Application of Green Polymeric Nanocomposites for Enhanced Oil Recovery by Spontaneous Imbibition from Carbonate Reservoirs

This study experimentally investigates the effect of green polymeric nanoparticles on the interfacial tension (IFT) and wettability of carbonate reservoirs to effectively change the enhanced oil recovery (EOR) parameters. This experimental study compares the performance of xanthan/magnetite/SiO2 nanocomposites (NC) and several green materials, i.e., eucalyptus plant nanocomposites (ENC) and walnut shell ones (WNC) on the oil recovery with performing series of spontaneous imbibition tests. Scanning electron microscopy (SEM), X-ray diffraction (XRD), energy-dispersive X-ray spectroscopy (EDAX), and BET (Brunauer, Emmett, and Teller) surface analysis tests are also applied to monitor the morphology and crystalline structure of NC, ENC, and WNC. Then, the IFT and contact angle (CA) were measured in the presence of these materials under various reservoir conditions and solvent salinities. It was found that both ENC and WNC nanocomposites decreased CA and IFT, but ENC performed better than WNC under different salinities, namely, seawater (SW), double diluted salted (2 SW), ten times diluted seawater (10 SW), formation water (FW), and distilled water (DIW), which were applied at 70 °C, 2000 psi, and 0.05 wt.% nanocomposites concentration. Based on better results, ENC nanofluid at salinity concentrations of 10 SW and 2 SW ENC were selected for the EOR of carbonate rocks under reservoir conditions. The contact angles of ENC nanocomposites at the salinities of 2 SW and 10 SW were 49 and 43.4°, respectively. Zeta potential values were −44.39 and −46.58 for 2 SW and 10 SW ENC nanofluids, which is evidence of the high stability of ENC nanocomposites. The imbibition results at 70 °C and 2000 psi with 0.05 wt.% ENC at 10 SW and 2 SW led to incremental oil recoveries of 64.13% and 60.12%, respectively, compared to NC, which was 46.16%.


Introduction
Due to the low level of oil production by standard methods, studies have been approached based on the use of alkaline [1,2], polymer [3,4], and surfactant [5,6] chemicals to improve oil recovery. Changing brine composition in the injected water is known as a cost-effective and efficient method, which can affect EOR scenarios [7]. One of the standard plans to intensify the oil recovery in all types of reservoirs is the injection of low concentrations of brine, known as low salinity flooding [8]. The main advantages of flooding with low salinity are its lower cost compared to expensive chemical methods and the fact for EOR based on the main parameters of this process (IFT and CA) at different salinity conditions. It was observed that green nanocomposites have high efficiency for EOR from carbonate reservoirs at different salinity conditions. Thus, CA and IFT were reduced to significantly lower values than those corresponding to commercial silica, and oil recovery at 2 SW and 10 SW salinity conditions increased to 25.1% and 34.1%, respectively [38]. Ali et al. (2020) utilized magnetite/xanthan/silica for the wettability alteration and IFT reduction, with xanthan being synthesized from the Alocasia macrorrhiza plant. The application of 250 to 1500 ppm concentration of the materials results in wettability alteration from the strongly oil-wet to the water-wet in the carbonate reservoir, and IFT decreased in the presence of nanocomposites [24]. According to their results, IFT was decreased from 28.3 to 4.35 mN/m, and contact angle was decreased from 134 to 28 • after using nanocomposites. As it was mentioned, the main effective parameters are IFT and CA reduction, and Table 1 summarized the last works for EOR in the presence of nanoparticles. It should be noted that although many EOR studies have already been conducted, there are limited works covering recovery tests at reservoir conditions. Moreover, too high concentrations have been commonly used for low permeability carbonate, and the mentioned plant is not easily accessible, especially in our region. Therefore, more accessible and cost-effective materials (i.e., eucalyptus plant and the walnut shell) are selected in this study instead of the Alocasia macrorrhiza plant, and their performance is compared with the base material (silica/xanthan/magnetite). Accordingly, the main novelty of this work was using cost-effective polymeric nanocomposites at different salinity at reservoir conditions.

Materials
The core sample and crude oil are provided by one of Iran's carbonate oil reservoirs. Core porosity, permeability, and oil density and viscosity were 14.90%, 10.45 mD, and 10.00 cP, respectively. It was tried to select two same plugs for performing imbibition tests in the presence of nanocomposites, as shown in Figure 1. Initial carbonate plug mass (gram), plug length (cm), diameter (cm), and saturated oil plus mass (gram) were 112.20, 4.80, 3.80, and 119.20, respectively. Solvents, salts (NaCl, CaCl 2 , MgCl 2 , KCl), and other chemical compounds were supplied by Merck and Aldrich with a purity of 99.5%. Xanthan gum (98% purity) was supplied by Aldrich company, iron chloride (FeCl 3 ), and sodium metasilicate (Na 2 SiO 3 ) with 98% purity by Merck company. The values of brine composition, pH, and density are shown in Tables 2 and 3, respectively, according to different salinities. Distilled water was used during dilution. After the preparation of specific amounts of salts (FW, SW, 2 SW, and 10 SW), the solution was prepared with DIW, and it was homogenized before applying. Solvents, salts (NaCl, CaCl2, MgCl2, KCl), and other chemical compou plied by Merck and Aldrich with a purity of 99.5%. Xanthan gum (98% pu plied by Aldrich company, iron chloride (FeCl3), and sodium metasilicate 98% purity by Merck company. The values of brine composition, pH, an shown in Tables 2 and 3, respectively, according to different salinities. Disti used during dilution. After the preparation of specific amounts of salts (F and 10 SW), the solution was prepared with DIW, and it was homogenized ing.  NaCl  2840  14,200  28,400  14  CaCl2  138  690  1380  4  MgCl2  643  3215  6430  2  KCl  80  400  800   Table 3. pH and density of the brine.

Synthesizing Green Polymeric Nanocomposites (NC, WNC, and ENC)
The based material was xanthan/magnetite/SiO2, and it was obtained b al., 2020 [24]. At the same condition, the desired plant extracts (from walnu lyptus leaves) were prepared by heating 50 g of the sample (walnut bark po eucalyptus leaves) in 400 cm 3 of distilled water at 80 °C for 40 min. The obtained from both extracts were filtered, 2 g of FeCl3 and 5 g of Na2SiO3   The based material was xanthan/magnetite/SiO 2 , and it was obtained based on Ali. et al., 2020 [24]. At the same condition, the desired plant extracts (from walnut bark or eucalyptus leaves) were prepared by heating 50 g of the sample (walnut bark powder or dried eucalyptus leaves) in 400 cm 3 of distilled water at 80 • C for 40 min. Then, the samples obtained from both extracts were filtered, 2 g of FeCl 3 and 5 g of Na 2 SiO 3 were added to 100 mL of the liquid solution at 80 • C, and the mixture was stirred at a pH value of 10 by adding NaOH. The stirring stops just after the formation of a black precipitate, and the solution filters for separation. The possible impurities are removed by heating the obtained residue at 400 • C and washing it with hot distilled water. Finally, the nanocomposites are synthesized by mixing 15 g of xanthan gum, 200 cm 3 of ethanol, and the collected sediment under reflux conditions for 8 h at 80 • C. Figures 2a and 1b show details about the preparation of WNC and ENC nanocomposites.

CA, IFT, and Imbibition Tests
A schematic view of the equipment for IFT and CA tests is shown in Figures 3a and 2b, respectively, with the Petro AZMA model. After preparing the nanofluids at different salinities, they were transferred to the primary cell. Next, the crude oil was injected with an oil pump, and the drops were recorded with a camera. The system pressure was set to 2000 psi with a nano pump, and the temperature was 70 •C in all tests. Finally, drops were calculated based on their analysis and IFT software. Instructions were rigorously followed for CA tests, and they differed only in the droplets on the carbonate sheets [38]. Figure 3c shows a schematic view of the equipment for the imbibition test, which was used for ascertaining oil recovery. Nanofluids containing 0.05 wt.% ENCs were prepared at two different salinities of 2 SW and 10 SW for IFT and CA tests, and the fluid was transferred to the primary cell surrounding the saturated oil core. The core initial mass, oil sodden group, initial oil saturation, and oil volume were recorded in the imbibition tests. Cell pressure and temperature were set at 70 °C and 2000 psi, and runs were performed with 2 SW and 10 SW salinities. All experiments in our study were repeated three times, and their average values were reported.

CA, IFT, and Imbibition Tests
A schematic view of the equipment for IFT and CA tests is shown in Figures 3a and 2b, respectively, with the Petro AZMA model. After preparing the nanofluids at different salinities, they were transferred to the primary cell. Next, the crude oil was injected with an oil pump, and the drops were recorded with a camera. The system pressure was set to 2000 psi with a nano pump, and the temperature was 70 •C in all tests. Finally, drops were calculated based on their analysis and IFT software. Instructions were rigorously followed for CA tests, and they differed only in the droplets on the carbonate sheets [38]. Figure 3c shows a schematic view of the equipment for the imbibition test, which was used for ascertaining oil recovery. Nanofluids containing 0.05 wt.% ENCs were prepared at two different salinities of 2 SW and 10 SW for IFT and CA tests, and the fluid was transferred to the primary cell surrounding the saturated oil core. The core initial mass, oil sodden group, initial oil saturation, and oil volume were recorded in the imbibition tests. Cell pressure and temperature were set at 70 • C and 2000 psi, and runs were performed with 2 SW and 10 SW salinities. All experiments in our study were repeated three times, and their average values were reported.

Chemical Composition and Surface Morphology of Nanocomposites
X-ray diffraction analysis was applied to observe the crystal structure with the PW1730 model. Figure 4 presents the X-ray diffraction spectrum of the base NC and those corresponding to WNCs and ENCs. As observed, the XRD pattern of the sample without the extract is different from that containing the extract, which is evidence of the successful preparation of these compounds. The 2θ peaks at 11.32 and 27.82 correspond to eucalyptus plant and walnut shells, respectively [44][45][46].

Chemical Composition and Surface Morphology of Nanocomposites
X-ray diffraction analysis was applied to observe the crystal structure w PW1730 model. Figure 4 presents the X-ray diffraction spectrum of the base NC an corresponding to WNCs and ENCs. As observed, the XRD pattern of the sample the extract is different from that containing the extract, which is evidence of the su preparation of these compounds. The 2ϴ peaks at 11.32 and 27.82 correspond to e tus plant and walnut shells, respectively [44][45][46].

Chemical Composition and Surface Morphology of Nanocomposites
X-ray diffraction analysis was applied to observe the crystal structure with the PW1730 model. Figure 4 presents the X-ray diffraction spectrum of the base NC and those corresponding to WNCs and ENCs. As observed, the XRD pattern of the sample without the extract is different from that containing the extract, which is evidence of the successful preparation of these compounds. The 2ϴ peaks at 11.32 and 27.82 correspond to eucalyptus plant and walnut shells, respectively [44][45][46].       Energy Diffraction X-ray analyses (EDAX) were performed with the TESCAN MIRA2 model to investigate the elemental analysis of nanocomposites. EDAX tests for NC, ENC, and WNC nanocomposites are illustrated in Figure 7a, 7b, and 7c, respectively. Their elemental analysis is set out in Table 4. By examining the X-ray energy diffraction spectra, the presence of new elements corresponding to the plant extracts confirms that these nanoparticles have been correctly synthesized. Energy Diffraction X-ray analyses (EDAX) were performed with the TESCAN MIRA2 model to investigate the elemental analysis of nanocomposites. EDAX tests for NC, ENC, and WNC nanocomposites are illustrated in Figure 7a, 7b, and 7c, respectively. Their elemental analysis is set out in Table 4. By examining the X-ray energy diffraction spectra, the presence of new elements corresponding to the plant extracts confirms that these nanoparticles have been correctly synthesized. Energy Diffraction X-ray analyses (EDAX) were performed with the TESCAN MIRA2 model to investigate the elemental analysis of nanocomposites. EDAX tests for NC, ENC, and WNC nanocomposites are illustrated in Figure 7a, 7b, and 7c, respectively. Their elemental analysis is set out in Table 4. By examining the X-ray energy diffraction spectra, the presence of new elements corresponding to the plant extracts confirms that these nanoparticles have been correctly synthesized.     Figure 8 shows the isotherms of the N 2 adsorption-desorption of NC, ENC, and WNC samples determined based on the BET (Brunauer-Emmett-Teller) method with the BELSORP MINI II model. Table 5 reports the pore volume, average pore diameter, and BET surface area. The specific surface areas of NC, ENC, and WNC samples were 14.22, 36.04, and 30.97 m 2 /g, respectively. Adding eucalyptus (ENCs) and walnut shells (WNCs) increased the pore volume of the nanocomposites, as well as their specific surface area.  Figure 8 shows the isotherms of the N2 adsorption-desorption of NC, ENC, and WNC samples determined based on the BET (Brunauer-Emmett-Teller) method with the BELSORP MINI II model. Table 5 reports the pore volume, average pore diameter, and BET surface area. The specific surface areas of NC, ENC, and WNC samples were 14.22, 36.04, and 30.97 m 2 /g, respectively. Adding eucalyptus (ENCs) and walnut shells (WNCs) increased the pore volume of the nanocomposites, as well as their specific surface area.

Results of the IFT, CA, and Imbibition Tests
One of the crucial parameters to monitor when flooding with low salinity is the interfacial tension. Figure 9 shows the IFT between crude oil and water containing different nanocomposites (NC, ENC, and WNC) at 0.05 wt.% concentration under reservoir conditions (70 °C and 2000 psi). The results show that the interfacial tension decreases when salt water concentration is decreased among SW, 2 SW, and 10 SW, FW had the lowest IFT, and DIW had the highest IFT.
Furthermore, interfacial tension with formation water is surprisingly lower than with the other salty solutions tested. Thus, when the salt water concentration was decreased, the surface-active material particles moved toward the contact surface, and the IFT decreased. As the concentration of saltwater was increased, the surface energy of the particles attenuated in the oil.

Results of the IFT, CA, and Imbibition Tests
One of the crucial parameters to monitor when flooding with low salinity is the interfacial tension. Figure 9 shows the IFT between crude oil and water containing different nanocomposites (NC, ENC, and WNC) at 0.05 wt.% concentration under reservoir conditions (70 • C and 2000 psi). The results show that the interfacial tension decreases when salt water concentration is decreased among SW, 2 SW, and 10 SW, FW had the lowest IFT, and DIW had the highest IFT. compound of the seawater and reported that diluting the seawater can effectively reduce the IFT.
As observed in this figure, the IFT values of Magnetite/SiO2/Xanthan nanocomposites decrease as the salinity of the solution is decreased. The main fact for IFT reduction lies in the use of xanthan gum in the structure of nanocomposites and the subsequent increase in tensile strength [38,50]. It should be noted that the data of IFT shown in Figure 9 correspond to the average of three replicates. In addition, wettability is another crucial factor of a porous medium. This factor plays a vital role in water displacement and EOR parameters. The rock wettability is possible to change from oil-wet to water-wet in the presence of nanoparticles. An adsorbed layer of nanomaterials on the rock surface affects the fluid/rock as well as fluid/fluid interactions. A wide range of factors, including rock surface characteristics, nanoparticles size/concentration, and the nanoparticles-rocks interaction, determine the type of deposited layer on the rock surface as well as the resulting wettability alteration. Figure 10 shows the contact angles measured in the presence of different nanocomposites (NCs, WNCs, and ENCs) and different salinity levels (DIW, FW, SW, 2 SW, and 10 SW). The results of the runs under the reservoir temperature and pressure (70 °C and 2000 psi) with 0.05 wt.% nanocomposites concentration showed that the injection of ENC and WNC nanocomposites solutions increases the hydrophilic strength of the carbonate rock more than the injection of the base NC nanocomposites. Deionized water has the highest CA changes among other tested points. FW, 2 SW, and 10 SW dilute seawater solutions recorded the lowest wettability in the presence of NC, WNC, and ENC nanocomposites at the concentration of 0.05 wt.% under the temperature and pressure of the reservoir (70 °C and 2000 psi). Furthermore, all the nanocomposite solutions enhance the hydrophilic properties of carbonate rock, but (independently of the salinity) ENC and WNC nanocomposites decreased the CA more than the base NC nanocomposites. Based on these results, the green particle of the highest efficiency was chosen for further studies in the porous media. Thus, the ENC Furthermore, interfacial tension with formation water is surprisingly lower than with the other salty solutions tested. Thus, when the salt water concentration was decreased, the surface-active material particles moved toward the contact surface, and the IFT decreased. As the concentration of saltwater was increased, the surface energy of the particles attenuated in the oil.
Among SW, 2 SW, and 10 SW, it was found that a solution of lower concentration reduces the solution ionic strength and, therefore, the interfacial tension, which enhances oil extraction [47]. This observation is quite consistent with the results reported by Nowrouzi et al. [48] and Ali et al. [49]. They described the effect of concentration and ionic compound of the seawater and reported that diluting the seawater can effectively reduce the IFT.
As observed in this figure, the IFT values of Magnetite/SiO 2 /Xanthan nanocomposites decrease as the salinity of the solution is decreased. The main fact for IFT reduction lies in the use of xanthan gum in the structure of nanocomposites and the subsequent increase in tensile strength [38,50]. It should be noted that the data of IFT shown in Figure 9 correspond to the average of three replicates.
In addition, wettability is another crucial factor of a porous medium. This factor plays a vital role in water displacement and EOR parameters. The rock wettability is possible to change from oil-wet to water-wet in the presence of nanoparticles. An adsorbed layer of nanomaterials on the rock surface affects the fluid/rock as well as fluid/fluid interactions. A wide range of factors, including rock surface characteristics, nanoparticles size/concentration, and the nanoparticles-rocks interaction, determine the type of deposited layer on the rock surface as well as the resulting wettability alteration. Figure 10 shows the contact angles measured in the presence of different nanocomposites (NCs, WNCs, and ENCs) and different salinity levels (DIW, FW, SW, 2 SW, and 10 SW). The results of the runs under the reservoir temperature and pressure (70 • C and 2000 psi) with 0.05 wt.% nanocomposites concentration showed that the injection of ENC and WNC nanocomposites solutions increases the hydrophilic strength of the carbonate rock more than the injection of the base NC nanocomposites. Deionized water has the highest CA changes among other tested points. FW, 2 SW, and 10 SW dilute seawater solutions recorded the lowest wettability in the presence of NC, WNC, and ENC nanocomposites at the concentration of 0.05 wt.% under the temperature and pressure of the reservoir (70 • C and 2000 psi). Furthermore, all the nanocomposite solutions enhance the hydrophilic properties of carbonate rock, but (independently of the salinity) ENC and WNC nanocomposites decreased the CA more than the base NC nanocomposites. Based on these results, the green particle of the highest efficiency was chosen for further studies in the porous media. Thus, the ENC nanocomposites at the salinities of 2 SW and 10 SW were selected for performing imbibition   Figure 11 shows oil recovery test scenarios using base (NC) and ENC at different salinity of 2 SW and 10 SW under 2000 psi and 70 °C by using spontaneous imbibition tests. Oil recovery for the base, 2 SW, and 10 SW were 46.16, 60.12, and 64.13%, respectively. The changes in CA and IFT are responsible for increasing oil recovery with the nanocomposites. Furthermore, a highly relevant fact that must also be considered is stability. Thus, nanoparticle stability is one of the crucial factors that must be considered during flooding, especially in carbonate reservoirs of low permeability. Zeta potential was measured to ascertain stability in the presence of ENC nanocomposites with Malvern Zetasizer Nano ZS ZEN3600, Malvern Instruments Ltd, Malvern, United Kingdom and values of −44.39 and −46.58 were obtained for 2 SW and 10 SW, respectively. This finding clarifies that this nanocomposite is highly stable in the two solutions [51].  Figure 11 shows oil recovery test scenarios using base (NC) and ENC at different salinity of 2 SW and 10 SW under 2000 psi and 70 • C by using spontaneous imbibition tests. Oil recovery for the base, 2 SW, and 10 SW were 46.16, 60.12, and 64.13%, respectively. The changes in CA and IFT are responsible for increasing oil recovery with the nanocomposites. Furthermore, a highly relevant fact that must also be considered is stability. Thus, nanoparticle stability is one of the crucial factors that must be considered during flooding, especially in carbonate reservoirs of low permeability. Zeta potential was measured to ascertain stability in the presence of ENC nanocomposites with Malvern Zetasizer Nano ZS ZEN3600, Malvern Instruments Ltd, Malvern, United Kingdom and values of −44.39 and −46.58 were obtained for 2 SW and 10 SW, respectively. This finding clarifies that this nanocomposite is highly stable in the two solutions [51].     Table 6 compares the results of the current study with relevant previous works. Based on the results, nanocomposites had better tertiary oil recovery compared to others.

Conclusions
In this study, green polymeric nanocomposites of eucalyptus and walnut shell (ENC and WNC) were prepared at different salinity concentrations [DIW, FW, SW, 2 SW, and 10 SW] to enhance oil recovery under reservoir conditions [70 • C and 2000 psi] by spontaneous imbibition tests. The main advantages of this study were using cost-effective green materials at reservoir conditions at a low concentration of 0.05 wt.%. Based on the results of IFT and CA tests, ENC nanocomposites perform better than WNC nanocomposites, and they were selected for actual imbibition tests at 2 SW and 10 SW salinities (they are the most efficient solutions). In the presence of ENC nanocomposites, the zeta potential for 2 SW and 10 SW salinities are −44.39 and −46.58, respectively, which is evidence of the excellent stability of eucalyptus nanocomposites. Furthermore, the wettability of the carbonate rock changes towards hydrophilicity for low concentrations of brine. Two scenarios, i.e., 2 SW and 10 SW, with these eucalyptus nanocomposites led to the best results in wettability tests. The oil recoveries with ENC at 2 SW and 10 SW were 60.12% and 64.13%, respectively, compared to NC, which was 46.16%. The explanation for this result lies in the reduction of IFT and CA and their high stability. Future research should be devoted to ascertaining the influence of the parameters analyzed in this study (solution salinity and reservoir pressure and temperature) when the process is scaled up.