## 4 Results and Discussion
### Coreflooding Test  
Table 5 summarizes the design of the ASP coreflooding tests. The proposed mixture used 1.1 wt% NaCl, while the comparison implemented 1.7 wt% NaCl as the salinity of the ASP slug, as the results of the phase behavior tests. The other elements of the ASP flooding, such as the preflush and polymer drive, were set to a salinity that was the same as the formation salinity to demonstrate field applicability. The microemulsion types would be the Winsor types I-III-I estimated by the phase behavior tests (Figure 4). Figure 5 depicted the pressure drop during the coreflooding tests. The test group showed less of a pressure drop than the reference case, so the nonionic surfactant helped to have less restricted flow and a reduction in pore plugging. Figure 6 compared the oil cut and the cumulative oil recovery after pre-flush. The cumulative oil recovery of the nonionic surfactant addition was about 74% of the residual oil after waterflooding, while that of the comparison remained at 51%. The oil cut of the proposed mixture showed a late-time recovery while that of the comparison case showed one highest peak and then a sharp decrease. The trajectories in the proposed mixture confirmed the effectiveness of the polymer drive. Figure 7 depicted CAOR to examine the efficiency of the ASP flooding. The CAOR of the nonionic surfactant addition was much higher than that of the heavy alcohol, and, thereby, the nonionic surfactant helped to recover the residual oil with better efficiency (Figure 7). Figure 6: Oilcut and cumulative oil recovery after pre-flush: (**a**) the reference case (heavy alcohol); (**b**) the proposed case (the nonionic surfactant) mixing with 0.25 wt% 1:4 (wt/wt) of LAS and DOSS anionic surfactant pair, 0.2 wt% Na\({}_{2}\)CO\({}_{3}\) as the alkali, and 0.15 wt% HPAM as the polymer. Figure 8 depicts the salinities and the regions of the type III microemulsion. The mixing effect with the formation salinity and the ASP slug increased the salinity at an early time and then eventually decreased when the polymer drive with a lower salinity arrives, following the desired transition. A steep inclination in the cumulative oil recovery profile intersected the type III region. The nonionic surfactant lasted in the type III region more than the reference case, as indicated with the type III effluent salinity, with the nonionic surfactant addition showing the larger PV of 0.85 (from 0.75 PV to 1.6 PV). The cumulative residual oil recovery when type III occurred at the proposed mixture was 61%, whereas 30% occurred for the reference case. Figure 8: Plot of the effluent salinity and cumulative oil recovery versus pore volumes to investigate the importance of the type III occurrence. ‘ME’ stands for microemulsion. Figure 7: Comparison of cumulative ASP oil ratio (CAOR) to evaluate the efficiency of ASP flooding. The oil recovery would be optimized when the type III region of the ASP formula approached the formation water closely, i.e., 0.8 to 1.5 wt% (Figure 8). As the salinity reached the type III and flowed through the core sample, the type III microemulsion was formed. This microemulsion type solubilized oil and water equally, and hence an ultralow interfacial tension was attained. It was apparent from the experimental results that the introduction of a nonionic surfactant effectively improved the performance of the anionic surfactant pair in a low salinity condition by modifying the hydrophobicity to obtain a lower optimum salinity. These findings provide an insight into the surfactant screening and formulation processes for ASP flooding where assigning a nonionic surfactant with a PO group into an anionic surfactant pair might work well in sandstone oil reservoirs with low salinity formation water and light oil. It was expected to reduce the trial and error time during the surfactant screening stage for cases similar to the reservoir characteristics in this work.