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Table 13. Viscosity of the extracted oil for the second series of experiments

Table 13 Viscosity of the extracted oil for the second series of experiments

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Table 1. Mineral composition of the glass beads via XRD analysis
Table 1. Mineral composition of the glass beads via XRD analysis
Table 2. Mineral Composition of fine particles via XRF analysis
Table 2. Mineral Composition of fine particles via XRF analysis
Table 3. General characteristics of nanoparticles
Table 3. General characteristics of nanoparticles
Table 4. Characteristics of formation and injection water As it is the first time that this experiment has been conducted, a simple model oil, composed of decane and paraffin, was used for the tests. Decane is completely miscible with paraffin and the oil is a transparent liquid which makes it possible to observe the displaced fines by the naked eye. The viscosity of hydrocarbon was measured to be 10.55 cp using an Ubbelohde viscometer. 3.2. Experimental Setup and Procedure
Table 4. Characteristics of formation and injection water As it is the first time that this experiment has been conducted, a simple model oil, composed of decane and paraffin, was used for the tests. Decane is completely miscible with paraffin and the oil is a transparent liquid which makes it possible to observe the displaced fines by the naked eye. The viscosity of hydrocarbon was measured to be 10.55 cp using an Ubbelohde viscometer. 3.2. Experimental Setup and Procedure
As it can be observed from the figure, the pressure drop related to concentration of 0.24 M, smoothly reaches to a constant value. But after replacing 0.24 M brine by 0.23 M NaCl, the pressure drop (AP) increases to a peak, which shows pore-throat plugging resulting from fines migration. The pressure drop increases and then decreases which may occur as a result of the bridges at pore throats to be broken or sheared away. In addition, the pressure drop curves for 0.22 and 0.2 M NaCl brine have been shown in Figure 2. These curves have a similar trend which confirms release of fines. Therefore, CSC for NaCl brine was measured to be 0.24 M. It is worth noting that CSC for NaCl in sand packs has previously been reported 0.2 by Khilar and Fogler (1998).
As it can be observed from the figure, the pressure drop related to concentration of 0.24 M, smoothly reaches to a constant value. But after replacing 0.24 M brine by 0.23 M NaCl, the pressure drop (AP) increases to a peak, which shows pore-throat plugging resulting from fines migration. The pressure drop increases and then decreases which may occur as a result of the bridges at pore throats to be broken or sheared away. In addition, the pressure drop curves for 0.22 and 0.2 M NaCl brine have been shown in Figure 2. These curves have a similar trend which confirms release of fines. Therefore, CSC for NaCl brine was measured to be 0.24 M. It is worth noting that CSC for NaCl in sand packs has previously been reported 0.2 by Khilar and Fogler (1998).
Table 5. Stability time of nanofluids at concentrations of 0.03 M and 0.3 M NaCl brine
Table 5. Stability time of nanofluids at concentrations of 0.03 M and 0.3 M NaCl brine
n order to study the effect of nano silica, two tests were conducted, a base test, and another test yy injecting nanofluid. In the base test, after saturating the core by oil, 10 pore volumes of low alinity water were injected to the core at a rate of 80 cc/hr. In the second test, the core was first looded by low salinity water plus nano silica particles and then soaked for 12 hr. Afterwards, 9 yore volumes of low-salinity water were injected to the core. The injection rate for the nanofluid ind LSW was 80 cc/hr like the base test. The graphs of oil recovery can be found in Figure 3. The recovery of oil for the test of nanofluid injection was greater than the base test. Also, the esults of oil recovery for the tests have been given in Table 6.
n order to study the effect of nano silica, two tests were conducted, a base test, and another test yy injecting nanofluid. In the base test, after saturating the core by oil, 10 pore volumes of low alinity water were injected to the core at a rate of 80 cc/hr. In the second test, the core was first looded by low salinity water plus nano silica particles and then soaked for 12 hr. Afterwards, 9 yore volumes of low-salinity water were injected to the core. The injection rate for the nanofluid ind LSW was 80 cc/hr like the base test. The graphs of oil recovery can be found in Figure 3. The recovery of oil for the test of nanofluid injection was greater than the base test. Also, the esults of oil recovery for the tests have been given in Table 6.
Table 6. Results of oil recovery for the first series of experiments
Table 6. Results of oil recovery for the first series of experiments
Table 7. Comparison of turbidity of the water output in the first series of experiments
Table 7. Comparison of turbidity of the water output in the first series of experiments
Table 8. pH of the samples for the first series of experiments Table 9. Viscosity of the extracted oil for the first series of experiments
Table 8. pH of the samples for the first series of experiments Table 9. Viscosity of the extracted oil for the first series of experiments
[his series of experiments aimed to investigate the impact of the SiOz nanofluid concentration on fines migration control. Therefore, SiO, nanofluid at three concentrations of 0.03, 0.1, and 0.3% wt. were prepared and injected into 3 similar porous media and the oil recovery was recorded. Then, each core was closed for 24 hours and after that, 9 pore volumes of low salinity water were injected to each of them. Besides the three experiments described above, a base test was Sonducted and the result was compared to the results of nanofluid injection tests. Figure 5 shows vil recoveries of the tests. As it can be observed, the highest amount of oil was recovered by injecting 0.1% wt. SiOo.
[his series of experiments aimed to investigate the impact of the SiOz nanofluid concentration on fines migration control. Therefore, SiO, nanofluid at three concentrations of 0.03, 0.1, and 0.3% wt. were prepared and injected into 3 similar porous media and the oil recovery was recorded. Then, each core was closed for 24 hours and after that, 9 pore volumes of low salinity water were injected to each of them. Besides the three experiments described above, a base test was Sonducted and the result was compared to the results of nanofluid injection tests. Figure 5 shows vil recoveries of the tests. As it can be observed, the highest amount of oil was recovered by injecting 0.1% wt. SiOo.
Table 10. Results of oil recovery for the second series of experiments
Table 10. Results of oil recovery for the second series of experiments
Figure 6. Comparison of dimensionless pressure drop for the second series of experiments
Figure 6. Comparison of dimensionless pressure drop for the second series of experiments
Table 11. Comparison of turbidity of the water output in the second series of experiments
Table 11. Comparison of turbidity of the water output in the second series of experiments
Table 14. Results of oil recovery for the third series of experiments
Table 14. Results of oil recovery for the third series of experiments
Table 15. Comparison of turbidity of the water output in the third series of experiments
Table 15. Comparison of turbidity of the water output in the third series of experiments
Soaking time periods of 12 and 24 hours of which the results were close to each other, were repeated in order to confirm the findings and investigate whether duration of soaking time influences oil recovery or not. Also, two other tests were conducted in which 0.3% wt. SiOz nanofluid with soaking times of 12 and 24 hours were examined. The results have been compared to previous recordings from 0.1% wt. SiO injection in Figure 9. According to Table 16, the oil recovery for the experiment of 24-hour soaking time of 0.1% wt. nanofluid was measured to be 67.8% while oil recovery was 66.5% for soaking time of 12 hours. Then, the concentration was increased to 0.3% wt. and the period of soaking time was set to 12 hours and 60.3% oil was recovered. Also, the amount of oil recovered for 0.3% wt. nanofluid injection with soaking time of 24 hours was 61%. By comparison of these results, it can be deducted that concentration of the nanofluid has a greater impact oil recovery than the period of soaking time. Table 16. Results of oil recovery for the experiments of concentration and soaking time
Soaking time periods of 12 and 24 hours of which the results were close to each other, were repeated in order to confirm the findings and investigate whether duration of soaking time influences oil recovery or not. Also, two other tests were conducted in which 0.3% wt. SiOz nanofluid with soaking times of 12 and 24 hours were examined. The results have been compared to previous recordings from 0.1% wt. SiO injection in Figure 9. According to Table 16, the oil recovery for the experiment of 24-hour soaking time of 0.1% wt. nanofluid was measured to be 67.8% while oil recovery was 66.5% for soaking time of 12 hours. Then, the concentration was increased to 0.3% wt. and the period of soaking time was set to 12 hours and 60.3% oil was recovered. Also, the amount of oil recovered for 0.3% wt. nanofluid injection with soaking time of 24 hours was 61%. By comparison of these results, it can be deducted that concentration of the nanofluid has a greater impact oil recovery than the period of soaking time. Table 16. Results of oil recovery for the experiments of concentration and soaking time
Table 17. pH of the samples for the third series of experiments
Table 17. pH of the samples for the third series of experiments
Table 18. Viscosity of the extracted oil for the third series of experiments
Table 18. Viscosity of the extracted oil for the third series of experiments
Table 19. Average size of nanoparticles used in experiments at concentration of 0.03 M NaCl The stability times of nanoparticles in 0.03 and 0.3 M NaCl solutions were reported in Table 5 Based on data in Table 5, SiOz nanoparticles have a good dispersion time in these solutions, bu Al,03 and MgO nanoparticles agglomerate and have very less dispersion time. In order to furthe: investigate the dispersion properties of nanoparticles in solution, the average size of th nanoparticles after 1 hour was measured by DLS method, as shown in Table 19. As it can be observed in Table 19, SiOz nanoparticles has a good dispersion in 0.03 M NaCl solution. Bu Al,03 and MgO nanofluids had nanoparticles of greater size which would lead to lower stability of nanoparticles in the solution. For each nanoparticle, the pH at the Zero Point Charge (ZPC) is a characteristic that determines the pH at which the surface has net electrical neutrality. If pH of the solution has a greater value than ZPC of nanoparticle, the charges take negative values and get more negative with increasing pH. The higher the difference between the pH of the solution and ZPC, the greater repulsive force separates the particles from one another and the higher stability time is. As noted before, pH of the solution was recorded as 5.9. ZPC of SiOz is pH 2.5-3 while ZPC of alumina lies between a pH of 7.5 and 9 and that of MgO is between 12-13 (Sahai, 2002). One way to increase stability of Alumina is to lower the pH of the solution by adding HCl. But it is not of interest to change the pH of the solution due to the fact that changing pH certainly affects the results; however, adding HCI and shifting the pH from 5.9 to 3 had an insignificant influence on stability time of this nanofluid and extended the stability time from 7 hours to 13 hours which is less than the time required for the experiment. Therefore, nanoparticles of AlxO3 and MgO nanoparticles were excluded because of their inadequate stability times.
Table 19. Average size of nanoparticles used in experiments at concentration of 0.03 M NaCl The stability times of nanoparticles in 0.03 and 0.3 M NaCl solutions were reported in Table 5 Based on data in Table 5, SiOz nanoparticles have a good dispersion time in these solutions, bu Al,03 and MgO nanoparticles agglomerate and have very less dispersion time. In order to furthe: investigate the dispersion properties of nanoparticles in solution, the average size of th nanoparticles after 1 hour was measured by DLS method, as shown in Table 19. As it can be observed in Table 19, SiOz nanoparticles has a good dispersion in 0.03 M NaCl solution. Bu Al,03 and MgO nanofluids had nanoparticles of greater size which would lead to lower stability of nanoparticles in the solution. For each nanoparticle, the pH at the Zero Point Charge (ZPC) is a characteristic that determines the pH at which the surface has net electrical neutrality. If pH of the solution has a greater value than ZPC of nanoparticle, the charges take negative values and get more negative with increasing pH. The higher the difference between the pH of the solution and ZPC, the greater repulsive force separates the particles from one another and the higher stability time is. As noted before, pH of the solution was recorded as 5.9. ZPC of SiOz is pH 2.5-3 while ZPC of alumina lies between a pH of 7.5 and 9 and that of MgO is between 12-13 (Sahai, 2002). One way to increase stability of Alumina is to lower the pH of the solution by adding HCl. But it is not of interest to change the pH of the solution due to the fact that changing pH certainly affects the results; however, adding HCI and shifting the pH from 5.9 to 3 had an insignificant influence on stability time of this nanofluid and extended the stability time from 7 hours to 13 hours which is less than the time required for the experiment. Therefore, nanoparticles of AlxO3 and MgO nanoparticles were excluded because of their inadequate stability times.
Besides, the surface roughness of the glass beads was investigated due to the fact that surface of the beads can be changed by coating with SiO», nanoparticles. Due to impossibility of measuring the roughness of spherical glass beads, a glass lamina was used for investigation of nanofluid effect on surface roughness. First, roughness of the glass laminas was recorded as a base value and it was measured to be about 2.3 nm for all the samples. Then, the glass laminas were soaked in SiO, nanofluid with different concentrations for 24 hours and surface roughness of the laminas was measured by AFM analysis. Figures 10 through 13 show the roughness of the glass surfaces for different cases (Hasannejad et al., 2017).
Besides, the surface roughness of the glass beads was investigated due to the fact that surface of the beads can be changed by coating with SiO», nanoparticles. Due to impossibility of measuring the roughness of spherical glass beads, a glass lamina was used for investigation of nanofluid effect on surface roughness. First, roughness of the glass laminas was recorded as a base value and it was measured to be about 2.3 nm for all the samples. Then, the glass laminas were soaked in SiO, nanofluid with different concentrations for 24 hours and surface roughness of the laminas was measured by AFM analysis. Figures 10 through 13 show the roughness of the glass surfaces for different cases (Hasannejad et al., 2017).
Table 20. Values of surface roughness measured by AFM apparatus
Table 20. Values of surface roughness measured by AFM apparatus
Results of the tests for different nanoparticle concentrations and soaking times are shown in Figure 14. Also, the ultimate amounts of oil recovery can be found in Table 21. According to the data in Table 21, the oil recoveries in these tests were close to each other. In the other term, by changing nanofluid concentration, no significant change in oil recovery was observed; therefore, it can be concluded that SiOz nanoparticles have no specific effect on enhance oil recovery. If increase in oil recovery for LSW plus nanoparticles was due to wettability alteration or nanoparticle effect, similar results would be expected for HSW plus nanoparticles.
Results of the tests for different nanoparticle concentrations and soaking times are shown in Figure 14. Also, the ultimate amounts of oil recovery can be found in Table 21. According to the data in Table 21, the oil recoveries in these tests were close to each other. In the other term, by changing nanofluid concentration, no significant change in oil recovery was observed; therefore, it can be concluded that SiOz nanoparticles have no specific effect on enhance oil recovery. If increase in oil recovery for LSW plus nanoparticles was due to wettability alteration or nanoparticle effect, similar results would be expected for HSW plus nanoparticles.
Table 21. Results of oil recovery for the tests of injecting nanofluid dispersed in HSW
Table 21. Results of oil recovery for the tests of injecting nanofluid dispersed in HSW
Figure 15 shows a comparison of the oil recovery curves regarding concentration of nanoparticles dispersed in high and low salinity water. Migration of fines is an accompanying phenomenon with LSW flooding method, which extremely affects the efficiency of the process. [t was observed that by injecting 0.1% wt. SiO, nanofluid, fines migration was better controlled and the highest value of ultimate oil recovery was obtained. Furthermore, there was a Sonsiderable difference in the oil recoveries using different concentrations of nanoparticles along with LSW. These differences may result from fines migration control or wettability alteration. If wettability alteration was the main mechanism behind enhanced-oil recovery during nanofluid injection, a similar trend to LSW plus nanoparticles should occur when nanoparticles along with nigh saline water were injected to the porous media. But, as it can be observed from figure 15, results of oil recovery for different concentration of nanoparticles dispersed in HSW approximately had similar results. Therefore, the differences between the oil recoveries during aanofluid injection do not result from wettability alteration. This can be attributed to the nature of the oil which exhibits no response to nanoparticles.
Figure 15 shows a comparison of the oil recovery curves regarding concentration of nanoparticles dispersed in high and low salinity water. Migration of fines is an accompanying phenomenon with LSW flooding method, which extremely affects the efficiency of the process. [t was observed that by injecting 0.1% wt. SiO, nanofluid, fines migration was better controlled and the highest value of ultimate oil recovery was obtained. Furthermore, there was a Sonsiderable difference in the oil recoveries using different concentrations of nanoparticles along with LSW. These differences may result from fines migration control or wettability alteration. If wettability alteration was the main mechanism behind enhanced-oil recovery during nanofluid injection, a similar trend to LSW plus nanoparticles should occur when nanoparticles along with nigh saline water were injected to the porous media. But, as it can be observed from figure 15, results of oil recovery for different concentration of nanoparticles dispersed in HSW approximately had similar results. Therefore, the differences between the oil recoveries during aanofluid injection do not result from wettability alteration. This can be attributed to the nature of the oil which exhibits no response to nanoparticles.
Figure 15. Comparison of oil recoveries for the tests of injecting nanofluid dispersed in LSW and HSW
Figure 15. Comparison of oil recoveries for the tests of injecting nanofluid dispersed in LSW and HSW
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