## 3 Experimental Procedure
### Phase Behavior Test  
The phase behavior test was divided into an aqueous stability test and a salinity scan. The former used an alkali, surfactant mixture, and polymer solution without crude oil, while the latter included crude oil. Synthetic brines (deionized water containing NaCl), ASP (alkaline surfactant polymer mixture with nonionic surfactant or heavy alcohol for the aqueous stability test), and AS (alkaline surfactant mixture with nonionic surfactant or heavy alcohol for the salinity scan) solutions were prepared in advance. Since the prepared synthetic brine was highly concentrated, it was first introduced into a 5 mL DIFFICO borosilicate pipette (Witeg Diffico, Wertheim, Germany), followed by deionized water to reach the desired salinity, and the ASP solution was added afterwards. We used a pipette from Pipetman (Gilson, USA), to ensure an accurate volume of the solution. The top end of the pipette was secured with silicone (Shin-Etsu, Japan). The aqueous solution mixture in the pipette was mixed by inverting and reverting the pipettes several times. It was placed in an oven to be visually inspected for any precipitation or phase separation at the reservoir temperature (60 \({}^{\circ}\)C) and atmospheric pressure for seven days of equilibrium time.  
The salinity scan test identified potential surfactants compatible with crude oil. The criteria included a high oil solubilization ratio in general and a low optimum salinity in the current reservoir condition. The solubilization ratio of oil or water was determined using Equation (1):  
\[\sigma_{i}=\frac{V_{i}}{V_{s}}, \tag{1}\]  
\begin{table}
\begin{tabular}{c c c} \hline \hline
**Reservoir Fluid** & **Property** & **Value or Amount** \\ \hline Formation water (brine) & Magnesium & 0.12 wt\% \\  & Barium & 0.005 wt\% \\  & Chloride & 0.31 wt\% \\  & Sodium & 0.04 wt\% \\  & Sulfate & 0.01 wt\% \\  & Calcium & 0.0020 wt\% \\  & Bicarbonate & 0.16 wt\% \\ Crude oil & API gravity (\({}^{\circ}\)API) \({}^{1}\) & 42.8 \\  & Viscosity (cp) & 0.85 at 25 \({}^{\circ}\)C and 1 atm \\ \hline \hline \end{tabular} \({}^{1}\) American Petroleum Institute gravity.  
\end{table}
Table 3: Properties of the reservoir fluids.  
In Equation (1), \(\sigma_{i}\) (mL/mL) is the solubilization ratio of \(i\) liquid phase, i.e., '\(o\)' for oil and '\(w\)' for water. \(V_{i}\) (mL) represents the volume of oil or water solubilized in the microemulsion at equilibrium state, and \(V_{s}\) (mL) is the volume of the surfactant obtained from the multiplication of aqueous volume and surfactant concentration [36]. The interfacial tension at the optimum salinity can be estimated using Equation (2):  
\[\gamma=\frac{0.3}{\left(\sigma^{*}\right)^{2}} \tag{2}\]  
where \(\gamma\) (mN/m) denotes the interfacial tension and \(\sigma^{*}\) (mL/mL) is the solubilization ratio at the optimum salinity [37]. The same pipette as in the aqueous stability test was used to ease the observation of the formed microemulsion [20]. The order of different solution placements into the pipettes were as follows: synthetic brine, AS solution, and crude oil. The volume ratio between the aqueous phase and oleic phase was 50:50. The fluid level was recorded, and the crude oil was then added to the pipette. The top opening of the pipette was sealed using silicone. The pipettes were shaken a few times, placed in the oven at 60 \({}^{\circ}\)C, and allowed to equilibrate within seven days.