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Table 4. Composition of the Brines injection brine and the sequence of injections are summarized in Table were a maximum of 0.5 bar and the drainage required ~4 weeks. The obtained irreducible water saturations are provided in Table 1.

Table 4 Composition of the Brines injection brine and the sequence of injections are summarized in Table were a maximum of 0.5 bar and the drainage required ~4 weeks. The obtained irreducible water saturations are provided in Table 1.

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Table 1. Physical Properties of Core Samples Table 2. Bulk Mineral Composition of Two Different Samples Measured by X-ray Diffraction (XRD)
Table 1. Physical Properties of Core Samples Table 2. Bulk Mineral Composition of Two Different Samples Measured by X-ray Diffraction (XRD)
2.2. Crude. A stock tank crude oil was used for primary drainage and aging. Physical properties and the composition of the crude oil are given in Table 3.
2.2. Crude. A stock tank crude oil was used for primary drainage and aging. Physical properties and the composition of the crude oil are given in Table 3.
Table 3. Chemical Composition and Physical Properties of the Crude Oil
Table 3. Chemical Composition and Physical Properties of the Crude Oil
The samples were then inserted in sealed and airtight aging cells, and the cells were filled with the crude oil (Table 3). The sealed aging cells were kept in a heating cabinet at 80 °C to alter the wettability of samples toward being neutral or oil-wet. Samples 1 and 2 were aged for 4 weeks and samples 3—S were aged for 7 weeks. The changes in water saturation at different pressures are illustrated in Figure 2. Pressure increments Figure 2. Drainage pressure versus saturation change using a porous ceramic plate in cores 1—S.
The samples were then inserted in sealed and airtight aging cells, and the cells were filled with the crude oil (Table 3). The sealed aging cells were kept in a heating cabinet at 80 °C to alter the wettability of samples toward being neutral or oil-wet. Samples 1 and 2 were aged for 4 weeks and samples 3—S were aged for 7 weeks. The changes in water saturation at different pressures are illustrated in Figure 2. Pressure increments Figure 2. Drainage pressure versus saturation change using a porous ceramic plate in cores 1—S.
Table S. Injection Sequence in Different Experiments “LSW, LSS, and HSW respectively stand for low-salinity water, low-salinity surfactant, and high-salinity water. Compositions of the brines are given in Table 4. LSS solutions were prepared by dissolving 0.5 wt % active $3 in the LSW brines.
Table S. Injection Sequence in Different Experiments “LSW, LSS, and HSW respectively stand for low-salinity water, low-salinity surfactant, and high-salinity water. Compositions of the brines are given in Table 4. LSS solutions were prepared by dissolving 0.5 wt % active $3 in the LSW brines.
Table 6. Contact Angle Tests; Surfactant Solutions (LSS) Were Prepared by Dissolving 0.1 wt % Active S3 in LSW Brines
Table 6. Contact Angle Tests; Surfactant Solutions (LSS) Were Prepared by Dissolving 0.1 wt % Active S3 in LSW Brines
Figure 4. Recoveries of tertiary LSS (injection 2) in the five flooding experiments based on original oil in place (%OOIP) (above) and residual oil volume after LSW (below) versus the ratio of divalent to monovalent cations. Figure 5. Oil recovery (solid line) and pressure drop (dashed line) in experiments 1 and 2. The aging duration was 4 weeks.
Figure 4. Recoveries of tertiary LSS (injection 2) in the five flooding experiments based on original oil in place (%OOIP) (above) and residual oil volume after LSW (below) versus the ratio of divalent to monovalent cations. Figure 5. Oil recovery (solid line) and pressure drop (dashed line) in experiments 1 and 2. The aging duration was 4 weeks.
*M?*/Mt? is the molar ratio of divalent to monovalent cations in injection brine.
*M?*/Mt? is the molar ratio of divalent to monovalent cations in injection brine.
Figure 7. Final (equilibrium) values of surfactant adsorption vs Ca”*/ Na‘* ratio in three packed bed experiments at 60 °C. Figure 8. Water relative permeabilities at the end of low and high flow rates of low-salinity water (LSW). The calculated points are shown by dots around water saturation of 0.6. The core samples were aged for 4 weeks prior to flooding in tests 1 and 2 and for 7 weeks in tests 3—S.
Figure 7. Final (equilibrium) values of surfactant adsorption vs Ca”*/ Na‘* ratio in three packed bed experiments at 60 °C. Figure 8. Water relative permeabilities at the end of low and high flow rates of low-salinity water (LSW). The calculated points are shown by dots around water saturation of 0.6. The core samples were aged for 4 weeks prior to flooding in tests 1 and 2 and for 7 weeks in tests 3—S.
Figure 6. IFT between the crude oil and surfactant $3 solutions at different salinities and Ca?*/Na* ratios at 60 °C."” test aging duration M?*/M*[(mol/L)/(mol/L)] injection 1 (LSW) injection 2 (LSS) injection 3 (*LSS2 or *HSW) ultimate recove: injection 2 (LSS ging y y y Ty )
Figure 6. IFT between the crude oil and surfactant $3 solutions at different salinities and Ca?*/Na* ratios at 60 °C."” test aging duration M?*/M*[(mol/L)/(mol/L)] injection 1 (LSW) injection 2 (LSS) injection 3 (*LSS2 or *HSW) ultimate recove: injection 2 (LSS ging y y y Ty )
‘able 7. Oil Recoveries of Different Injections Are Based on Original Oil in Place (%OOIP) (Except the Last Column, Where the SS Recoveries Are Presented Based on Residual Oil after LSW Flooding)*
‘able 7. Oil Recoveries of Different Injections Are Based on Original Oil in Place (%OOIP) (Except the Last Column, Where the SS Recoveries Are Presented Based on Residual Oil after LSW Flooding)*
Figure 10. Contact angles; crystals 1 and 2 were aged for 2 days and crystals 3—S were aged for 15 days. Figure 11. Oil recovery (solid line) and pressure drop (dashed line) in experiments 3, 4, and S. The aging duration was 7 weeks.
Figure 10. Contact angles; crystals 1 and 2 were aged for 2 days and crystals 3—S were aged for 15 days. Figure 11. Oil recovery (solid line) and pressure drop (dashed line) in experiments 3, 4, and S. The aging duration was 7 weeks.
Figure 9. Water relative permeabilities at the end of low-salinity water (LSW) and low-salinity surfactant (LSS). The calculated points are shown by dots. The core samples were aged for 4 weeks prior to flooding in tests 1 and 2 and for 7 weeks in tests 3—S.
Figure 9. Water relative permeabilities at the end of low-salinity water (LSW) and low-salinity surfactant (LSS). The calculated points are shown by dots. The core samples were aged for 4 weeks prior to flooding in tests 1 and 2 and for 7 weeks in tests 3—S.
Figure 12. Phase behavior and IFT values of crude oil with surfactant $3 (0.1 wt % active material) at different salinities in 60 °C. Samples at 0.205 and 0.240 mol/L had the lowest IFT.'” 0.556 mol/L after switching to HSW injection. The IFT was <0.001 mN/m in the salinity interval of 0.205—0.240 mol/L, as shown in Figures 6 and 12, and the aqueous phase could
Figure 12. Phase behavior and IFT values of crude oil with surfactant $3 (0.1 wt % active material) at different salinities in 60 °C. Samples at 0.205 and 0.240 mol/L had the lowest IFT.'” 0.556 mol/L after switching to HSW injection. The IFT was <0.001 mN/m in the salinity interval of 0.205—0.240 mol/L, as shown in Figures 6 and 12, and the aqueous phase could
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