poor sweep efficiency of waterflooding.45, 46 As depicted in Figure 7c, the area in the micromodel was mostly reached, indicating the increase in sweep efficiency with rhamnolipid solution. This result illustrates the dredging of the pores saturated with oil. In addition, the displacement effect of rhamnolipid solution flooding was more effective than that of waterflooding.45

25


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Figure 7. Comparison of oil recovery following (a) aging crude oil; (b) waterflooding; (c) rhamnolipid solution; (d) bionanofluid. In the close-up images of micromodel test as shown in Figure 7d, the interaction between the nanofluid and oil was further analyzed. In porous media, some “dead-end pores” have only one open end. Figure 7c shows that the dead-end pores remained full of residual oil after water and rhamnolipid solution flooding, exhibiting poor treatment impact for displacing oil from such pores. The sweep volume was small because the displacing fluid could only be in contact with one side of the oil in dead-end pores.45 When nanofluid flooding was applied (Figure 7d), most of the residual oil in the “dead-end pores” was displaced. In comparison with Figure 7b,c, Figure 7d revealed that a large number of channels became cleared after bionanofluid flooding. During bionanofluid flooding, the thickness of the oil film decreased. In some areas, the water film that formed between the pore wall and oil film differed from that in the waterflooding and biosurfactant flooding treatment. The formation of this water film can be interpreted in accordance with the theory of structural disjoining pressure.19-21 The residual oil was stripped from pore wall surfaces because of the high surface energy of nanoparticles, subsequently forming the water film via the hydrophilicity of the nanoparticles. To a certain extent, the water film could obstruct the crude oil from re-adsorbing on the surfaces, accordingly improving the efficiency of oil displacement. Conversely, an increase in residual oil volume caused 26


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by the accumulation of mobilized oil might be observed in some areas after nanofluid flooding. In the future, this problem could be solved by optimizing the injection rates and concentrations of nanoparticles and biosurfactants. Figure 8a presents the oil recovery results obtained with bionanofluid injection compared with rhamnolipid solution injection in the micromodel test. The oil recovery rate increased until water breakthrough, and then only a small amount of oil could be recovered by waterflooding because additional injected water flowed mostly through the water-filled pores, resulting in low recovery at the end of the displacement. For rhamnolipid solution and biosurfactant flooding, additional 4% and 13% oil recovery values were achieved, respectively. Figure 8b shows the tertiary flooding to enhance oil recovery. Rhamnolipid solution was injected into the micromodel following waterflooding, providing an additional 4% oil recovery. Then, the bionanofluid contributed an additional 5% recovery. Basing from the microscopic images and oil recovery in Figure 7 and Figure 8, respectively, we can conclude that the oil entrapped in the small pores was displaced more efficiently by the bionanofluid than the rhamnolipid solution because of the synergistic effect of SiO2 nanoparticles and rhamnolipid molecules.

Figure 8. (a) Oil recovery for two displacement methods; (b) cumulative oil recovery for tertiary flooding. 27


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4. CONCLUSION As a new technology, the application of nanofluids has shown significant potential in the oil recovery field by decreasing the difficulty of enhanced oil recovery from reservoirs where traditional techniques face challenges. Figure S5 shows a schematic of the methodology applied in this study. The study evaluated the wettability alteration of sandstone cores by bionanofluids prepared by dispersing SiO2 nanoparticles in rhamnolipid solution through contact angle measurements and imbibitions tests. The best performance was achieved with a nanoparticle concentration of 1000 ppm and a rhamnolipid concentration of 25 ppm. Finally, the capability of the bionanofluids to enhance oil recovery was verified and compared with those of waterflooding and rhamnolipid solution in micromodel tests, yielding more than 70% production. The mechanisms of bionanofluid stability and structural disjoining pressure were described. Based on the experimental results, the bionanofluid for low-permeability reservoirs demonstrates a great potential for improving oil recovery. ASSOCIATED CONTENT Supporting Information The schematic of the methodology applied, SEM image of utilized SiO2 nanoparticles, and diagram of nanoparticle aggregation. These materials are available free of charge online at http://pubs.acs.org. AUTHOR INFORMATION ∗

Corresponding authors: Tel: +86-10-89734284; fax: +86-10-89734284; E-mail

address: [email protected] and [email protected] ACKNOLEDGEMENTS The authors are grateful to the State Key Laboratory of Heavy Oil of China University 28


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of Petroleum. This research was funded by the National Natural Science Foundation of China (No. 51634008) and National Science and Technology Major Projects (No. 2017ZX05009-004).

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Synergistic Effect of Silica Nanoparticles and Rhamnolipid on

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